The information in this prospectus supplement is not complete and may be changed. This prospectus supplement is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

Filed Pursuant to Rule 424(b)(5)

Registration No. 333-130597

Subject to completion, dated March 3, 2006

Preliminary prospectus supplement

(to prospectus dated March 2, 2006)

Quicksilver Resources Inc.

$300,000,000

                % Senior Subordinated Notes due 2016

Interest payable                             and                             

Issue price:               %

The notes will mature on                     , 2016. Interest will accrue from                     , 2006, and the first interest payment will be due on                     , 2006.

We may redeem the notes, in whole or in part, on and after                     , 2011 at the redemption prices described herein. Prior to                     , 2011 we may redeem the notes, in whole but not in part, at a redemption price equal to 100% of the principal amount thereof plus a “make whole” premium as described herein. Prior to                     , 2009 we may redeem up to 35% of the notes using proceeds of certain equity offerings. If we sell certain of our assets or experience specific kinds of changes in control, we must offer to purchase the notes.

The notes will be our senior subordinated obligations. The notes will be unsecured and will be subordinated to all our existing and future senior debt and rank senior to all our existing and future subordinated debt. Our obligations under the notes will be guaranteed on a senior subordinated basis by some of our current and future domestic subsidiaries.

Investing in the notes involves risks. See “Risk factors” beginning on page S-11.

			Underwriting		Proceeds to
			discounts and		Quicksilver
	Price to public(1)		commissions		Resources Inc.
Per note		%		%		%
Total	$		$		$

(1) Plus accrued interest, if any, from                , 2006

The notes will not be listed on any securities exchange. Currently, there is no public market for the notes.

Delivery of the notes, in book-entry form, will be made on or about                     , 2006 through The Depository Trust Company.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities, or determined if this prospectus supplement or the prospectus to which it relates are truthful or complete. Any representation to the contrary is a criminal offense.

Joint book-running managers

JPMorgan Credit Suisse

Co-managers

Banc of America Securities LLC

BNP PARIBAS

Goldman, Sachs & Co.

                      , 2006

Table of contents

	Page
Prospectus supplement
Prospectus summary	S-1
The offering	S-4
Summary historical financial data	S-6
Summary reserve, production and operating data	S-8
Risk factors	S-11
Use of proceeds	S-24
Capitalization	S-25
Selected historical consolidated financial information	S-26
Management’s discussion and analysis of financial condition and results of operations	S-27
Business	S-52
Management	S-61
Security ownership of management and certain beneficial holders	S-64
Certain relationships and related transactions	S-66
Description of other indebtedness	S-67
Description of the notes	S-68
Certain U.S. federal income tax considerations	S-127
Underwriting	S-131
Legal matters	S-133
Experts	S-133
Reserve engineers	S-133
Glossary of certain oil and natural gas terms	S-134
Consolidated financial statements	F-1
Prospectus
About this prospectus	2
Where you can find more information	2
Incorporation by reference	2
Forward-looking statements	3
Description of debt securities	3
Description of capital stock	11
Description of depositary shares	15
Description of warrants	15
Description of purchase contracts	16
Description of units	16
Ratio of earnings to fixed charges	17
Use of proceeds	17
Certain legal matters	17
Experts	17
Reserve engineers	17

i

About this prospectus supplement

This document is in two parts. The first part is this prospectus supplement, which describes the specific terms of the           % Senior Subordinated Notes due 2016 we are offering and certain other matters. The second part, the base prospectus dated March 2, 2006, provides more general information about the various securities that we may offer from time to time, some of which information may not apply to the notes we are offering hereby. Generally when we refer to this prospectus, we are referring to both this prospectus supplement and the base prospectus combined. If any of the information in this prospectus supplement is inconsistent with any of the information in the base prospectus, you should rely on the information in this prospectus supplement.

You should rely only on the information contained in the prospectus or to which the prospectus refers or that is contained in any free writing prospectus relating to the notes. We have not, and the underwriters have not, authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not making an offer of the notes in any jurisdiction where their offer or sale is not permitted. The information in this prospectus supplement and the base prospectus may only be accurate as of the respective date of each document. Our business, financial condition, results of operations and prospects may have changed since those dates.

ii

Prospectus summary

This summary highlights selected information contained elsewhere in this prospectus and in the documents we incorporate by reference. This summary is not complete and does not contain all of the information that you should consider before deciding whether or not to invest in the notes. For a more complete understanding of our company and this offering, we encourage you to read this entire document, including “Risk factors,” the financial and other information incorporated by reference in this prospectus and the other documents to which we have referred. Unless otherwise indicated or required by the context, as used in this prospectus, the terms “we,” “our” and “us” refer to Quicksilver Resources Inc. and all of its subsidiaries that are consolidated under accounting principles generally accepted in the United States (“GAAP”). Some of the oil and gas terms we use are defined under “Glossary of oil and gas terms.” Our fiscal year ends on December 31 of each year.

Our company

We are a Fort Worth, Texas-based independent oil and gas company. We are 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 found in fractured shales, coal seams and tight sands. 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. For the year ended December 31, 2005, we generated revenues, EBITDA and net income of $310 million, $205 million and $87 million, respectively.

For the year ended December 31, 2005, we had average daily production of 140.9 MMcfe per day, which implies a reserve life (proved reserves divided by 2005 annual production) of approximately 21.7 years. The following table presents our December 31, 2005 reserves and our average daily production for the year ended December 31, 2005.

	Proved reserves as of						Average daily
	December 31, 2005						production
							Year ended
	Total		% natural		% proved		December 31, 2005
Areas of operations	Bcfe		gas		developed		(Mcfed)
Michigan		581.5		95%		90%		80,656
Alberta, Canada		304.9		100%		66%		40,672
Texas		183.1		74%		48%		10,463
Other		44.7		66%		91%		9,104
Total		1,114.2		92%		77%		140,895

Since going public in 1999, we have grown our reserves and production at a compound annual growth rate of 23% and 15%, respectively. We have achieved an annual reserve replacement ratio of 299%, 345% and 384% in 2003, 2004 and 2005, respectively, virtually all of which was achieved organically, with an all in three-year average finding and development cost of $1.12 per Mcfe. 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

S-1

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 the acquisition of additional leasehold interests.

We operate in Canada through our subsidiary MGV Energy Inc. At December 31, 2005, it comprised 27% of our reserves, 29% of our annual production, and $46 million, or 32%, of our cash flow from operations.

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 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 provides 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 in the Fort Worth Basin. Our growth was achieved with an all in three-year average finding and development cost of $1.12 per Mcfe ($1.24 per Mcfe in 2005), which we believe compares favorably to the industry. 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 Exploration Company, which made significant contributions of properties to us at the time of our incorporation. Since then, they have

S-2

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 continue 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 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. In addition, 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.

Our principal executive offices are located at 777 West Rosedale Street, Suite 300, Fort Worth, Texas 76104. Our telephone number is (817) 665-5000. We maintain a website at www.qrinc.com; however, the information on our website is not part of this prospectus, and you should rely only on the information contained in this prospectus and in the documents we incorporate by reference when making a decision as to whether to invest in the notes.

S-3

The offering

The following summary contains basic information about the notes and is not intended to be complete. For a more complete understanding of the notes, please refer to the section entitled “Description of the notes” in this prospectus supplement.

Issuer	Quicksilver Resources Inc.
Securities offered	$300,000,000 aggregate principal amount of           % Senior Subordinated Notes due 2016.
Maturity	, 2016.
Interest payment dates	and                     , commencing                     , 2006
Optional redemption	The notes will be redeemable at our option, in whole or in part, at any time on and after                     , 2011 at the redemption prices described in this prospectus supplement, together with accrued and unpaid interest, if any, to the date of redemption.
	At any time prior to                     , 2009, we may redeem up to 35% of the original principal amount of the notes with the proceeds of certain equity offerings of our shares of common stock at a redemption price of           % of the principal amount of the notes, together with accrued and unpaid interest, if any, to the date of redemption.
	Additionally, at any time prior to                     , 2011, we may redeem the notes, in whole but not in part, at a price equal to 100% of the principal amount of the notes plus a “make-whole” premium.
Change of control	If a change of control occurs, subject to certain conditions, we must give holders of the notes an opportunity to sell us the notes at a purchase price of 101% of the principal amount of the notes, plus accrued and unpaid interest to the date of the purchase. See “Description of the notes— Change of control.”
Guarantees	The payment of the principal, premium and interest on the notes will be fully and unconditionally guaranteed on a senior subordinated basis by some of our current and future domestic subsidiaries. The subsidiary guarantees will be subordinated to all existing and future senior indebtedness of our subsidiary guarantors, including their guarantees of our obligations under our senior secured revolving credit facilities. See “Description of the notes— Subsidiary guarantees.”
Ranking	The notes will be our unsecured senior subordinated obligations. The notes and the subsidiary guarantees will rank:
	• junior in right of payment to all of our and the subsidiary guarantors’ existing and future senior indebtedness and guarantor senior indebtedness including the senior secured revolving credit facilities;

S-4

	• equally in right of payment with any of our and the subsidiary guarantors’ existing and future senior subordinated indebtedness and guarantor senior subordinated indebtedness; and
	• senior in right of payment to any of our and the subsidiary guarantors’ existing and future subordinated obligations.
	As of December 31, 2005, after giving pro forma effect to this offering and the application of the net proceeds from this offering the notes would have ranked junior to approximately $240 million of senior indebtedness, all of which would have been secured. See “Description of the notes— Ranking and subordination.”
Covenants	We will issue the notes under an indenture with JPMorgan Chase Bank, National Association, as trustee. The indenture will, among other things, limit our ability and the ability of our restricted subsidiaries to:
	• incur additional debt;
	• pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated debt;
	• make investments;
	• create liens on our assets;
	• create restrictions on the ability of our restricted subsidiaries to pay dividends or make other payments to us;
	• engage in transactions with our affiliates;
	• transfer or sell assets; and
	• consolidate, merge or transfer all or substantially all of our assets and the assets of our subsidiaries.
	These covenants are subject to important exceptions and qualifications, which are described under the caption “Description of the notes— Certain covenants.”
Use of proceeds	We intend to use approximately $265 million of the net proceeds from this offering to repay our second lien mortgage notes and/or to repay current borrowings under our senior secured revolving credit facilities. We intend to use the remainder of the proceeds for general corporate purposes. See “Use of proceeds.”

Risk factors

Investing in the notes involves substantial risk. You should carefully consider the risk factors set forth under “Risk factors” and the other information contained in this prospectus supplement prior to making an investment in the notes. See “Risk factors” beginning on page S-11.

S-5

Summary historical financial data

The following table shows our summary consolidated historical financial data as of and for the periods indicated. Our summary historical financial data as of and for the fiscal years ended December 31, 2003, 2004 and 2005 have been derived from our audited financial statements. Certain historical amounts have been reclassified to conform to the current presentation.

You should read the summary consolidated historical financial data below in conjunction with our consolidated financial statements and the accompanying notes which are contained elsewhere in this prospectus. You should also read the sections entitled “Selected historical consolidated financial information” and “Management’s discussion and analysis of financial condition and results of operations.”

				Years ended December 31,
($ in thousands unless otherwise indicated)				2003			2004			2005
Statement of operations data:
	Revenues:
		Oil, gas and NGL sales		$	139,037		$	177,173		$	306,204
		Other revenue			1,912			2,556			4,244
			Total revenues		140,949			179,729			310,448
	Expenses:
		Oil and gas production costs			52,524			65,626			86,272
		Other operating costs			971			810			1,661
		Depletion, depreciation and amortization			32,067			40,691			55,213
		Provision for doubtful accounts			87			153			108
		General and administrative			8,133			12,934			18,979
			Total expenses		93,782			120,214			162,233
		Income from equity affiliates			1,331			1,178			914
		Operating income			48,498			60,693			149,129
	Other income/expense:
	Other income—net				(186	)		(415	)		(585	)
	Interest expense				20,182			15,662			21,740
	Income before income taxes				28,502			45,446			127,974
	Income tax expense				9,997			14,174			40,702
	Income from continuing operations				18,505			31,272			87,272
	Discontinued operations(1)				—			—			162
	Income before cumulative effect of change in accounting principle				18,505			31,272			87,434
	Cumulative effect of change in accounting principle, net of tax(2)				2,297			—			—
	Net income			$	16,208		$	31,272		$	87,434

S-6

		Years ended December 31,
($ in thousands unless otherwise indicated)		2003			2004			2005
Balance sheet (as of period end):
Working capital (deficit)(3)		$	(30,803	)	$	(17,255	)	$	(98,606	)
Property, plant and equipment—net			604,576			802,610			1,112,002
Total assets			666,934			888,334			1,243,094
Long-term debt			249,097			399,134			506,039
Stockholders’ equity			241,816			304,276			383,615
Cash flow data:
Net cash flow provided by (used in):
	Operating activities	$	49,602		$	84,847		$	144,468
	Investing activities		(137,744	)		(205,898	)		(319,269	)
	Financing activities		79,369			134,389			172,426
Other financial data:
EBITDA(4)		$	78,454		$	101,799		$	205,089
EBITDA/interest expense(5)			3.9x			6.5x			9.4x
Ratio of earnings to fixed charges(6)			2.4x			3.8x			6.8x

(1) Represents gain from sale of drilling operations net of income tax of $86.

(2) Represents the cumulative effect of the adoption of SFAS No. 143, Asset Retirement Obligations, net of deferred income tax benefits of, $1,217.

(3) Working capital (deficit) is calculated by subtracting current liabilities from current assets and includes current portion of assets and liabilities, which reflect the estimated fair value of derivative obligations.

(4) EBITDA represents net earnings before income taxes, interest expense, depreciation, depletion and amortization. EBITDA is not a measure calculated in accordance with generally accepted accounting principles (GAAP). EBITDA should not be considered as an alternative to net income, income before taxes, net cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP. We believe that EBITDA is a widely accepted financial indicator of a company’s ability to incur and service debt and to fund capital expenditures. Because EBITDA is commonly used in the oil and gas industry, we believe it is useful in evaluating our ability to meet our interest obligations in connection with this offering. EBITDA calculations may vary among entities, so our computation of EBITDA may not be comparable to EBITDA or similar measures of other entities. In evaluating EBITDA, we believe that investors should consider, among other things, the amount by which EBITDA exceeds interest costs, how EBITDA compares to principal payments on debt and how EBITDA compares to capital expenditures for each period. EBITDA is reconciled to net income as shown in the table below.

The following table provides a reconciliation of net income to EBITDA:

	Years ended December 31,
($ in thousands)	2003		2004		2005
Net income	$	16,208	$	31,272	$	87,434
Adjustments:
Depletion, depreciation and amortization		32,067		40,691		55,213
Interest expense		20,182		15,662		21,740
Income tax expense		9,997		14,174		40,702
EBITDA	$	78,454	$	101,799	$	205,089

(5) Represents EBITDA divided by interest expense. The ratio of net income to interest expense for the years ended December 31, 2003, 2004 and 2005 were 0.8x, 2.0x, and 4.0x, respectively.

(6) For purposes of calculating the ratio of earnings to fixed charges, “earnings” represents income from continuing operations before income taxes before income from equity investees plus distributed earnings from equity investees and fixed charges. “Fixed charges” consist of interest expense, including amortization of debt issuance costs and that portion of rental expense considered to be a reasonable approximation of interest.

S-7

Summary reserve, production and operating data

The following table sets forth summary data with respect to estimated proved reserves, costs incurred, reserve replacement ratios and finding and development costs on a historical basis as of and for the periods presented. Our 2003, 2004, and 2005 estimates of our proved reserves in the United States are based on reserve reports prepared by Schlumberger Data and Consulting Services. Our 2003 estimates of our proved reserves in Canada are based on reserve reports prepared by Netherland, Sewell & Associates, Inc. and our 2004 and 2005 estimates of our proved reserves in Canada are based on reserve reports prepared by LaRoche Petroleum Consultants, Ltd.

			As of December 31,
			2003		2004		2005
Proved reserves:
	Natural gas (MMcf)			790,152		888,753		1,020,953
	Crude oil (MBbl)			13,173		9,067		5,915
	NGL (MBbl)			1,918		4,187		9,623
		Total (MMcfe)		880,696		968,276		1,114,181
	% natural gas			90%		92%		92%
	% proved developed			81%		77%		77%
	Reserve life (years)(1)			21.9		21.9		21.7
Costs incurred (in thousands):
	Proved acreage acquisition costs		$	6,603	$	14,849	$	2,441
	Unproved acreage acquisition costs			30,802		39,001		52,203
	Development costs			79,502		116,307		106,395
	Exploration costs			26,477		48,304		118,977
		Total	$	143,384	$	218,461	$	280,016
Annual reserve replacement ratio(2)				299%		345%		384%
Three-year average F&D cost per Mcfe(3)			$	0.81	$	0.79	$	1.09
All in three-year average F&D cost per Mcfe(3)			$	0.77	$	0.78	$	1.12

(1) Calculated by dividing year-end reserves by annual production rates. This methodology implies that reserves are produced ratably over the reserve life indicated. Actual production rates for new wells tend initially to increase to peak production and thereafter to decline at an initially accelerated rate before moderating to decrease much more gradually over the majority of the well’s productive life.

(2) The reserve replacement ratio is calculated by dividing the sum of reserve additions from all sources (revisions, purchases, extensions and discoveries) for a period by the actual production for the period. Additions to our reserves are proved developed and proved undeveloped reserves. We expect to continue to add to our total proved reserves through these activities, but various factors could impede our ability to do so. See “Risk factors.” The reserve additions and production values used in the calculation of our reserve replacement ratio are derived directly from the proved reserve table presented in note 22 to our consolidated financial statements included elsewhere in this prospectus supplement.

We use the reserve replacement ratio as an indicator of our ability to replenish annual production volumes and grow reserves. We believe that reserve replacement is relevant and useful information that is commonly used by analysts, investors and other interested parties in the oil and gas industry as a means of evaluating the operational performance and prospects of entities engaged in the production and sale of depleting natural resources. It should be noted that the reserve replacement ratio is a statistical indicator that has limitations. As an annual measure, the ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not consider the cost or timing of future production of new reserves, it cannot be used as a measure of value creation. The ratio does not distinguish between changes in reserve quantities that are developed and those that will require additional time and funding to develop. The percentage of our reserves that were developed was 81%, 77% and 77% for the years ended December 31, 2003, 2004 and 2005, respectively.

(3) Finding and development cost, or F&D cost, is calculated by dividing (x) development, exploitation, exploration and acquisition capital expenditures for the period, plus unevaluated capital expenditures as of the beginning of the period, less unevaluated capital expenditures as of the end of the period, by (y) reserve additions for the period. The following tables set

S-8

forth reconciliations of our F&D cost for each of the thirty-six month periods ended December 31, 2003, 2004 and 2005 to the information required by paragraphs 11 and 21 of Statement of Financial Accounting Standard No. 69. Our calculation of “all in average F&D cost” includes costs and reserve additions related to the purchase of proved reserves. Our calculation of “average F&D cost” does not include the costs and reserves related to the purchase of proved reserves. The methods we use to calculate our F&D cost may differ significantly from methods used by other companies to compute similar measures. As a result, our F&D cost may not be comparable to similar measures provided by other companies.

We believe that providing a measure of F&D cost is useful in evaluating the cost, on a per thousand cubic feet of natural gas equivalent basis, to add proved reserves. However, this measure is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in Quicksilver’s financial statements prepared in accordance with GAAP (including the notes thereto) included elsewhere in this prospectus. Due to various factors, including timing differences in the addition of proved reserves and the related costs to develop those reserves, F&D costs do not necessarily reflect precisely the costs associated with particular reserves. For example, exploration costs may be recorded in periods prior to the periods in which related increases in reserves are recorded, and development costs may be recorded in periods subsequent to the periods in which related increases in reserves are recorded. In addition, changes in commodity prices can affect the magnitude of recorded increases in reserves independent of the related costs of such increases. As a result of the foregoing factors and various factors that could materially affect the timing and amounts of future increases in reserves and the timing and amounts of future costs, including factors disclosed in “Risk factors,” we cannot assure you that our future F&D costs will not differ materially from those set forth above.

			Thirty-six months ended December 31,
($ in thousands, unless otherwise indicated)			2003			2004			2005
Three-year average F&D cost:
	Unproved acreage acquisition costs		$	39,566		$	75,775		$	122,006
	Development costs			164,623			230,925			302,204
	Exploration costs			51,164			89,365			193,758
		Total exploration, development and acquisition capital expenditures		255,353			396,065			617,968
	Adjustments:
		Unevaluated costs at beginning of period		8,239			14,458			16,913
		Unevaluated costs at end of period		(49,918	)		(97,168	)		(132,090	)
	Adjusted capital expenditures related to reserve additions		$	213,674		$	313,355		$	502,791
	Reserve extensions, discoveries and revisions (MMcfe)			263,972			398,293			460,221
	F&D cost per Mcfe		$	0.81		$	0.79		$	1.09
All in three-year average F&D cost:
	Proved acreage acquisition costs		$	41,956		$	53,651		$	23,893
	Unproved acreage acquisition costs			39,566			75,775			122,006
	Development costs			164,623			230,925			302,204
	Exploration costs			51,164			89,365			193,758
		Total exploration, development and acquisition capital expenditures		297,309			449,716			641,861
	Adjustments:
		Unevaluated costs at beginning of period		8,239			14,458			16,913
		Unevaluated costs at end of period		(49,918	)		(97,168	)		(132,090	)
	Adjusted capital expenditures related to reserve additions		$	255,630		$	367,006		$	526,684
	Reserve extensions, discoveries and revisions (MMcfe)			331,510			472,381			470,131
	F&D cost per Mcfe		$	0.77		$	0.78		$	1.12

S-9

Our all in F&D cost for the twelve months ended December 31, 2005 was $1.24 per Mcfe. The following table sets forth a reconciliation of our all in F&D cost for the twelve months ended December 31, 2005 to the information required by paragraphs 11 and 21 of Statement of Financial Accounting Standards No. 69.

($ in thousands, unless otherwise indicated)			Twelve months ended December 31, 2005
All in 2005 F&D cost:
	Proved acreage acquisition costs		$	2,441
	Unproved acreage acquisition costs			52,203
	Development costs			106,395
	Exploration costs			118,977
		Total exploration, development and acquisition capital expenditures		280,016
	Adjustments:
		Unevaluated cost at beginning of period		97,168
		Unevaluated cost at end of period		(132,090	)
	Adjusted capital expenditures related to reserve additions		$	245,094
	Reserve extensions, discoveries and revisions (MMcfe)			197,396
	F&D cost per Mcfe		$	1.24

The following table sets forth summary data with respect to production and other operating data on a historical basis for the periods presented:

			As of December 31,
			2003		2004		2005
Production data:
	Natural gas (MMcf)			34,536		39,351		46,769
	Crude oil (MBbl)			808		689		553
	NGL (MBbl)			135		129		223
		Total production (MMcfe)		40,192		44,257		51,427
Product sale revenues (in thousands):
	Natural gas sales		$	116,563	$	150,716	$	269,547
	Crude oil sales			19,576		22,782		27,947
	NGL sales			2,898		3,675		8,710
		Total gas, oil and NGL sales	$	139,037	$	177,173	$	306,204
Effective unit prices—including impact of hedges:
	Natural gas (per Mcf)		$	3.38	$	3.83	$	5.76
	Crude oil (per Bbl)		$	24.23	$	33.07	$	50.50
	NGL (per Bbl)		$	21.50	$	28.52	$	39.08
Production expenses (per Mcfe)(1):			$	1.31	$	1.48	$	1.68
General and administrative expenses (per Mcfe):			$	0.20	$	0.29	$	0.37

(1) Includes production taxes.

S-10

Risk factors

You should carefully consider the risks described below before making an investment decision. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also impair our business operations. If any of the following risks actually occurs, our business, financial condition or results of operations could be materially adversely affected.

This prospectus supplement, the base prospectus and the documents we incorporate by reference also contain forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in the forward-looking statements as a result of a number of factors, including the risks described below and elsewhere in this prospectus.

Risks related to our business

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 revolving credit facilities is subject to periodic redetermination based in part on changing expectations of future prices. Lower prices may also reduce the amount of natural gas and crude oil that we can economically produce.

While prices for natural gas and crude oil may be favorable at any point in time, they fluctuate widely. For example, the closing New York Mercantile Exchange (“NYMEX”) wholesale price of natural gas was at a six-year low of approximately $1.83 per Mcf for October of 2001, reached an all time high of approximately $13.91 per Mcf for October of 2005 and subsequently declined to $8.40 per Mcf for February of 2006. Among the factors that can cause these fluctuations are:

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

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

•  the price and availability of alternative fuels;

•  weather conditions;

•  domestic and foreign governmental regulations;

•  political conditions in oil and gas producing regions; and

•  worldwide economic conditions.

Due to the volatility of natural gas and crude oil prices and our inability to control the factors that affect natural gas and crude oil prices, we cannot predict whether prices will remain at current levels, increase or decrease in the future.

S-11

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 prospectus.

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 prospectus. In addition, we may adjust estimates of proved reserves to reflect our 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 prospectus 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 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.

S-12

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 “Management’s discussion and analysis of financial condition and results of operations.” 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.

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.

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 our wholly-owned subsidiary MGV Energy Inc. (“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

S-13

indicate that net recoverable reserves on coal bed methane (“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 at 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,” 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 practices. 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.

S-14

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 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.

At 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

S-15

and associated costs could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities. As a result, the success and timing of our drilling and development activities on properties operated by others depend upon a number of factors that are outside of our control, including:

•  timing and amount of capital expenditures;

•  the operator’s expertise and financial resources;

•  approval of other participants in drilling wells; and

•  selection of technology.

We cannot control the operations of gas processing and transportation facilities that 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 many 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 operate and develop 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.

S-16

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 for natural gas and crude oil. These hedging arrangements also expose us to risk of financial losses in some circumstances, including the following:

•  our production is materially less than expected; or

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

The result of natural gas and crude oil market prices exceeding our swap prices requires us to make payment for the settlement of our hedge derivatives on the fifth day of the production month for natural gas hedges and the fifth day after the production month for crude oil hedges. We do not receive market price cash payments from our customers until 25 to 60 days after the end of the production month. This could have a material adverse effect on our cash flows for the period between hedge settlement and payment for revenues earned.

If we choose not to engage in hedging arrangements in the future, we may be more adversely affected by changes in natural gas and crude oil prices than our competitors who engage in hedging arrangements.

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

Due to the recent record high oil and gas prices, there is currently a high demand 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.

S-17

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

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

•  discharge permits for drilling operations;

•  drilling permits and bonds;

•  reports concerning operations;

•  spacing of wells;

•  unitization and pooling of properties;

•  environmental protection; and

•  taxation.

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

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

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

Risks related to our indebtedness and the notes

We have a substantial amount of debt and the cost of servicing that debt could adversely affect our business and hinder our ability to make payments on the notes, 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 agreements governing our senior secured revolving credit facilities, 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 risks associated with the Canadian dollar. If we incur additional indebtedness or fail to increase the quantity of proved reserves attributable to

S-18

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 the notes, including, among others, operating expenses and interest and principal payments under our senior secured revolving credit facilities 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 the notes. For example, they could:

•  make it more difficult for us to satisfy our obligations with respect to the notes and our other debt;

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

•  require us to make principal payments under our senior secured revolving credit facilities if the quantity of proved reserves attributable to our natural gas and crude oil properties are insufficient to support our level of borrowings under such credit facilities;

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

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

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

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

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

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

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

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

If we are unable to service our indebtedness and fund our operating costs, we will be forced to adopt alternative strategies that may include:

•  reducing or delaying capital expenditures;

•  seeking additional debt financing or equity capital;

•  selling assets; or

S-19

•  restructuring or refinancing debt.

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

Our senior secured revolving credit facilities restrict and the indenture will 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 restrict and the indenture governing the notes will restrict our ability to, among other things:

•  incur additional debt;

•  pay dividends on or redeem or repurchase capital stock;

•  make certain investments;

•  incur or permit to exist certain liens;

•  enter into transactions with affiliates;

•  merge, consolidate or amalgamate with another company;

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

•  redeem subordinated debt.

The loan agreements for our senior secured revolving credit facilities contain certain covenants, which, among other things, restrict our ability to prepay the notes and require the maintenance of a minimum current ratio, a minimum collateral coverage ratio and a minimum earnings (before interest, taxes, depreciation, depletion and amortization, non-cash income and expense, and exploration costs) to interest expense 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.

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, the indenture or 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 principal of that debt, together with accrued interest, to be immediately due and payable. Moreover, any of our other 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 lenders 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 that 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.

S-20

Your right to receive payments on the notes is junior to our senior indebtedness and the senior indebtedness of our subsidiary guarantors.

The indebtedness evidenced by the notes and the guarantees will be senior subordinated obligations of Quicksilver and our subsidiary guarantors. The payment of the principal of, premium on, if any, and interest on the notes and the payment of the subsidiary guarantees are each subordinate in right of payment, as set forth in the indenture, to the prior payment in full of all senior indebtedness of Quicksilver or the senior indebtedness of our subsidiary guarantors, as the case may be, including the obligations of Quicksilver under, and the obligations of our subsidiary guarantors with respect to, our senior secured revolving credit facilities. Any future subsidiary guarantee will be similarly subordinated to senior indebtedness of such subsidiary guarantor.

As of December 31, 2005, after giving pro forma effect to this offering and the application of the net proceeds from this offering as described under ”Use of proceeds,” our senior indebtedness would have been approximately $240 million, which includes letters of credit and hedging obligations with parties to our senior secured revolving credit facilities, leaving us with $407 million of borrowing base capacity under our senior secured revolving credit facilities, which would be senior indebtedness if incurred. Although the indenture governing the notes contains limitations on the amount of additional indebtedness that we may incur, under certain circumstances the amount of such indebtedness could be substantial and, in any case, such indebtedness may be senior indebtedness. See “Description of the notes—Certain covenants— Limitation on indebtedness.”

Because the notes are unsecured and because of the subordination provisions of the notes, in the event of our bankruptcy, liquidation or dissolution or that of any subsidiary guarantor, our assets and the assets of the subsidiary guarantors would be available to pay obligations under the notes only after all payments had been made on our and the subsidiary guarantors’ senior indebtedness, including under our senior secured revolving credit facilities. We cannot assure you that sufficient assets will remain after all these payments have been made to make any payments on the notes, including payments of interest when due. Also, because of these subordination provisions, you may recover less ratably than our other creditors in a bankruptcy, liquidation or dissolution. In addition, all payments on the notes and the guarantees will be prohibited in the event of a payment default on senior indebtedness, including borrowings under our senior secured revolving credit facilities, and may be prohibited for up to 180 days in the event of non-payment defaults on certain of our senior indebtedness, including the senior secured revolving credit facilities. See “Description of the notes—Ranking and subordination.”

The notes are not secured by our assets nor the assets of our subsidiary guarantors.

The notes will be our general unsecured obligations and will be effectively subordinated in right of payment to all of our secured indebtedness to the extent of the value of the assets securing such indebtedness. If we become insolvent or are liquidated, our assets which serve as collateral under our secured indebtedness would be made available to satisfy our obligations under any secured debt before any payments are made on the notes. Our obligations under our senior secured revolving credit facilities are secured by substantially all of our producing oil and gas properties.

S-21

The notes will be structurally subordinated to all indebtedness and other liabilities of our existing and future subsidiaries that are not guarantors of the notes.

You will not have any claim as a creditor against MGV Energy, Inc., our Alberta, Canada subsidiary that is not a guarantor of the notes, or against any of our future subsidiaries that do not become guarantors of the notes. As of December 31, 2005, on a pro forma basis, our non-guarantor subsidiaries represented 31% of our total revenue and 23% of our total operating expense. Indebtedness and other liabilities, including trade payables, whether secured or unsecured, of those subsidiaries will be effectively senior to your claims against those subsidiaries.

In addition, the indenture governing the notes will, subject to some limitations, permit our existing or future non-guarantor subsidiaries to incur additional indebtedness and will not contain any limitation on the amount of other liabilities, such as trade payables, that these subsidiaries may incur.

If we undergo a change of control, we may not have the ability to raise the funds necessary to finance the change of control offer required by the indenture governing the notes, which would violate the terms of the notes.

Upon the occurrence of a change of control, holders of the notes will have the right to require us to purchase all or any part of such holders’ notes at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of purchase. The events that constitute a change of control under the indenture governing the notes would constitute a default under our senior secured revolving credit facilities, which prohibit the purchase of the notes by us in the event of certain change of control events, unless, and until, such time as our indebtedness under the senior secured revolving credit facilities is repaid in full. There can be no assurance that either we or our subsidiary guarantors would have sufficient financial resources available to satisfy all of our or their obligations under our senior secured revolving credit facilities and these notes in the event of a change in control. Our failure to purchase the notes as required under the indenture governing the notes would result in a default under the indenture and under our senior secured revolving credit facilities, each of which could have material adverse consequences for us and the holders of the notes. See “Description of the notes—Change of control.”

A subsidiary guarantee could be voided if it constitutes a fraudulent transfer under U.S. bankruptcy or similar state law, which would prevent the holders of the notes from relying on that subsidiary to satisfy claims.

Under U.S. bankruptcy law and comparable provisions of state fraudulent transfer laws, a guarantee can be voided, or claims under the guarantee may be subordinated to all other debts of that guarantor if, among other things, the guarantor, at the time it incurred the indebtedness evidenced by its guarantee or, in some states, when payments become due under the guarantee, received less than reasonably equivalent value or fair consideration for the incurrence of the guarantee and:

•  was insolvent or rendered insolvent by reason of such incurrence;

•  was engaged in a business or transaction for which the guarantor’s remaining assets constituted unreasonably small capital; or

•  intended to incur, or believed that it would incur, debts beyond its ability to pay those debts as they mature.

S-22

A guarantee may also be voided, without regard to the above factors, if a court found that the guarantor entered into the guarantee with the actual intent to hinder, delay or defraud its creditors. A court would likely find that a guarantor did not receive reasonably equivalent value or fair consideration for its guarantee if the guarantor did not substantially benefit directly or indirectly from the issuance of the notes. If a court were to void a guarantee, you would no longer have a claim against the guarantor. Sufficient funds to repay the notes may not be available from other sources, including the remaining guarantors, if any. In addition, the court might direct you to repay any amounts that you already received from the subsidiary guarantor.

The measures of insolvency for purposes of fraudulent transfer laws vary depending upon the governing law. Generally, a guarantor would be considered insolvent if:

•  the sum of its debts, including contingent liabilities, was greater than the fair saleable value of all its assets;

•  the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they became absolute and mature; or

•  it could not pay its debts as they became due.

Each subsidiary guarantee will contain a provision intended to limit the guarantor’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its subsidiary guarantee to be a fraudulent transfer. This provision may not be effective to protect the subsidiary guarantees from being voided under fraudulent transfer law.

You cannot be sure that an active trading market will develop for the notes.

The notes will constitute a new issue of securities for which there is no established trading market. We do not intend to list the notes on any national securities exchange or seek the admission of the notes for quotation through the National Association of Securities Dealers Automated Quotation System. We have been informed by the underwriters that they intend to make a market in the notes after this offering is completed. However, the underwriters are not obligated to do so and may cease their market-making activities at any time. In addition, the liquidity of the trading market in the notes, and the market price quoted for the notes, may be adversely affected by changes in the overall market for high yield securities and by changes in our financial performance or prospects or in the financial performance or prospects of companies in our industry generally. As a result, we cannot assure you that an active trading market will develop or be maintained for the notes. If an active market does not develop or is not maintained, the market price and liquidity of the notes may be adversely affected.

S-23

Use of proceeds

We estimate that the net proceeds from this offering will be approximately $292 million after deducting underwriting discounts and commissions and estimated expenses of the offering. We intend to use approximately $265 million to repay our second lien mortgage notes and/or to repay current borrowings under our senior secured revolving credit facilities. As of December 31, 2005, the interest rate with respect to our second lien mortgage notes was 7.5% on $40 million and 8.6% on $30 million and the effective interest rate with respect to our senior secured revolving credit facilities was 5.3%. Our second lien mortgage notes mature on December 31, 2006, and the indebtedness under our revolving credit facilities matures on July 28, 2009. We intend to use the remainder of the proceeds for general corporate purposes.

S-24

Capitalization

The following table sets forth, as of December 31, 2005, our actual historical cash and capitalization and our cash and cash equivalents and capitalization as adjusted to give pro forma effect to this offering and the application of the net proceeds from the offering as described in “Use of proceeds.”

You should read this table along with our audited consolidated financial statements and related notes and the other financial information contained in this prospectus.

			As of December 31, 2005
						As
(in thousands, except par value and number of shares)			Actual			adjusted
Cash and cash equivalents (1)			$	14,318		$	71,768
Total debt including current portion:
	Senior secured revolving credit facilities (1)			357,788			192,788
	Convertible subordinated debentures			147,881			147,881
	Second lien mortgage notes payable			70,000			—
	Other loans			746			746
	Deferred gain — fair value interest hedge			117			—
	Notes offered hereby			—			300,000
		Total debt including current portion	$	576,532		$	641,415
Stockholders’ equity:
	Preferred stock, $0.01 par value, 10,000,000 shares authorized; 1 share issued and outstanding			—			—
	Common stock, $0.01 par value, 100,000,000 shares authorized; and 78,650,110 shares issued (2)			787			787
	Paid-in capital in excess of par value			215,175			215,175
	Deferred compensation			(3,332	)		(3,332	)
	Treasury stock of 2,571,069 shares			(10,353	)		(10,353	)
	Accumulated other comprehensive loss			(12,382	)		(12,382	)
	Retained earnings (3)			193,720			193,008
		Total stockholders’ equity		383,615			382,903
		Total capitalization	$	960,147		$	1,024,318

(1) We intend to repay only borrowings under our senior secured revolving credit facilities that are denominated in U.S. dollars with proceeds from this offering. At December 31, 2005, we had $165 million of such borrowings outstanding. Such borrowings have subsequently increased.

(2) The number of shares issued and outstanding does not include the following: 4,908,128 shares of common stock issuable upon conversion of our convertible subordinated debentures; 2,840,695 shares of common stock issuable upon exercise of outstanding stock options issued under our stock plans as of December 31, 2005; and 2,564,949 shares of common stock available for future grant under our stock plans as of December 31, 2005.

(3) Repayment of the second lien mortgage notes would have resulted in a prepayment penalty of approximately $0.8 million, the write-off of deferred financing costs of approximately $0.4 million and recognized deferred hedge gains of approximately $0.1 million. These items would have decreased earnings for the period by approximately $0.7 million after income taxes.

S-25

Selected historical consolidated financial information

The following tables set forth selected financial information as of the dates and for the periods indicated. This financial information is derived from our consolidated financial statements as of such dates and for such periods. This 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 prospectus. The following information is not necessarily indicative of our future results.

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

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

(2) Working capital (deficit) is calculated by subtracting current liabilities from current assets, and includes the current portion of assets and liabilities, which reflect the estimated fair value of derivative obligations.

S-26

Management’s discussion and analysis of

financial condition and results of operations

The following management’s discussion and analysis (“MD&A”) is intended to help the reader understand our business, financial condition, results of operations, liquidity and capital resources. MD&A is provided as a supplement to, and should be read in conjunction with, the other sections of this prospectus, including “Business,” “Selected historical consolidated financial information,” and our consolidated financial statements and the related notes.

Our MD&A includes the following sections:

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

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

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

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

•  Liquidity, capital resources and financial position— an analysis of our cash flows, sources and uses of cash, contractual obligations and commercial commitments.

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

Overview

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

At December 31, 2005, approximately 92% of our proved reserves were natural gas and approximately 52% of our proved reserves were located in Michigan. Our activities in the Michigan Basin Antrim Shale have allowed us to develop a technical and operational expertise in the development, exploitation, exploration, acquisition and production of unconventional natural gas reserves. Consistent with one of our business strategies, we have applied the expertise gained in our Michigan activities to our Canadian projects in Alberta, Canada and our

S-27

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.

Our Company focuses on three key value drivers:

•  reserve growth;

•  production growth; and

•  improving the Company’s cash flows.

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

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

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

S-28

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

(1) Excludes production taxes.

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

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

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.

S-29

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.

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

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

S-30

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

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

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

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

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

S-31

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

Interest rate risk

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

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

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

Credit risk

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

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

Performance risk

Performance risk results when a financial counterparty fails to fulfill its contractual obligations such as commodity pricing or volume commitments. Typically, such risk obligations are defined within the trading agreements. We manage performance risk through management of credit

S-32

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

Foreign currency risk

Our Canadian subsidiary, uses the Canadian dollar as its functional currency. To the extent that business transactions in Canada are not denominated in Canadian dollars, we are exposed to foreign currency exchange rate risk. In the fourth quarter of 2005, a foreign currency transaction loss of $0.1 million was recorded as a result of a loss in the Canadian-$ value of U.S.-$ bank balances. During October and November 2004, Quicksilver loaned MGV approximately $11.4 million. To reduce its exposure to exchange rate risk, MGV entered into a forward contract that fixed the Canadian-U.S. exchange rate. The balance of the loan was repaid at the end of November 2004 and upon settlement of the forward contract, a gain of $0.2 million was recognized.

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

Application of critical accounting policies

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

Use of estimates

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

Oil and gas properties

We employ the full cost method of accounting for our oil and gas properties. Under the full cost method, all costs associated with the development, exploration and acquisition of oil and gas properties are capitalized and accumulated in cost centers on a country-by-country basis. This includes any internal costs that are directly related to development and exploration activities, but does not include any costs related to production, general corporate overhead or similar activities. Effective with the adoption of Statement of Financial Accounting Standard (“SFAS”) No. 143 in 2003, the carrying amount of oil and gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation when incurred. Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country. The application of the full cost method of accounting for oil and gas properties generally results in

S-33

higher capitalized costs and higher depletion rates compared to the successful efforts method of accounting for oil and gas properties. The sum of net capitalized costs and estimated future development and dismantlement costs for each cost center is depleted on the equivalent unit-of-production basis using proved oil and gas reserves as determined by independent petroleum engineers.

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

Oil and gas reserves

Proved oil and gas reserves, as defined by SEC Regulation S-X Rule 4-10(a) 2(i), 2(ii), 2(iii), (3) and (4), are the estimated quantities of crude oil, natural gas, and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made). Prices include consideration of changes in existing prices provided only by contractual arrangements, which do not include financial derivatives that hedge our oil and gas revenue.

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

Ceiling test

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

S-34

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

Derivative instruments

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

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

Asset retirement obligations

We have significant obligations to remove equipment and restore land at the end of oil and gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells and associated production facilities. We adopted SFAS No. 143, Accounting for Asset Retirement Obligations, effective January 1, 2003. Under SFAS No. 143, the estimated fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets is recorded in the periods in which it is incurred. When the liability is recorded, we increase the carrying amount of the related long-lived asset. The liability is accreted to the fair value at the time of the settlement over the useful life of the asset, and the capitalized cost is depleted or depreciated over the useful life of the related asset.

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

S-35

subjectivity of assumptions and the relatively long life of most of our oil and gas assets, the costs to ultimately retire these assets may vary significantly from previous estimates.

Income taxes

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

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

Off-balance sheet arrangements

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

Results of operations

Summary financial data

Years ended December 31, 2005, 2004 and 2003

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

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

S-36

Operating revenues

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

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

Gas, oil and NGL sales

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

				Years ended December 31,
				2005		2004		2003
Average daily sales volume
	Natural gas— Mcfd
		United States			87,518		83,727		86,608
		Canada			40,617		23,789		8,011
			Total		128,135		107,516		94,619
	Crude oil— Bbld
		United States			1,516		1,882		2,212
		Canada			—		—		1
			Total		1,516		1,882		2,213
	NGL— Bbld
		United States			603		351		365
		Canada			8		1		4
			Total		611		352		369
	Total sales— Mcfed
		United States			100,223		97,120		102,073
		Canada			40,672		23,802		8,042
			Total		140,895		120,922		110,115
Natural gas, oil and NGL revenue (in thousands)
		United States		$	209,715	$	134,268	$	127,339
		Canada			96,489		42,905		11,698
			Total natural gas, oil and NGL revenue	$	306,204	$	177,173	$	139,037

S-37

					Years ended December 31,
					2005		2004		2003
Product revenue (in thousands)
		Natural gas sales			$	269,547	$	150,716	$	116,563
		Crude oil sales				27,947		22,782		19,576
		NGL sales				8,710		3,675		2,898
			Total product sale revenue		$	306,204	$	177,173	$	139,037
Unit prices— including impact of hedges
	Natural gas— per Mcf
		United States			$	5.42	$	3.52	$	3.32
		Canada				6.50		4.92		3.98
				Consolidated		5.76		3.83		3.38
Crude oil— per Bbl
		United States			$	50.50	$	33.07	$	24.23
		Canada				—		—		24.46
			Consolidated			50.50		33.07		24.23
NGL— per Bbl
		United States			$	38.88	$	28.55	$	21.45
		Canada				53.91		22.18		26.01
			Consolidated			39.08		28.52		21.50

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

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

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

S-38

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

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

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

Other revenues

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

Operating expenses

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

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

S-39

Oil and gas production expense

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

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

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

Canadian production expense for 2005 increased $6.0 million from 2004 production expense, exclusive of stock-based compensation expense. We drilled 483 (259.1 net) wells during 2005 and net natural gas production increased 6.1 MMcf. Canadian production expense on a Mcfe-

S-40

basis decreased $0.07/ Mcfe. The decrease reflected additional improvement in the economies of scale for our Canadian operations.

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

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

Depletion, depreciation and accretion

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

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

Depletion expense for 2004 was $34.5 million, as compared to 2003 depletion expense of $27.4 million. Additional sales volumes of approximately 4,070,000 Mcfe and a $0.10 per Mcfe increase in the consolidated depletion rate added $7.2 million of depletion expense from 2003

S-41

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

General and administrative expense

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

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

Interest expense

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

For 2004, interest expense was $15.7 million and $4.5 million less than 2003 interest expense. Interest expense in 2003 included a charge of $3.8 million as a result of the early redemption of $53.0 million in principal amount of our subordinated notes payable, which included a $3.2 million prepayment penalty and the write-off of $1.5 million of remaining deferred financing costs, partially offset by a deferred hedging gain of $0.9 million. Ongoing interest expense decreased approximately $0.7 million due to a decrease in LIBOR interest rates and the

S-42

2003 issuance of our second mortgage notes, which accrue interest at a substantially lower rate than the subordinated notes payable that were retired in mid-2003, partially offset by an increase in our average debt outstanding during 2004 as compared to 2003.

Income taxes

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

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

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

Liquidity, capital resources and financial position

Our statements of cash flows are summarized as follows:

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

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

Cash flows from operating activities increased $35.2 million, or 71%, for 2004 compared to 2003. The principal factor in the increase was a $12.2 million increase in operating income for 2004, together with increases in accounts receivable and payable, accrued liabilities and depletion, depreciation and amortization. In addition, 2003 income included a $3.2 million prepayment premium incurred when the $53 million of subordinated notes were redeemed. Operating cash flows were also higher because of MGV’s use of cash calls on other working

S-43

interest owners prior to incurring capital expenditures on various CBM exploration and development projects. A reduction in our third party marketing activities further increased operating cash flows approximately $2.0 million.

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

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

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

Property and equipment costs incurred

		United
(In thousands)		States		Canada		Consolidated
2005
Proved acreage		$	821	$	1,620		$  2,441
Unproved acreage			48,419		3,784		52,203
Development costs			24,007		82,388		106,395
Exploration costs			109,148		9,829		118,977
Gas processing, transportation and administrative			59,894		21,059		80,953
	Total	$	242,289	$	118,680		$360,969

S-44

		United
(In thousands)		States		Canada		Consolidated
2004
Proved acreage		$	11,907	$	2,942		$ 14,849
Unproved acreage			31,857		7,144		39,001
Development costs			45,213		71,094		116,307
Exploration costs			25,673		22,631		48,304
Gas processing, transportation and administrative			12,527		769		13,296
	Total	$	127,177	$	104,580		$231,757
2003
Proved acreage		$	3,215	$	3,388		$  6,603
Unproved acreage			24,063		6,739		30,802
Development costs			37,682		41,820		79,502
Exploration costs			9,411		17,066		26,477
Gas processing, transportation and administrative			4,820		284		5,104
	Total	$	79,191	$	69,297		$148,488

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

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

Capital costs incurred in 2003 of $148.5 million included $69.0 million for development and exploration of our Canadian CBM projects and acreage. We spent $31.8 million for further development of our Indiana/ Kentucky properties and additional acreage positions. Our pipeline

S-45

in the area, Cardinal Pipeline, accounted for $4.0 million of our capital expenditures. Michigan capital expenditures of $24.6 million focused on continued development and exploitation of the Antrim Shale. A significant acreage position in the Fort Worth Basin of Texas was acquired for approximately $12.6 million in 2003.

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

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

At December 31, 2005, we had outstanding $150 million of 1.875% convertible subordinated debentures due in 2024. Holders of the debentures may require us to repurchase all or a portion of their debentures on November 1, 2011, 2014 or 2019 at a price equal to the principal amount thereof plus accrued and unpaid interest. The debentures are convertible into Quicksilver common stock at a rate of 32.7209 shares for each $1,000 debenture, subject to adjustment. Generally, except upon the occurrence of specified events, holders of the debentures are not entitled to exercise their conversion rights unless the closing price of our stock price for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter is $36.67 (120% of the conversion price

S-46

per share). Upon conversion, we have the option to deliver in lieu of our common stock, cash or a combination of cash and our common stock. At December 31, 2005, the debentures were convertible into 4,908,128 shares of Quicksilver common stock.

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

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

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

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

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

Financial position

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

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

S-47

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

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

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

Contractual obligations and commercial commitments

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

		Payments due by period
Contractual obligations				Less than		1-3		4-5		More than
(In thousands)		Total		1 year		years		years		5 years
Long-term debt		$	578,534	$	70,493	$	358,041	$	—		$150,000
Scheduled interest obligations			109,559		9,190		16,728		11,152		72,489
Derivative obligations			45,263		40,632		4,631		—		—
Purchase obligations			6,894		6,894		—		—		—
Asset retirement obligations			20,965		73		173		115		20,604
Operating lease obligations			8,132		2,819		5,313		—		—
	Total obligations	$	769,347	$	130,101	$	384,886	$	11,267		$243,093

•  Long-term debt— As of December 31, 2005, we had $357.8 million outstanding under our senior secured credit facility, $150 million of contingently convertible debentures (before discount), $70 million of second lien mortgage notes and $0.7 million of other debt. Based upon our debt outstanding and interest rates in effect at December 31, 2005, we anticipate interest payments to be approximately $27.7 million in 2006. We expect to increase borrowings under our senior secured credit facility to fund our capital spending program throughout 2006. For each additional $10 million in borrowings, annual interest payments will increase by approximately $0.5 million. If the borrowing base under our senior secured credit facility were to be fully utilized by year-end 2006 at interest rates in effect at December 31, 2005, we estimate that interest payments would increase by approximately $6.5 million. If interest rates on our December 31, 2005 variable debt balance of $387.8 million increase or decrease by one percentage point, our annual pretax income will decrease or increase by $3.9 million.

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

S-48

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

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

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

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

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

		Amounts of commitments expiration per period
Commercial commitments		Total		Less than		1-3		4-5		More than
(In thousands)		committed		1 year		years		years		5 years
Drilling rig commitment			4,448		4,448		—		—		—
Standby letters of credit		$	997	$	420	$	557		$—		$—
	Total commitments	$	5,445	$	4,868	$	557		$—		$—

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

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

Forward-looking information

Certain statements contained in this prospectus and other materials we file with the SEC, or in other written or oral statements made or to be made by us, other than statements of historical fact, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements give our current expectations or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. Actual results may vary materially. You are

S-49

cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

•  changes in general economic conditions;

•  fluctuations in natural gas and crude oil prices;

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

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

•  effects of hedging natural gas and crude oil prices;

•  competitive conditions in our industry;

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

•  changes in the availability and cost of capital;

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

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

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

•  the effects of existing or future litigation.

This list of factors is not exhaustive, and new factors may emerge or changes to these factors may occur that would impact our business. Additional information regarding these and other factors may be contained in our filings with the SEC, especially on Forms 10-K, 10-Q and 8-K. All such risk factors are difficult to predict, contain material uncertainties that may affect actual results and may be beyond our control.

Recently issued accounting standards

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

S-50

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

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

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

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

S-51

Business

General

We are a Fort Worth, Texas-based independent oil and gas company engaged in the development and production of natural gas, 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 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 have achieved a reserve replacement ratio of 299%, 345% and 384% in 2003, 2004 and 2005, respectively, virtually all of which was achieved organically, with an all in three-year average finding and development cost of $1.12 per Mcfe. We believe that much of our future growth will be through development, exploitation and exploration of our leasehold interests, including those in CBM formations in Alberta, Canada, the Barnett Shale formation in the Fort Worth Basin in north Texas, and the 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 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.

S-52

The remaining $5 million of the 2006 capital expenditure budget is planned for our interests in Indiana/ Kentucky and the Rocky Mountain Region.

For the year ended December 31, 2005, we had average daily production of 140.9 MMcfe per day, which implies a reserve life (proved reserved divided by 2005 annual production) of approximately 21.7 years. The following table presents our reserves at December 31, 2005 and our average daily production for the year ended December 31, 2005. In addition, our geographic segment information is included under note 21 of our consolidated financial statements, included elsewhere in this prospectus supplement.

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

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 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, representing a 299%, 345% and 384% in 2003, 2004 and 2005, respectively, reserve replacement ratio over that time period. 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

S-53

the Barnett Shale formation in the Fort Worth Basin. Our growth was achieved with an all in three-year average finding and development cost of $1.12 per Mcfe ($1.24 per Mcfe in 2005), which we believe compares favorably to the industry. 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 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. In addition, 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.

S-54

Properties

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

Michigan

Our Michigan operations comprised approximately 52% of our estimated proved reserves and 57% of our average daily production for the year ended December 31, 2005. 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 vast majority of our Michigan reserves are located in the Antrim Shale, as illustrated by the table below.

	Proved						2005
	reserves				% Proved		production
Producing formation	(Bcfe)		% Gas		developed		(MMcfed)
Antrim Shale		503.5		100%		92%		59.7
Non-Antrim		78.0		62%		82%		21.0
All formations		581.5		95%		90%		80.7

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.

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.

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

S-55

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.

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 1,683 (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.

We operate in the Horseshoe Canyon formation in Alberta, Canada and also have acreage in the Mannville formation in Alberta. Our 2006 Canadian capital budget for drilling, gathering lines and gas processing facilities, and acreage acquisitions, is approximately $123 million.

S-56

Texas

Our operations in Texas comprised approximately 16% of our estimated proved reserves and approximately 7% of our average daily production for the year ended December 31, 2005. We operate in the Barnett Shale in the Fort Worth Basin in northern Texas and we also have acreage in the Delaware Basin in west Texas. The 2006 capital budget allocated to Texas is approximately $399 million.

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.

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

S-57

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 “Risk factors.”

Governmental regulation

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

Environmental matters

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

•  require the acquisition of a permit before drilling commences;

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

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

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

•  impose substantial liabilities for pollution resulting from operations.

In addition, these laws, rules and regulations may restrict the rate of natural gas and crude oil production below the rate that would otherwise exist. The regulatory burden on the industry increases the cost of doing business and consequently affects our profitability. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, disposal or clean-up requirements could adversely affect our financial position, results of operations and cash flows. While we believe that we are in

S-58

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 definition of hazardous waste “drilling fluids, produced waters,

S-59

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.

S-60

Management

The following sets forth information about our executive officers and directors as of February 15, 2006.

Directors and executive officers

Name	Age		Position(s)
James A. Hughes		43	Director
Steven M. Morris		54	Director
W. Yandell Rogers, III		43	Director
Mark J. Warner		42	Director
Thomas F. Darden		52	Chairman of the Board
Glenn Darden		50	President, Chief Executive Officer and Director
Anne Darden Self		48	Vice President— Human Resources and Director
Jeff Cook		49	Executive Vice President— Operations
John C. Cirone		56	Senior Vice President, General Counsel and Secretary
Philip W. Cook		44	Senior Vice President— Chief Financial Officer
D. Wayne Blair		49	Vice President, Controller and Chief Accounting Officer
William S. Buckler		44	Vice President— U.S. Operations
Robert N. Wagner		42	Vice President— Reservoir Engineering

Directors

•  James A. Hughes has been an executive of Priest River Ltd., a privately owned holding company, since 2003. Mr. Hughes served as a director of Quicksilver from 2001 through 2004 and again since March 2005. He served as President and Chief Operating Officer of Enron Global Assets, an international energy infrastructure company from 1994 until 2003. Mr. Hughes’ term expires in 2006.

•  Steven M. Morris has served as President of Morris & Company, a private investment firm, since 1992. He is a Certified Public Accountant, and has been a director of Quicksilver since 1999. Mr. Morris’ term expires in 2007.

•  W. Yandell Rogers, III has served as Chief Executive Officer of Priest River Ltd. and Lewiston Atlas Ltd., each a privately owned holding company since 2002. Mr. Rogers has served as a director of Quicksilver since 1999. Mr. Roger’s term expires in 2006. He was Chief Executive Officer of Ridgway’s, Inc., a provider of reprographics to the engineering and construction industries from 1997 until 2002.

•  Mark J. Warner has been Director of Corporate Development of Point One, a telecommunications company, since April 2004. He served as Senior Vice President, Growth Capital Partners, L.P., an investment banking firm from 2000 until 2004. Mr. Warner has served as a director of Quicksilver since 1999. Mr. Warner’s term expires in 2008. From 1995 until 2000, he was Director of Domestic Finance at Enron Corporation, an energy trading company.

•  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. During his term as President of Mercury, Mercury developed and acquired interests in over 1,200 producing

S-61

	wells in Michigan, Indiana, Kentucky, Wyoming, Montana, New Mexico and Texas. Prior to joining us, Mr. Darden was employed by Mercury or its 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. Mr. Darden’s term expires in 2008.
•	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. Mr. Darden’s term expires in 2006.
•	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. Ms. Self’s term expires in 2007.

Executive officers

•  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 of Mercury in 1998 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

S-62

	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 the 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.
•	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.

Our board of directors has standing Audit, Nominating and Corporate Governance, and Compensation Committees. Messrs. Hughes, Morris, Rogers and Warner serve on each of these committees. The Board has determined that Mr. Morris, the Chair of the Audit Committee, is an “audit committee financial expert” within the meaning of applicable SEC regulations. Our board of directors also elected Mr. Hughes to fill the position of Presiding Director.

Family relationship among directors

Thomas F. Darden, Glenn Darden and Anne Darden Self are siblings.

S-63

Security ownership of management

and certain beneficial holders

The following table presents information regarding the number of shares of our common stock beneficially owned as of February 13, 2006 (unless otherwise indicated), by each of Quicksilver’s directors, Quicksilver’s five most highly compensated executive officers (referred to as our Named Executive Officers), and all of our directors and executive officers as a group. In addition, the table presents information about each person known to us to beneficially own 5% or more of our common stock. Unless otherwise indicated by footnote, the beneficial owner exercises sole voting and investment power over the shares. The percentage of beneficial ownership is calculated on the basis of 78,802,306 shares of our common stock outstanding as of February 13, 2006.

	Beneficial share ownership
			Percent of
	Number		outstanding
Directors, Named Executive Officers and 5% stockholders	of shares		shares
Directors/ Named Executive Officers
Glenn Darden(1)(2)(3)		1,763,945		2.24%
Thomas F. Darden(1)(2)(3)(4)		1,833,430		2.32%
Anne Darden Self(1)(2)(3)		1,376,257		1.75%
James A. Hughes(3)		4,547		*
Steven M. Morris(3)		491,689		*
W. Yandell Rogers, III(3)		73,357		*
Mark J. Warner(3)		49,752		*
William S. Buckler(2)(3)		18,118		*
John C. Cirone(3)(4)		18,637		*
Jeff Cook(3)		317,785		*
Directors and executive officers as a group (13 persons)(1)(2)(3)(4)		5,581,916		7.05%
5% or more stockholders
Mercury Production Company(5)(7)		13,117,935		16.65%
Mercury Exploration Company(5)(7)		13,113,435		16.64%
Quicksilver Energy, L.P.(6)(7)		9,092,583		11.54%
Pennsylvania Management, LLC(6)(7)		9,092,583		11.54%
FMR Corp.(8)		9,766,379		12.72%
Neuberger Berman, Inc.(9)		7,944,173		10.46%
Capital Research and Management Company(10)		7,853,850		10.30%

* Indicates less than 1%

(1) Includes with respect to Messrs. G. Darden and T. Darden and Ms. Self 340,050, 399,330 and 285,600 shares, respectively, owned by family member trusts of which he or she is a trustee. Includes for all directors and officers as a group 512,490 shares held by the trusts. Does not include shares beneficially owned by Mercury Exploration, Mercury Production, Quicksilver Energy, L.P. (“QELP”) or Pennsylvania Management. See footnotes 5 and 6.

(2) Includes with respect to each of the following individuals and the directors and executive officers as a group the following approximate numbers of shares represented by units in a Unitized Stock Fund held through our 401(k) Plan: Mr. G. Darden 3,112; Mr. T. Darden 41,168; Ms. Self 19,503; Mr. Buckler 93; and all directors and officers as a group 65,316.

(3) Includes with respect to each of the following individuals and the directors and executive officers as a group the following numbers of shares subject to options that will vest on or before April 14, 2006: Mr. G. Darden 59,702, Mr. T. Darden 59,702; Ms. Self 28,173; Mr. Hughes 2,455; Mr. Morris 33,807; Mr. Rogers 34,407; Mr. Warner 33,807; Mr. Buckler 4,200; Mr. Cirone 6,792; Mr. Cook 35,953; and all directors and executive officers as a group 298,998.

S-64

(4) Excludes as to Mr. T. Darden and Mr. Cirone 22,000 and 11,500 shares, respectively, subject to restricted stock units granted in January 2006.

(5) Each of Messrs G. Darden and T. Darden and Ms. Self is a director and stockholder of Mercury Production and a director of Mercury Exploration. Mercury Exploration is a wholly-owned subsidiary of Mercury Production. In addition to the 13,113,435 shares owned by its subsidiary, Mercury Production owns 4,500 shares directly. Each of Messrs. G. Darden and T. Darden and Ms. Self disclaims beneficial ownership of all shares owned by Mercury, except to the extent of his or her pecuniary interest therein. Such shares are not included in the shares reported as beneficially owned by Messrs. G. Darden or T. Darden or Ms. Self.

(6) Pennsylvania Management is the general partner of QELP and, as such, has sole voting and investment power with respect to 9,092,583 shares of our common stock held by QELP. Each of Messrs. G. Darden and T. Darden and Ms. Self is a member of Pennsylvania. Each of Messrs. G. Darden and T. Darden and Ms. Self disclaims beneficial ownership of all shares owned by QELP, except to the extent of his or her pecuniary interest therein. Such shares are not included in the shares reported as beneficially owned by Messrs. G. Darden or T. Darden or Ms. Self.

(7) The address of Mercury Exploration, Mercury Production, QELP and Pennsylvania Management is 777 West Rosedale Street, Suite 300, Fort Worth, Texas 76104.

(8) According to a Schedule 13G/ A filed by FMR Corp. with the SEC on February 14, 2006, FMR Corp. had sole voting power over 2,234,012 shares of common stock and sole investment power over 9,766,379 shares of our common stock. The address of FMR Corp. is 82 Devonshire Street, Boston, Massachusetts 02109.

(9) According to a Schedule 13G/ A filed by Neuberger Berman Inc. with the SEC on February 14, 2006, Neuberger Berman Inc. had sole voting power over 738,214 shares of our common stock, shared voting power with Neuberger Berman, LLC over 6,643,150 shares of our common stock, and shared investment power with Neuberger Berman, LLC over 7,944,173 shares of our common stock. The address of Neuberger Berman Inc. is 605 Third Avenue, New York, New York 10158.

(10) According to a Schedule 13G/ A filed by Capital Research and Management Company with the SEC on February 10, 2006, Capital Research and Management Company had sole voting power over 5,753,850 shares of our common stock and sole investment power over 7,853,850 shares of our common stock. The address of Capital Research and Management Company is 333 South Hope Street, Los Angeles, California 90071.

S-65

Certain relationships and related transactions

We paid $780,000 in 2003, $860,000 in 2004 and $1,032,000 in 2005, for rent on buildings owned by Pennsylvania Avenue, L.P., a limited partnership owned by members of the Darden family and Mercury. Rental rates were determined based on comparable rates charged by third parties. In February 2006, we entered into an amendment to our lease with Pennsylvania Avenue to increase the amount of office space covered thereby. In conjunction with this lease amendment, we also agreed to sublease a portion of the property we lease to Mercury. At December 31, 2005, we had future lease obligations to Pennsylvania Avenue of $3.8 million through 2009. The lease amendment increases the obligation by $0.6 million. During 2003, we paid $2.05 million of principal and interest on a note payable to Mercury associated with the acquisition of assets from Mercury. The note was retired in 2003. Mercury paid us $103,000 in 2004 and $102,000 in 2005 to reimburse us for property and casualty insurance, workers compensation insurance and health insurance premiums we paid for the benefit of Mercury. We paid $5,600 in 2004 and $11,400 in 2005 for the use of an airplane owned by Panther City Aviation LLC, a limited liability company owned in part by Thomas F. Darden.

S-66

Description of other indebtedness

Senior secured revolving credit facilities

Our senior secured revolving credit facilities mature on July 28, 2009 and provide for revolving credit loans and letters of credit from time to time in an aggregate amount outstanding not to exceed the lesser of the borrowing base or $600 million. At December 31, 2005 the borrowing base was $600 million. The borrowing base is subject to annual redetermination and certain other redeterminations, based upon several factors. Scheduled redeterminations occur on May 1 of each year. The lenders’ commitments under the facilities are allocated between U.S. and Canadian funds, with the U.S. funds being available for borrowing by Quicksilver and Canadian funds being available for borrowing by our Canadian subsidiary, MGV Energy Inc. At our option, loans may be prepaid, and revolving credit commitments may be reduced, in whole or in part at any time in minimum amounts. As of year-end, we can designate the interest rate on amounts outstanding at either the London Interbank Offered Rate (LIBOR) +1.375% or specified bank rates. The collateral for the credit facility consists of substantially all of our existing assets and any future reserves acquired. Quicksilver’s obligations under the senior secured revolving credit facilities are guaranteed by the subsidiary guarantors, and MGV Energy Inc.’s obligations are guaranteed by Quicksilver and the subsidiary guarantors. The loan agreements prohibit the declaration or payment of dividends by us and contain other restrictive covenants, which, among other things, require the maintenance of a minimum current ratio (calculated in accordance with provisions of the loan agreements) of at least 1.0. At December 31, 2005, the effective interest rate under our senior secured revolving credit facilities was 5.328% and we had $242.2 million available under the senior secured revolving credit facilities.

Second mortgage notes due 2006

As of December 31, 2005, we had outstanding $70 million of second mortgage notes due 2006, of which $40 million bore interest at a fixed rate of 7.5% and $30 million bore interest at a variable rate based upon three-month LIBOR plus 4.06%. We intend to use a portion of the proceeds from this offering to fully repay our second mortgage notes. See “Use of proceeds.”

Convertible subordinated debentures due 2024

On November 1, 2004, we sold $150 million of 1.875% convertible subordinated debentures due in 2024 for gross proceeds of approximately $147.8 million. Holders of the debentures may require us to repurchase all or a portion of their debentures on November 1, 2011, 2014 or 2019 at a price equal to the principal amount thereof plus accrued and unpaid interest. The debentures are convertible into Quicksilver common stock at a current rate of 32.72085 shares for each $1,000 debenture, subject to adjustment. Generally, except upon the occurrence of specified events, holders of the debentures are not entitled to exercise their conversion rights until the Quicksilver’s stock price is 120% of the conversion price per share. Upon conversion, we have the option to deliver in lieu of Quicksilver common stock, cash or a combination of cash and Quicksilver common stock. Currently, these debentures are convertible at the option of the holder.

S-67

Description of the notes

The Company will issue the Notes under an Indenture, dated as of December 22, 2005 (the “Base Indenture”), between the Company and JPMorgan Chase Bank, National Association, as trustee (the “Trustee”), as supplemented by a First Supplemental Indenture relating to the Notes among the Company, the Trustee and the Subsidiary Guarantors (the “Supplemental Indenture,” and together with the Base Indenture, the “Indenture”). The Indenture is unlimited in aggregate principal amount, although the issuance of Notes in this offering will be limited to $300 million. We may issue an unlimited principal amount of additional notes having identical terms and conditions as the Notes (the “Additional Notes”). We will be permitted to issue such Additional Notes only if at the time of such issuance, we are in compliance with the covenants contained in the Indenture. Any Additional Notes will be part of the same series as the Notes that we are currently offering and will vote on all matters with the holders of the Notes.

This description of Notes is intended to be an overview of the material provisions of the Notes and the Indenture. Because this description of notes is only a summary, you should refer to the Indenture for a complete description of the Company’s obligations and your rights in respect of the Notes. We have filed a copy of each of the Base Indenture and the Supplemental Indenture as exhibits to the registration statement which includes this Prospectus. You should read the Base Indenture and the Supplemental Indenture carefully and in their entirety. You may request copies of these documents at the Company’s address set forth under the caption “Where You Can Find More Information” in the base prospectus.

You will find the definitions of capitalized terms used in this description under the heading “Certain Definitions.” For purposes of this description, references to “the Company,” “we,” “our” and “us” refer only to Quicksilver Resources Inc. and not to its subsidiaries.

General

The Notes. The Notes:

•  are general unsecured, senior subordinated obligations of the Company;

•  are limited to an aggregate principal amount of $300 million, subject to our ability to issue Additional Notes;

•  mature on           , 2016;

•  will be issued only in fully registered form, without coupons;

•  will be issued in denominations of $1,000 and integral multiples of $1,000;

•  will generally be represented by one or more registered Notes in global form, but in certain circumstances may be represented by Notes in definitive form, in each case as described in “Book-entry, Delivery and Form;”

•  are subordinated in right of payment to all existing and future Senior Indebtedness of the Company, including the Senior Secured Credit Agreement;

•  rank equally in right of payment to any future Senior Subordinated Indebtedness of the Company; and

•  are unconditionally guaranteed on a senior subordinated basis by Mercury Michigan Inc., Terra Energy Ltd., GTG Pipeline Corporation, Cowtown Pipeline Funding, Inc.,

S-68

Cowtown Pipeline Management, Inc., Terra Pipeline Company, Beaver Creek Pipeline, L.L.C., Cowtown Pipeline, LP and Cowtown Gas Processing L.P., each a Domestic Subsidiary of the Company, as described in “Subsidiary Guarantees.”

Interest. Interest on the Notes will compound semi-annually and will:

•  accrue at the rate of      % per annum;

•  accrue from the date of original issuance or, if interest has already been paid, from the most recent interest payment date;

•  be payable in cash semi-annually in arrears on           and           , commencing on           , 2006;

•  be payable to the holders of record on the close of business on the           and           immediately preceding the related interest payment dates; and

•  be computed on the basis of a 360-day year comprised of twelve 30-day months.

Payments on the notes; paying agent and registrar

We will pay principal of, premium, if any, and interest on the Notes at the office or agency designated by the Company in the Borough of Manhattan, The City of New York, except that we may, at our option, pay interest on the Notes by check mailed to holders of the Notes at their registered address as it appears in the security register for the Notes. We have initially designated the corporate trust office of the Trustee in New York, New York to act as our paying agent and registrar in respect of the Notes. We may, however, change the paying agent or registrar without prior notice to the holders of the Notes, and the Company or any of its Restricted Subsidiaries may act as paying agent or registrar in respect of the Notes.

We will pay principal of, premium, if any, and interest on, Notes in global form registered in the name of or held by The Depository Trust Company or its nominee in immediately available funds to The Depository Trust Company or its nominee, as the case may be, as the registered holder of the global Note.

Transfer and exchange

The Notes will be issued in registered form and will be transferable only upon the surrender of the Notes being transferred for registration of transfer. No service charge will be imposed by the Company, the Trustee or the registrar for any registration of transfer or exchange of Notes, but we may require a holder to pay a sum sufficient to cover any tax or other governmental charge that may be imposed in connection with any registration of transfer. The Company is not required to transfer or exchange any Note selected for redemption. Also, the Company is not required to transfer or exchange any Note for a period of 15 days before a selection of Notes to be redeemed.

The registered holder of a Note will be treated as its owner for all purposes.

Optional redemption

Except as described below, the Notes are not redeemable until           , 2011. On and after           , 2011, the Company may redeem all or, from time to time, a part of the Notes upon not less than 30 nor more than 60 days’ notice, at the following redemption prices (expressed as a percentage of principal amount) plus accrued and unpaid interest on the Notes, if any, to the

S-69

applicable redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date), if redeemed during the twelve-month period beginning on                     of the years indicated below:

Year	Percentage
2011		%
2012		%
2013		%
2014 and thereafter		100.00%

Prior to                     , 2009, the Company may on any one or more occasions redeem up to 35% of the original principal amount of the Notes with the Net Cash Proceeds of one or more equity offerings at a redemption price of           % of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date); provided that:

(1) at least 65% of the original principal amount of the Notes remains outstanding after each such redemption; and

(2) the redemption occurs within 90 days after the closing of such equity offering.

If the optional redemption date is on or after an interest record date and on or before the related interest payment date, the accrued and unpaid interest, if any, will be paid to the Person in whose name the Note is registered at the close of business on the record date, and no additional interest will be payable to holders whose Notes will be subject to redemption.

In the case of any partial redemption, selection of the Notes for redemption will be made by the Trustee:

•  in compliance with the requirements of the principal national securities exchange, if any, on which the Notes are listed; or

•  if the Notes are not listed, then on a pro rata basis, by lot or by such other method as the Trustee in its sole discretion may deem to be fair and appropriate.

No Note of $1,000 in original principal amount or less will be redeemed in part. If any Note is to be redeemed in part only, the notice of redemption relating to such Note will state the portion of the principal amount thereof to be redeemed. A new Note in principal amount equal to the unredeemed portion thereof will be issued in the name of the holder upon cancellation of the original Note.

In addition, at any time prior to                     , 2011, the Company may redeem the Notes, in whole but not in part, at a redemption price equal to 100% of the principal amount thereof plus the Applicable Premium plus accrued and unpaid interest, if any, to the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date).

“Applicable Premium” means, with respect to a Note at any redemption date, the greater of (i) 1.0% of the principal amount of such Note and (ii) the excess of (A) the present value at such time of (1) the redemption price of such Note at                     , 2011 (expressed as a percentage of principal amount) plus (2) all required interest payments due on such Note

S-70

through                     , 2011, computed using a discount rate equal to the Treasury Rate plus 50 basis points, over (B) the then outstanding principal amount of such Note.

“Treasury Rate” means the yield to maturity at the time of computation of United States Treasury securities with a constant maturity (as compiled and published in the most recent Federal Reserve Statistical Release H.15 (519) which has become publicly available at least two business days prior to the redemption date (or, if such Statistical Release is no longer published, any publicly available source or similar market data)) most nearly equal to the period from the redemption date to                     , 2011; provided, however, that if the period from the redemption date to                     , 2011 is not equal to the constant maturity of a United States Treasury security for which a weekly average yield is given, the Treasury Rate shall be obtained by linear interpolation (calculated to the nearest one-twelfth of a year) from the weekly average yields of United States Treasury securities for which such yields are given, except that if the period from the redemption date to                     , 2011 is less than one year, the weekly average yield on actually traded United States Treasury securities adjusted to a constant maturity of one year shall be used.

The Company is not required to make mandatory redemption payments or sinking fund payments with respect to the Notes.

Ranking and subordination

The Notes will be unsecured Senior Subordinated Indebtedness of the Company, will be subordinated in right of payment to all existing and future Senior Indebtedness of the Company, will rank equally in right of payment with all existing and future Senior Subordinated Indebtedness of the Company and will be senior in right of payment to all existing and future Subordinated Obligations of the Company. The Notes will be effectively subordinated to all of our secured Indebtedness to the extent of the value of the assets securing such Indebtedness. However, payment from the money or the proceeds of U.S. Government Obligations held in trust in connection with any defeasance under the Indenture (as described under “Defeasance”) will not be subordinated to any Senior Indebtedness or subject to these restrictions.

As a result of the subordination provisions described below, holders of the Notes may recover less than holders of the Company’s Senior Indebtedness in the event of an insolvency, bankruptcy, reorganization, receivership or similar proceedings relating to the Company. Similarly, the Subsidiary Guarantees of the Notes will be subordinated to obligations in respect of Guarantor Senior Indebtedness to the same extent the Notes are subordinated to Senior Indebtedness. Moreover, the Notes will be structurally subordinated to the liabilities of non-guarantor Subsidiaries of the Company. Assuming that we had applied the net proceeds we receive from the offering in the manner described under “Use of proceeds,” as of December 31, 2005:

•  our outstanding Senior Indebtedness would have been $240 million, which includes letters of credit and hedging obligations with parties to our senior secured revolving credit facilities, all of which would have been secured;

•  we would have had no Senior Subordinated Indebtedness other than the Notes;

•  our Restricted Subsidiaries would have had $325 million of liabilities (excluding intercompany liabilities); and

S-71

•  our non-guarantor Subsidiaries would have had $298 million of liabilities (excluding intercompany liabilities).

Although the Indenture will limit the amount of indebtedness that we and our Restricted Subsidiaries may Incur, such indebtedness may be substantial and all of it may be Senior Indebtedness.

Only Indebtedness of the Company that is Senior Indebtedness will rank senior to the Notes in accordance with the provisions of the Indenture. The Notes will in all respects rank equally with all other Senior Subordinated Indebtedness of the Company. As described in “Limitation on layering,” we may not Incur any Indebtedness that is senior in right of payment to the Notes, but junior in right of payment to Senior Indebtedness. Our unsecured Indebtedness is not deemed to be subordinate or junior to secured Indebtedness merely because it is unsecured.

The Company may not pay principal of, premium, if any, or interest on, or other payment obligations in respect of, the Notes or make any deposit pursuant to the provisions described under “Defeasance” and may not otherwise repurchase, redeem or retire any Notes (collectively, “pay the Notes”) if:

(1)	any Senior Indebtedness is not paid when due in cash or Cash Equivalents; or
(2)	any other default on Senior Indebtedness occurs and the maturity of the Senior Indebtedness is accelerated in accordance with its terms;

unless, in either case, the Senior Indebtedness has been paid in full in cash or Cash Equivalents and, in the case of revolving Indebtedness, all commitments to lend thereunder have been terminated or the default has been cured or waived and any acceleration has been rescinded. However, the Company may pay the Notes if the Company and the Trustee receive written notice approving such payment from the Representative of the Senior Indebtedness with respect to which either of the events set forth in clause (1) or (2) of the immediately preceding sentence has occurred and is continuing.

The Company also will not be permitted to pay the Notes for a Payment Blockage Period (as defined below) during the continuance of any default, other than a default described in clause (1) or (2) of the preceding paragraph, on any Designated Senior Indebtedness that permits the holders of the Designated Senior Indebtedness to accelerate its maturity immediately without either further notice (except such notice as may be required to effect such acceleration) or the expiration of any applicable grace periods.

A “Payment Blockage Period” commences on the receipt by the Trustee (with a copy to the Company) of written notice (a “Blockage Notice”) of a default of the kind described in the immediately preceding paragraph from the Representative of the holders of the Designated Senior Indebtedness specifying an election to effect a Payment Blockage Period and ends 179 days after receipt of the notice. The Payment Blockage Period will end earlier if the Payment Blockage Period is terminated:

(1)	by written notice to the Trustee and the Company from the Person or Persons who gave the Blockage Notice;
(2)	because the default giving rise to the Blockage Notice is no longer continuing; or
(3)	because the Designated Senior Indebtedness has been repaid in full.

S-72

The Company may resume payments on the Notes after the end of a Payment Blockage Period (including any missed payments) unless the holders of the Designated Senior Indebtedness or the Representatives of such holders have accelerated the maturity of the Designated Senior Indebtedness. Not more than one Blockage Notice may be given in any consecutive 360-day period, irrespective of the number of defaults with respect to Designated Senior Indebtedness during that period. However, if any Blockage Notice within such 360-day period is given by or on behalf of any holders of Designated Senior Indebtedness other than the Bank Indebtedness, the Representatives of the Bank Indebtedness may give another Blockage Notice within that period. In no event, however, may the total number of days during which any Payment Blockage Period or Periods is in effect exceed 179 days in the aggregate during any consecutive 360-day period. No default or event of default that existed or was continuing on the date of the commencement of any Payment Blockage Period with respect to the Designated Senior Indebtedness initiating the Payment Blockage Period shall be, or be made, the basis of the commencement of a subsequent Payment Blockage Period by the Representative of the Designated Senior Indebtedness, whether or not within a period of 360 consecutive days, unless such default or event of default shall have been cured or waived for a period of not less than 90 consecutive days.

In the event of:

(1)	a total or partial liquidation or a dissolution of the Company;
(2)	a reorganization, bankruptcy, insolvency, receivership of or similar proceeding relating to the Company or its property; or
(3)	an assignment for the benefit of creditors or marshaling of the Company’s assets and liabilities, then

the holders of Senior Indebtedness will be entitled to receive payment in full in cash or Cash Equivalents in respect of Senior Indebtedness (including interest accruing after, or which would accrue but for, the commencement of any proceeding at the rate specified in the applicable Senior Indebtedness, whether or not a claim for such interest would be allowed in such proceeding) before the holders of the Notes will be entitled to receive any payment or distribution, in the event of any payment or distribution of the assets or securities of the Company. In addition, until the Senior Indebtedness is paid in full in cash or Cash Equivalents, any payment or distribution to which holders of the Notes would be entitled but for the subordination provisions of the Indenture will be made to holders of the Senior Indebtedness as their interests may appear. If a payment or distribution is made to holders of the Notes that, due to the subordination provisions, should not have been made to them, the holders are required to hold it in trust for the holders of Senior Indebtedness and pay the payment or distribution over to holders of Senior Indebtedness, as their interests may appear.

If payment of the Notes is accelerated because of an event of default under the Indenture, the Company or the Trustee will promptly notify the holders of the Designated Senior Indebtedness or the Representatives of such holders of the acceleration. The Company may not pay the Notes until five business days after such holders or the Representatives of the Designated Senior Indebtedness receives notice of such acceleration and, after that five business day period, may pay the Notes only if the subordination provisions of the Indenture otherwise permit payment at that time.

S-73

Subsidiary guarantees

The Subsidiary Guarantors will, jointly and severally, fully and unconditionally guarantee, on a senior subordinated basis, the Company’s obligations under the Notes and all obligations under the Indenture. The Subsidiary Guarantors will agree to pay, in addition to the amount stated above, any and all costs and expenses (including reasonable counsel fees and expenses) Incurred by the Trustee or the holders in enforcing any rights under the Subsidiary Guarantees.

Each Subsidiary Guarantee will be subordinated to the prior payment in full of all Guarantor Senior Indebtedness in the same manner and to the same extent that the Notes are subordinated to Senior Indebtedness. Each Subsidiary Guarantee will rank equally with all other Guarantor Senior Subordinated Indebtedness of that Subsidiary Guarantor and will be senior in right of payment to all future Guarantor Subordinated Obligations of that Guarantor. The Subsidiary Guarantees will be effectively subordinated to any secured Indebtedness of the applicable Subsidiary Guarantor to the extent of the value of the assets securing such Indebtedness. The Subsidiary Guarantors will not be permitted to Incur indebtedness that is junior in right of payment to Guarantor Senior Indebtedness but senior in right of payment to the Subsidiary Guarantee. Unsecured Indebtedness of the Subsidiary Guarantors is not deemed to be subordinate or junior to secured Indebtedness merely because it is unsecured.

Assuming that we had applied the net proceeds we receive from this offering in the manner described under “Use of proceeds,” as of December 31, 2005, the Subsidiary Guarantors would have had no Guarantor Senior Subordinated Indebtedness other than the Subsidiary Guarantees.

Although the Indenture will limit the amount of indebtedness that Restricted Subsidiaries may Incur, such indebtedness may be substantial and all of it may be Guarantor Senior Indebtedness.

The obligations of each Subsidiary Guarantor under its Subsidiary Guarantee will be limited as necessary to prevent that Subsidiary Guarantee from constituting a fraudulent conveyance or fraudulent transfer under applicable law.

In the event a Subsidiary Guarantor is sold or disposed of (whether by merger, consolidation, the sale of its Capital Stock or the sale of all or substantially all of its assets (other than by lease)) and whether or not the Subsidiary Guarantor is the surviving entity in such transaction to a Person that is not the Company or a Restricted Subsidiary, such Subsidiary Guarantor will be released from its obligations under its Subsidiary Guarantee if:

(1)	the sale or other disposition is in compliance with the Indenture, including the covenants “Limitation on sales of assets and subsidiary stock” and “Limitation on sales of capital stock of restricted subsidiaries;” and
(2)	all of the obligations of the Subsidiary Guarantor under any Credit Facility and related documentation and any other agreements relating to any other Indebtedness of the Company or its Restricted Subsidiaries terminate upon consummation of such transaction.

In addition, a Subsidiary Guarantor will be released from its obligations under the Indenture and its Subsidiary Guarantee if the Company designates the Subsidiary as an Unrestricted Subsidiary and the designation complies with the other applicable provisions of the Indenture.

S-74

Change of control

If a Change of Control occurs, unless the Company has exercised its right to redeem all of the Notes as described under “Optional redemption,” the Company will be required to offer to repurchase from each holder all or any part (equal to $1,000 or an integral multiple thereof) of such holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest, if any, to the date of purchase (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date).

Within 30 days following any Change of Control, unless the Company has exercised its right to redeem the Notes as described under “Optional redemption,” the Company will mail a notice (the “Change of Control Offer”) to each holder, with a copy to the Trustee, stating:

(1)	that a Change of Control has occurred and that the Company is offering to purchase the holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest, if any, to the date of purchase (subject to the right of holders of record at the close of business on a record date to receive interest on the relevant interest payment date) (the “Change of Control Payment”);
(2)	the repurchase date (which shall be no earlier than 30 days nor later than 60 days from the date such notice is mailed) (the “Change of Control Payment Date”); and
(3)	the procedures determined by the Company, consistent with the Indenture, that a holder must follow in order to have its Notes repurchased.

On the Change of Control Payment Date, the Company will, to the extent lawful:

(1)	accept for payment all Notes or portions of Notes (in integral multiples of $1,000) properly tendered pursuant to the Change of Control Offer;
(2)	deposit with the paying agent for the Notes an amount equal to the Change of Control Payment in respect of all Notes or portions of Notes so tendered; and
(3)	deliver or cause to be delivered to the Trustee the Notes so accepted together with an officers’ certificate stating the aggregate principal amount of Notes or portions of Notes being purchased by the Company.

Our paying agent will promptly mail to each holder of Notes so tendered the Change of Control Payment for the Notes, and the Trustee will promptly authenticate and mail (or cause to be transferred by book entry) to each holder a new Note equal in principal amount to any unpurchased portion of the Notes surrendered, if any; provided that each new Note will be in a principal amount of $1,000 or an integral multiple thereof.

If the Change of Control Payment Date is on or after an interest record date and on or before the related interest payment date, any accrued and unpaid interest will be paid to the Person in whose name a Note is registered at the close of business on the record date, and no additional interest will be payable to holders who tender pursuant to the Change of Control Offer.

Prior to mailing a Change of Control Offer:

•  all Senior Indebtedness must be repaid in full and, in the case of revolving Indebtedness, all commitments to lend thereunder have been terminated, or we must offer to repay all Senior Indebtedness and make payment to the holders that accept

S-75

	such offer and obtain waivers of any event of default from the remaining holders of such Senior Indebtedness; or
•	the requisite holders of each issue of Senior Indebtedness must have consented to the Change of Control Offer being made.

Any failure by the Company to effect such repayment or obtain such consent within 30 days following any Change of Control, will constitute a default under the Indenture. A default under the Indenture may result in a cross-default under a Credit Facility. In the event of a default under a Credit Facility, the subordination provisions of the Indenture would likely restrict payments to the holders of the Notes.

The Company will not be required to make a Change of Control Offer upon a Change of Control if a third party makes the Change of Control Offer in the manner, at the times and otherwise in compliance with the requirements set forth in the Indenture applicable to a Change of Control Offer made by the Company and purchases all Notes validly tendered and not withdrawn under the Change of Control Offer.

The Company will comply, to the extent applicable, with the requirements of Section 14(e) of the Exchange Act and any other securities laws or regulations in connection with the repurchase of Notes pursuant to this covenant. To the extent that the provisions of any securities laws or regulations conflict with provisions of the Indenture, the Company will comply with the applicable securities laws and regulations and will be deemed not to have breached its obligations described in the Indenture by virtue of such compliance.

The Company’s ability to repurchase Notes pursuant to a Change of Control Offer may be limited by a number of factors. The occurrence of any of the events that constitute a Change of Control may constitute a default under the Senior Secured Credit Agreement. In addition, certain events that may constitute a change of control under the Senior Secured Credit Agreement and cause a default under that agreement may not constitute a Change of Control under the Indenture. Future Indebtedness of the Company and its Subsidiaries may also contain prohibitions of certain events that would constitute a Change of Control or require such Indebtedness to be repurchased upon a Change of Control. Moreover, the exercise by the holders of their right to require the Company to repurchase the Notes could cause a default under such Indebtedness, even if the Change of Control itself does not, due to the financial effect of such repurchase on the Company. Finally, the Company’s ability to pay cash to the holders upon a repurchase may be limited by the Company’s then existing financial resources. There can be no assurance that sufficient funds will be available when necessary to make any required repurchases.

Even if sufficient funds were otherwise available, the terms of the Senior Secured Credit Agreement may (and other Indebtedness may) prohibit the Company’s prepayment or repurchase of Notes before their scheduled maturity. Consequently, if the Company is not able to prepay the Bank Indebtedness and any other Indebtedness containing similar restrictions or obtain requisite consents, as described above, the Company will be unable to consummate a Change of Control Offer, resulting in a default under the Indenture. A default under the Indenture may result in a cross-default under the Senior Secured Credit Agreement. In the event of a default under the Senior Secured Credit Agreement, the subordination provisions of the Indenture would likely restrict payments to the holders of the Notes.

S-76

The Change of Control provisions described above may deter certain mergers, tender offers and other takeover attempts involving the Company by increasing the capital required to effectuate these transactions.

The definition of “Change of Control” includes a disposition of all or substantially all of the property and assets of the Company and its Restricted Subsidiaries taken as a whole to any Person other than a Permitted Holder. Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve a disposition of “all or substantially all” of the property and assets of a Person. As a result, it may be unclear as to whether a Change of Control has occurred and the Company is obligated to make a Change of Control Offer. The provisions under the Indenture obligating the Company to make a Change of Control Offer may be waived or modified with the written consent of the holders of a majority in principal amount of the Notes.

Certain covenants

Effectiveness of covenants

From and after the first day on which:

(1)	the Notes have an Investment Grade Rating from both of the Ratings Agencies; and
(2)	no Default has occurred and is continuing under the Indenture;

the Company and its Restricted Subsidiaries will cease to be subject to the provisions of the Indenture summarized under the subheadings below:

(1)	“Limitation on indebtedness,”
(2)	“Limitation on restricted payments,”
(3)	“Limitation on restrictions on distributions from restricted subsidiaries,”
(4)	“Limitation on sales of assets and subsidiary stock,”
(5)	“Limitation on affiliate transactions,”
(6)	“Limitation on sale of capital stock of restricted subsidiaries,”
(7)	“Limitation on lines of business,” and
(8)	Clause (4) of “Merger and consolidation”

(collectively, the “Suspended Covenants”). If at any time the credit rating of the Notes is downgraded from an Investment Grade Rating by either Rating Agency, then the Suspended Covenants will thereafter be reinstated and again be applicable pursuant to the terms of the Indenture, unless and until the Notes subsequently attain an Investment Grade Rating. Neither the failure of the Company or any of its Subsidiaries to comply with a Suspended Covenant after the Notes attain an Investment Grade Rating and before any reinstatement of the Suspended Covenants nor compliance by the Company or any of its Subsidiaries with any contractual obligation entered into in compliance with the Indenture during that period will constitute a Default, Event of Default or breach of any kind under the Indenture, the Notes or the Subsidiary Guarantees.

S-77

During any period when the Suspended Covenants are not in effect, the Board of Directors of the Company may not designate any of the Company’s Subsidiaries as Unrestricted Subsidiaries pursuant to the Indenture.

Limitation on indebtedness

The Company may not, and may not permit any of its Restricted Subsidiaries to, Incur any Indebtedness (including Acquired Indebtedness); except, that the Company and any Restricted Subsidiary may Incur Indebtedness if on the date thereof:

(1)	the Consolidated Coverage Ratio for the Company and its Restricted Subsidiaries is at least 2.25 to 1.0; and
(2)	no Default or Event of Default shall have occurred and be continuing or would occur as a consequence of Incurring the Indebtedness or the transactions relating to such Incurrence.

The first paragraph of this covenant will not prohibit the Incurrence of the following Indebtedness:

(1)	Indebtedness of the Company and its Restricted Subsidiaries Incurred pursuant to a Credit Facility in an aggregate principal amount up to the greater of (x) $750 million or (y) 30% of Adjusted Consolidated Net Tangible Assets, in each case, determined as of the date of the Incurrence of the Indebtedness;
(2)	Guarantees of Indebtedness Incurred in accordance with the provisions of the Indenture; provided that if the Indebtedness that is being Guaranteed is Guaranteed by a Subsidiary Guarantor and is (a) Senior Subordinated Indebtedness or Guarantor Senior Subordinated Indebtedness, then the related Guarantee shall rank equally in right of payment to the Subsidiary Guarantee or (b) a Subordinated Obligation or a Guarantor Subordinated Obligation, then the related Guarantee shall be subordinated in right of payment to the Subsidiary Guarantee;
(3)	Indebtedness of the Company owing to and held by any Wholly-Owned Subsidiary or Indebtedness of a Restricted Subsidiary owing to and held by the Company or any Wholly-Owned Subsidiary; provided, however, that:

  (a)  if the Company is the obligor on the Indebtedness, the Indebtedness is subordinated in right of payment to all obligations with respect to the Notes;

  (b)  if a Subsidiary Guarantor is the obligor on the Indebtedness and the Company or a Subsidiary Guarantor is not the obligee, such Indebtedness is subordinated in right of payment to the Subsidiary Guarantees of that Subsidiary Guarantor; and

  (c)  any subsequent issuance or transfer of Capital Stock, sale or other transfer of any such Indebtedness or other event that results in any such Indebtedness being held by a Person other than the Company or a Wholly-Owned Subsidiary of the Company shall be deemed, in each case, to constitute an Incurrence of such Indebtedness by the Company or such Subsidiary, as the case may be, as of the date such Indebtedness first became held by such Person;

  (4)  Indebtedness represented by (a) the Notes issued on the Issue Date, and the Subsidiary Guarantees, (b) any Indebtedness (other than the Indebtedness described in clauses (1), (2), (3), (6), (8), (9) and (10)) outstanding on the Issue Date, and (c) any Refinancing

S-78

	Indebtedness Incurred in respect of any Indebtedness described in this clause (4) or clause (5) or Incurred pursuant to the first paragraph of this covenant;
(5)	Indebtedness of a Restricted Subsidiary Incurred and outstanding on the date on which such Restricted Subsidiary was acquired by the Company (other than Indebtedness Incurred (a) to provide all or any portion of the funds utilized to consummate the transaction or series of related transactions pursuant to which such Restricted Subsidiary was acquired by the Company or (b) otherwise in connection with, or in contemplation of, such acquisition); provided, however, that, at the time such Restricted Subsidiary is acquired by the Company, the Company would have been able to Incur $1.00 of additional Indebtedness pursuant to the first paragraph of this covenant after giving effect to the Incurrence of such Indebtedness;
(6)	Indebtedness under Currency Agreements, Commodity Agreements and Interest Rate Agreements; provided, that, in the case of Currency Agreements or Commodity Agreements, such Currency Agreements or Commodity Agreements are related to business transactions of the Company or its Restricted Subsidiaries entered into in the ordinary course of business and, in the case of Currency Agreements, Commodity Agreements and Interest Rate Agreements, such Currency Agreements, Commodity Agreements and Interest Rate Agreements are entered into for bona fide hedging purposes of the Company or its Restricted Subsidiaries (as determined in good faith by the Board of Directors or senior management of the Company);
(7)	the Incurrence by the Company or any of its Restricted Subsidiaries of Indebtedness represented by Capital Lease Obligations, mortgage financings or purchase money obligations with respect to assets other than Capital Stock or other Investments, in each case Incurred for the purpose of financing all or any part of the purchase price or cost of construction or improvements of property used in the business of the Company or the Restricted Subsidiary, in an aggregate principal amount not to exceed $20 million at any time outstanding;
(8)	Indebtedness Incurred in respect of workers’ compensation claims, self-insurance obligations, bid, reimbursement, performance, surety, appeal and similar bonds, completion guarantees provided by the Company or a Restricted Subsidiary in the ordinary course of business, or required by regulatory authorities in connection with the conduct by the Company and its Restricted Subsidiaries of their businesses, including supporting Guarantees and letters of credit (in each case other than for an obligation for money borrowed);
(9)	Indebtedness arising from agreements of the Company or a Restricted Subsidiary providing for indemnification, adjustment of purchase price or similar obligations, in each case, Incurred or assumed in connection with the disposition of any business, assets or Capital Stock of the Company or a Restricted Subsidiary;

(10)	Indebtedness arising from the honoring by a bank or other financial institution of a check, draft or similar instrument (except in the case of daylight overdrafts) drawn against insufficient funds in the ordinary course of business; provided, however, that such Indebtedness is extinguished within five business days of the Incurrence; and
(11)	in addition to the items referred to in clauses (1) through (10) above, Indebtedness of the Company and its Restricted Subsidiaries in an aggregate outstanding principal amount which, when taken together with the principal amount of all other

S-79

Indebtedness Incurred pursuant to this clause (11) and then outstanding, will not exceed $40 million at any time outstanding.

The Company may not Incur any Indebtedness under the preceding paragraph if the proceeds thereof are used, directly or indirectly, to refinance any Subordinated Obligations of the Company unless such Indebtedness will be subordinated to the Notes to at least the same extent as such Subordinated Obligations. No Subsidiary Guarantor may Incur any indebtedness under the preceding paragraph if the proceeds thereof are used, directly or indirectly, to refinance any Guarantor Subordinated Obligations of such Subsidiary Guarantor unless such Indebtedness will be subordinated to the obligations of such Subsidiary Guarantor under its Subsidiary Guarantee to at least the same extent as such Guarantor Subordinated Obligations. No Subsidiary Guarantor may Incur any Indebtedness if the proceeds thereof are used, directly or indirectly, to refinance any Guarantor Senior Subordinated Indebtedness unless such refinancing Indebtedness is either Guarantor Senior Subordinated Indebtedness or Guarantor Subordinated Obligations. No Restricted Subsidiary may Incur any Indebtedness under the preceding paragraph if the proceeds are used to refinance Indebtedness of the Company other than Senior Indebtedness of the Company or the Notes.

For purposes of determining compliance with, and the outstanding principal amount of any particular Indebtedness Incurred pursuant to and in compliance with, this covenant:

(1)	Indebtedness permitted by this covenant need not be permitted solely by one provision permitting such Indebtedness but may be permitted in part by one such provision and in part by one or more other provisions of this covenant permitting such Indebtedness;
(2)	in the event that Indebtedness meets the criteria of more than one of the provisions permitting the Incurrence of Indebtedness described in the first and second paragraphs above, the Company, in its sole discretion, may classify (or subsequently reclassify) such item of Indebtedness as being permitted by one or more such provisions;
(3)	all Indebtedness outstanding on the date of the Indenture under the Senior Secured Credit Agreement shall be deemed initially Incurred on the Issue Date under clause (1) of the second paragraph above and not the first paragraph or clause (4) of the second paragraph above;
(4)	Guarantees of, or obligations in respect of letters of credit relating to, Indebtedness which is otherwise included in the determination of a particular amount of Indebtedness shall not be included;
(5)	if obligations in respect of letters of credit are Incurred pursuant to a Credit Facility and are being treated as Incurred pursuant to clause (1) of the second paragraph above and the letters of credit relate to other Indebtedness, then such other Indebtedness shall not be included;
(6)	no item of Indebtedness will be given effect more than once in any calculation contemplated by this covenant and no individual item or related items of Indebtedness will be given effect at an aggregate amount in excess of the aggregate amount required to satisfy and discharge the principal amount of such item or related items of Indebtedness;
(7)	the principal amount of any Disqualified Stock of the Company or a Restricted Subsidiary, or Preferred Stock of a Restricted Subsidiary that is not a Subsidiary Guarantor, will be equal to the greater of the maximum mandatory redemption or

S-80

	repurchase price (not including, in either case, any redemption or repurchase premium) or the liquidation preference thereof; and
(8)	the amount of Indebtedness issued at a price that is less than the principal amount thereof will be equal to the amount of the liability in respect thereof determined in accordance with GAAP.

Accrual of interest, accrual of dividends, the accretion of accreted value, the payment of interest in the form of additional Indebtedness and the payment of dividends in the form of additional shares of Preferred Stock or Disqualified Stock will not be deemed to be an Incurrence of Indebtedness for purposes of this covenant. The amount of any Indebtedness outstanding as of any date shall be (i) the accreted value thereof in the case of any Indebtedness issued with original issue discount and (ii) the principal amount or liquidation preference thereof, together with any interest thereon that is more than 30 days past due, in the case of any other Indebtedness.

In addition, the Company will not permit any of its Unrestricted Subsidiaries to Incur any Indebtedness or issue any shares of Disqualified Stock, other than Non-Recourse Debt. If at any time an Unrestricted Subsidiary becomes a Restricted Subsidiary, any Indebtedness of such Subsidiary shall be deemed to be Incurred by a Restricted Subsidiary as of such date (and, if such Indebtedness is not permitted to be Incurred as of such date under this “Limitation on indebtedness” covenant, the Company shall be in Default of this covenant).

For purposes of determining compliance with any U.S. dollar-denominated restriction on the Incurrence of Indebtedness, the U.S. dollar-equivalent principal amount of Indebtedness denominated in a foreign currency will be calculated based on the relevant currency exchange rate in effect on the date the Indebtedness was Incurred, in the case of term Indebtedness, or first committed, in the case of revolving credit Indebtedness; provided that if such Indebtedness is Incurred to refinance other Indebtedness denominated in a foreign currency, and the refinancing would cause the applicable U.S. dollar-dominated restriction to be exceeded if calculated at the relevant currency exchange rate in effect on the date of the refinancing, such U.S. dollar-dominated restriction shall be deemed not to have been exceeded so long as the principal amount of such refinancing Indebtedness does not exceed the principal amount of such Indebtedness being refinanced. Notwithstanding any other provision of this covenant, the maximum amount of Indebtedness that the Company may Incur pursuant to this covenant shall not be deemed to be exceeded solely as a result of fluctuations in the exchange rate of currencies. The principal amount of any Indebtedness Incurred to refinance other Indebtedness, if Incurred in a different currency from the Indebtedness being refinanced, will be calculated based on the currency exchange rate applicable to the currencies in which the Refinancing Indebtedness is denominated that is in effect on the date of such refinancing.

Limitation on layering

The Company will not Incur any Indebtedness if such Indebtedness is subordinate or junior in ranking in any respect to any Senior Indebtedness unless the Indebtedness is Senior Subordinated Indebtedness or is contractually subordinated in right of payment to Senior Subordinated Indebtedness. No Subsidiary Guarantor will Incur any Indebtedness if the Indebtedness is contractually subordinate or junior in ranking in any respect to any Guarantor Senior Indebtedness of the Subsidiary Guarantor unless the Indebtedness is Guarantor Senior Subordinated Indebtedness of the Subsidiary Guarantor or is contractually subordinated in right of payment to Guarantor Senior Subordinated Indebtedness of the Subsidiary Guarantor.

S-81

Limitation on restricted payments

The Company will not, and will not permit any of its Restricted Subsidiaries, directly or indirectly, to:

(1)  pay any dividend or make any distribution on or in respect of its Capital Stock (including any payment in respect of its Capital Stock in connection with any merger or consolidation involving the Company or any of its Restricted Subsidiaries) except:

(a)  dividends or distributions payable in Capital Stock of the Company (other than Disqualified Stock) or in options, warrants or other rights to purchase Capital Stock of the Company; and

(b)  dividends or distributions payable to the Company or a Restricted Subsidiary (and if the Restricted Subsidiary is not a Wholly-Owned Subsidiary, to its other holders of Capital Stock on a pro rata basis);

(2)	purchase, redeem, retire or otherwise acquire for value any Capital Stock of the Company or any direct or indirect parent of the Company held by Persons other than the Company or a Restricted Subsidiary (other than in exchange for Capital Stock of the Company or any direct or indirect parent of the Company (other than Disqualified Stock));
(3)	purchase, repurchase, redeem, defease or otherwise acquire or retire for value, prior to scheduled maturity, scheduled repayment or scheduled sinking fund payment, any Subordinated Obligations or Guarantor Subordinated Obligations (other than the purchase, repurchase, redemption, defeasance or other acquisition or retirement of Subordinated Obligations or Guarantor Subordinated Obligations purchased in anticipation of satisfying a sinking fund obligation, principal installment or final maturity, in each case due within one year of the date of purchase, repurchase, redemption, defeasance or other acquisition or retirement); or
(4)	make any Restricted Investment in any Person;

(any such dividend, distribution, purchase, redemption, repurchase, defeasance, other acquisition, retirement or Restricted Investment referred to in clauses (1) through (4) being referred to herein as a “Restricted Payment”), if at the time the Company or such Restricted Subsidiary makes such Restricted Payment:

(a)  a Default shall have occurred and be continuing (or would result therefrom); or

(b)  the Company is not able to Incur an additional $1.00 of Indebtedness pursuant to the first paragraph under “Limitation on indebtedness” above after giving effect, on a pro forma basis, to the Restricted Payment; or

(c)  the aggregate amount of the Restricted Payment and all other Restricted Payments made subsequent to the Issue Date would exceed the sum of:

 (i)  50% of Consolidated Net Income for the period (treated as one accounting period) from the beginning of the most recent fiscal quarter ended prior to the Issue Date to the end of the most recent fiscal quarter ending prior to the date of such Restricted Payment for which financial statements are in existence (or, in case such Consolidated Net Income is a deficit, minus 100% of such deficit);

S-82

(ii)	100% of the aggregate Net Cash Proceeds received by the Company from the issue or sale of its Capital Stock (other than Disqualified Stock) or other capital contributions subsequent to the Issue Date (other than Net Cash Proceeds received from an issuance or sale of such Capital Stock to a Subsidiary of the Company or an employee stock ownership plan, option plan or similar trust to the extent such sale to an employee stock ownership plan, option plan or similar trust is financed by loans from or Guaranteed by the Company or any Restricted Subsidiary unless such loans have been repaid with cash on or prior to the date of determination);
(iii)	the amount by which Indebtedness of the Company or its Restricted Subsidiaries is reduced on the Company’s balance sheet upon the conversion or exchange (other than by a Subsidiary of the Company) subsequent to the Issue Date of any Indebtedness of the Company or its Restricted Subsidiaries convertible into or exchangeable for Capital Stock (other than Disqualified Stock) of the Company (less the amount of any cash, or the fair market value of any other property, distributed by the Company upon such conversion or exchange); and
(iv)	the amount equal to payments received by the Company or any Restricted Subsidiary in respect of, or the net reduction in, Restricted Investments made by the Company or any of its Restricted Subsidiaries in any Person resulting from:

(A)  repurchases or redemptions of such Restricted Investments by the Person in which such Restricted Investments are made, proceeds realized upon the sale of such Restricted Investment to an unaffiliated purchaser or payments in respect of such Restricted Investment, whether through interest payments, principal payments, dividends, distributions or otherwise, by such Person to the Company or any Restricted Subsidiary; or

(B)  the redesignation of Unrestricted Subsidiaries as Restricted Subsidiaries (valued in each case as provided in the definition of “Investment”) not to exceed, in the case of any Unrestricted Subsidiary, the amount of Investments previously made by the Company or any Restricted Subsidiary in such Unrestricted Subsidiary;

which amount in each case under clause (iv) was included in the calculation of the amount of Restricted Payments; provided, however, that no amount will be included under clause (iv) to the extent it is already included in Consolidated Net Income.

The provisions of the preceding paragraph will not prohibit:

  (1)  any purchase, repurchase, redemption, defeasance or other acquisition or retirement of Capital Stock, Disqualified Stock or Subordinated Obligations or Guarantor Subordinated Obligations made by exchange for, or out of the proceeds of the substantially concurrent sale of, Capital Stock of the Company (other than Disqualified Stock and other than Capital Stock issued or sold to a Subsidiary or an employee stock ownership plan or similar trust to the extent such sale to an employee stock ownership plan or similar trust is financed by loans from or Guaranteed by the Company or any Restricted Subsidiary unless such loans have been repaid with cash on or prior to the date of determination); provided, however, that (a) such purchase, repurchase, redemption, defeasance, acquisition or retirement will be excluded in subsequent calculations of the amount of Restricted Payments and (b) the Net Cash Proceeds from

S-83

	such sale of Capital Stock will be excluded from clause (c)(ii) of the preceding paragraph;
(2)	any purchase, repurchase, redemption, defeasance or other acquisition or retirement of Subordinated Obligations or Guarantor Subordinated Obligations made by exchange for, or out of the proceeds of the substantially concurrent sale of, Subordinated Obligations or any purchase, repurchase, redemption, defeasance or other acquisition or retirement of Guarantor Subordinated Obligations made by exchange for or out of the proceeds of the substantially concurrent sale of Guarantor Subordinated Obligations that, in each case, is permitted to be Incurred as described under “Limitation on indebtedness” and that in each case constitutes Refinancing Indebtedness; provided, however, that such purchase, repurchase, redemption, defeasance, acquisition or retirement will be excluded in subsequent calculations of the amount of Restricted Payments;
(3)	any purchase, repurchase, redemption, defeasance or other acquisition or retirement of Disqualified Stock of the Company or a Restricted Subsidiary made by exchange for or out of the proceeds of the substantially concurrent sale of Disqualified Stock of the Company or such Restricted Subsidiary, as the case may be, that, in each case, is permitted to be Incurred pursuant to the covenant described under “Limitation on indebtedness” and that in each case constitutes Refinancing Indebtedness; provided, however, that such purchase, repurchase, redemption, defeasance, acquisition or retirement will be excluded in subsequent calculations of the amount of Restricted Payments;
(4)	so long as no Default or Event of Default has occurred and is continuing, any purchase or redemption of Subordinated Obligations or Guarantor Subordinated Obligations from Net Available Cash to the extent permitted under “Limitation on sales of assets and subsidiary stock” below; provided, however, that such purchase or redemption will be excluded in subsequent calculations of the amount of Restricted Payments;
(5)	dividends paid within 60 days after the date of declaration if at such date of declaration the dividend would have complied with this provision; provided, however, that such dividends will be included in subsequent calculations of the amount of Restricted Payments;
(6)	so long as no Default or Event of Default has occurred and is continuing,

(a)  the purchase, redemption or other acquisition, cancellation or retirement for value of Capital Stock, or options, warrants, equity appreciation rights or other rights to purchase or acquire Capital Stock of the Company or any Restricted Subsidiary or any direct or indirect parent of the Company held by any existing or former employees or directors of the Company or any Subsidiary of the Company or their assigns, estates or heirs, in each case in accordance with the terms of employee stock option or stock purchase agreements or other agreements to compensate employees or directors; provided that such purchases, redemptions acquisitions, cancellations or retirements pursuant to this clause will not exceed $2.0 million in the aggregate during any calendar year; provided further however, that the amount of any such purchases, redemptions, acquisitions, cancellations or retirements will be included in subsequent calculations of the amount of Restricted Payments; and

S-84

(b)  loans or advances to employees or directors of the Company or any Subsidiary of the Company the proceeds of which are used to purchase Capital Stock of the Company, in an aggregate amount not in excess of $2.0 million at any one time outstanding; provided, however, that the amount of such loans and advances will be included in subsequent calculations of the amount of Restricted Payments;

(7)	so long as no Default or Event of Default has occurred and is continuing, the declaration and payment of dividends to holders of any class or series of Disqualified Stock of the Company issued in accordance with the terms of the Indenture to the extent such dividends are included in the definition of “Consolidated Interest Expense;” provided, however, that the payment of such dividends will be excluded in subsequent calculations of the amount of Restricted Payments;
(8)	repurchases of Capital Stock deemed to occur upon the exercise of stock options, warrants or other convertible securities if such Capital Stock represents a portion of the exercise price thereof; provided, however, that such repurchases will be excluded from subsequent calculations of the amount of Restricted Payments;
(9)	the purchase, repurchase, redemption, defeasance or other acquisition or retirement for value of any Subordinated Obligation (i) at a purchase price not greater than 101% of the principal amount of such Subordinated Obligation in the event of a Change of Control in accordance with provisions similar to the “Change of control” covenant described herein or (ii) at a purchase price not greater than 100% of the principal amount thereof in accordance with provisions similar to the “Limitation on sales of assets and subsidiary stock” covenant described herein; provided that, prior to or simultaneously with such purchase, repurchase, redemption, defeasance or other acquisition or retirement, the Company has made the Change of Control Offer or Asset Disposition Offer, as applicable, as required with respect to the Notes and has completed the repurchase or redemption of all Notes validly tendered for payment in connection with such Change of Control Offer or Asset Disposition Offer; provided, however, that such repurchases will be excluded from subsequent calculations of the amount of Restricted Payments;

(10)	any redemption of share purchase rights at a redemption price not to exceed $0.01 per right; provided, however, that such redemption will be included in subsequent calculations of the amount of Restricted Payments;
(11)	the payment of cash in lieu of fractional shares of Capital Stock in connection with any transaction otherwise permitted under the Indenture; provided, however, that such payment will be included in subsequent calculations of the amount of Restricted Payments;
(12)	payments to dissenting stockholders not to exceed $5 million (x) pursuant to applicable law or (y) in connection with the settlement or other satisfaction of legal claims made pursuant to or in connection with a consolidation, merger or transfer of assets in connection with a transaction that is not prohibited by the Indenture; provided, however, that such payments will be included in subsequent calculations of the amount of Restricted Payments; and
(13)	Restricted Payments in an amount not to exceed $25 million; provided, however, that the amount of the Restricted Payments will be included in subsequent calculations of the amount of Restricted Payments.

S-85

The amount of all Restricted Payments (other than cash) shall be the fair market value on the date of the Restricted Payment of the asset(s) or securities proposed to be paid, transferred or issued by the Company or such Restricted Subsidiary, as the case may be, pursuant to the Restricted Payment. The fair market value of any cash Restricted Payment shall be its face amount and any non-cash Restricted Payment shall be determined conclusively by the Board of Directors of the Company acting in good faith, such determination to be based upon an opinion or appraisal issued by an accounting, appraisal or investment banking firm of national standing if such fair market value is estimated in good faith by the Board of Directors of the Company to exceed $25 million.

Limitation on liens

The Company may not, and may not permit any of its Restricted Subsidiaries to, directly or indirectly, create, Incur or suffer to exist any Lien (other than Permitted Liens) upon any of its property or assets (including Capital Stock of Restricted Subsidiaries), whether owned on the Issue Date or acquired after that date, which Lien secures any Senior Subordinated Indebtedness, or Subordinated Obligations, Guarantor Senior Subordinated Indebtedness or Guarantor Subordinated Obligations, unless contemporaneously with the Incurrence of such Lien effective provision is made to secure the Indebtedness due with respect to the Notes or, with respect to Liens on any Restricted Subsidiary’s property or assets, any Subsidiary Guarantee of such Restricted Subsidiary, equally and ratably with (or prior to in the case of Liens with respect to Subordinated Obligations or Guarantor Subordinated Obligations, as the case may be) the Indebtedness secured by such Lien for so long as such Indebtedness is so secured.

Limitation on restrictions on distributions from restricted subsidiaries

The Company may not, and may not permit any Restricted Subsidiary to, create or otherwise cause or permit to exist or become effective any consensual encumbrance or consensual restriction on the ability of any Restricted Subsidiary to:

(1)	pay dividends or make any other distributions on its Capital Stock or pay any Indebtedness or other obligations owed to the Company or any Restricted Subsidiary (the priority of any Preferred Stock in receiving dividends or liquidating distributions prior to dividends or liquidating distributions being paid on Common Stock and any subordination of any such Indebtedness or other obligations being deemed not to constitute such encumbrances or restrictions);
(2)	make any loans or advances to the Company or any Restricted Subsidiary (the subordination of loans or advances made to the Company or any Restricted Subsidiary to other Indebtedness Incurred by the Company or any Restricted Subsidiary being deemed not to constitute such an encumbrance or restriction); or
(3)	transfer any of its property or assets to the Company or any Restricted Subsidiary.

The preceding provisions will not prohibit:

(a)  any encumbrance or restriction pursuant to an agreement in effect at or entered into on the Issue Date, including, without limitation, the Indenture, the Notes and the Senior Secured Credit Agreement in effect on such date;

(b)  any encumbrance or restriction with respect to a Restricted Subsidiary pursuant to an agreement relating to any Capital Stock or Indebtedness Incurred by a Restricted Subsidiary on or before the date on which the Restricted Subsidiary was acquired by

S-86

the Company (other than Capital Stock or Indebtedness Incurred as consideration in, or to provide all or any portion of the funds utilized to consummate, the transaction or series of related transactions pursuant to which such Restricted Subsidiary became a Restricted Subsidiary or was acquired by the Company or in contemplation of the transaction or transactions) and outstanding on such date provided, that any such encumbrance or restriction shall not extend to any assets or property of the Company or any other Restricted Subsidiary other than the assets and property so acquired;

(c)  any encumbrance or restriction with respect to a Restricted Subsidiary pursuant to an agreement effecting a refunding, replacement or refinancing of Indebtedness Incurred pursuant to an agreement referred to in clause (a) or (b) of this paragraph or this clause (c) or contained in any amendment to an agreement referred to in clause (a) or (b) of this paragraph or this clause (c), including successive refundings, replacements or refinancings; provided, however, that the encumbrances and restrictions with respect to such Restricted Subsidiary contained in any such agreement are no less favorable in any material respect to the holders of the Notes than the encumbrances and restrictions contained in such agreements referred to in clauses (a) or (b) of this paragraph on the Issue Date or the date such Restricted Subsidiary became a Restricted Subsidiary, whichever is applicable;

(d)  in the case of clause (3) of the first paragraph of this covenant, any encumbrance or restriction:

(i)	that restricts in a customary manner the subletting, assignment or transfer of any property or asset that is subject to a lease, license or similar contract, or the assignment or transfer of any such lease, license or other contract;
(ii)	contained in mortgages, pledges or other security agreements permitted under the Indenture securing Indebtedness of the Company or a Restricted Subsidiary to the extent such encumbrances or restrictions restrict the transfer of the property subject to such mortgages, pledges or other security agreements; or
(iii)	pursuant to customary provisions restricting dispositions of real property interests set forth in any reciprocal easement agreements of the Company or any Restricted Subsidiary;

(e)  (i) purchase money obligations for property acquired in the ordinary course of business and (ii) Capital Lease Obligations permitted under the Indenture, in each case, that impose encumbrances or restrictions of the nature described in clause (3) of the first paragraph of this covenant on the property so acquired;

(f)  any restriction with respect to a Restricted Subsidiary (or any of its property or assets) imposed pursuant to an agreement entered into for the direct or indirect sale or disposition of all or substantially all the Capital Stock or assets of such Restricted Subsidiary (or the property or assets that are subject to such restriction) pending the closing of such sale or disposition;

(g)  customary encumbrances or restrictions imposed pursuant to any agreement referred to in the definition of “Permitted Business Investment;”

S-87

(h)  net worth provisions in leases and other agreements entered into by the Company or any Restricted Subsidiary in the ordinary course of business; and

(i)  encumbrances or restrictions arising or existing by reason of applicable law or any applicable rule, regulation or order.

Limitation on sales of assets and subsidiary stock

The Company may not, and may not permit any of its Restricted Subsidiaries to, make any Asset Disposition unless:

(1)

the Company or the Restricted Subsidiary, as the case may be, receives consideration at the time of the Asset Disposition at least equal to the fair market value of the assets subject to the Asset Disposition (determined on the date of contractually agreeing to such Asset Disposition), as determined in good faith by senior management of the Company or, if the consideration with respect to such Asset Disposition exceeds $10 million, the Board of Directors of the Company (including as to the value of all non-cash consideration); and

(2)

at least 75% of the consideration from the Asset Disposition received by the Company or the Restricted Subsidiary, as the case may be, is in the form of cash or Cash Equivalents.

The Company or such Restricted Subsidiary, as the case may be, may elect to apply all or any portion of the Net Available Cash from such Asset Disposition either:

(1)

to prepay, repay, purchase, repurchase, redeem, defease or otherwise acquire or retire Senior Indebtedness of the Company (other than Disqualified Stock or Subordinated Obligations) or Indebtedness of a Wholly-Owned Subsidiary (other than any Disqualified Stock or Guarantor Senior Subordinated Indebtedness or Guarantor Subordinated Obligation of a Wholly-Owned Subsidiary Guarantor) (in each case other than Indebtedness owed to the Company or an Affiliate of the Company) within 365 days from the later of the date of such Asset Disposition or the receipt of such Net Available Cash; provided, however, that, in connection with any prepayment, repayment, purchase, repurchase, redemption, defeasance, or acquisition of Indebtedness pursuant to this clause (1), the Company or such Restricted Subsidiary will retire such Indebtedness and, in the case of revolving Indebtedness, will cause the related commitment (if any) to be permanently reduced in an amount equal to the principal amount so retired; or

(2)

to invest in Additional Assets or make Permitted Business Investments within 365 days from the later of the date of such Asset Disposition or the receipt of such Net Available Cash;

provided, that, pending the final application of any such Net Available Cash in accordance with clauses (1) or (2) above, the Company and its Restricted Subsidiaries may temporarily reduce Indebtedness or otherwise invest such Net Available Cash in any manner not prohibited by the Indenture.

Any Net Available Cash from Asset Dispositions that is not applied or invested as provided in the preceding paragraph will be deemed to constitute “Excess Proceeds.” On the 366th day after an Asset Disposition, if the aggregate amount of Excess Proceeds exceeds $20 million, the Company must make an offer (“Asset Disposition Offer”) to all holders of Notes and to the

S-88

extent required by the terms of other Senior Subordinated Indebtedness, to all holders of other Senior Subordinated Indebtedness outstanding with similar provisions requiring the Company to make an offer to purchase such Senior Subordinated Indebtedness with the proceeds from any Asset Disposition (“Pari Passu Notes”), to purchase the maximum principal amount of Notes and any Pari Passu Notes to which the Asset Disposition Offer applies that may be purchased out of the Excess Proceeds, at an offer price in cash in an amount equal to 100% of the principal amount of the Notes and Pari Passu Notes plus accrued and unpaid interest to the date of purchase, in accordance with the procedures set forth in the Indenture or the agreements governing the Pari Passu Notes, as applicable, in each case in integral multiples of $1,000. To the extent that the aggregate amount of Notes and Pari Passu Notes so validly tendered and not properly withdrawn pursuant to an Asset Disposition Offer is less than the Excess Proceeds, the Company may use any remaining Excess Proceeds for general corporate purposes, subject to the other covenants contained in the Indenture. If the aggregate principal amount of Notes surrendered by holders thereof and other Pari Passu Notes surrendered by holders or lenders, collectively, exceeds the amount of Excess Proceeds, the Trustee shall select the Notes and Pari Passu Notes to be purchased pro rata on the basis of the aggregate principal amount of tendered Notes and Pari Passu Notes. Upon completion of the Asset Disposition Offer, the amount of Excess Proceeds will be reset at zero.

The Asset Disposition Offer must remain open for a period of 20 business days following its commencement, except to the extent that a longer period is required by applicable law (the “Asset Disposition Offer Period”). No later than five Business Days after the termination of the Asset Disposition Offer Period (the “Asset Disposition Purchase Date”), the Company will purchase the principal amount of Notes and Pari Passu Notes required to be purchased pursuant to the Asset Disposition Offer (the “Asset Disposition Offer Amount”) or, if less than the Asset Disposition Offer Amount has been so validly tendered, all Notes and Pari Passu Notes validly tendered in response to the Asset Disposition Offer.

If the Asset Disposition Purchase Date is on or after an interest record date and on or before the related interest payment date, any accrued and unpaid interest will be paid to the Person in whose name a Note is registered at the close of business on such record date, and no additional interest will be payable to holders who tender Notes pursuant to the Asset Disposition Offer.

On or before the Asset Disposition Purchase Date, the Company must, to the extent lawful, accept for payment, on a pro rata basis to the extent necessary, the Asset Disposition Offer Amount of Notes and Pari Passu Notes or portions of Notes and Pari Passu Notes so validly tendered and not properly withdrawn pursuant to the Asset Disposition Offer, or if less than the Asset Disposition Offer Amount has been validly tendered and not properly withdrawn, all Notes and Pari Passu Notes so validly tendered and not properly withdrawn, in each case in integral multiples of $1,000. The Company or the paying agent, as the case may be, must promptly (but in any case not later than five business days after the termination of the Asset Disposition Offer Period) mail or deliver to each tendering holder of Notes or holder or lender of Pari Passu Notes, as the case may be, an amount equal to the purchase price of the Notes or Pari Passu Notes so validly tendered and not properly withdrawn by such holder or lender, as the case may be, and accepted by the Company for purchase, and the Company must promptly issue a new Note, and the Trustee, upon delivery of an officers’ certificate from the Company, must authenticate and mail or deliver such new Note to such holder, in a principal amount equal to any unpurchased portion of the Note surrendered; provided that each such new Note will be in a principal amount of $1,000 or an integral multiple of $1,000. In addition, the

S-89

Company must take any and all other actions required by the agreements governing the Pari Passu Notes. Any Note not so accepted must be promptly mailed or delivered by the Company to the holder thereof. The Company will publicly announce the results of the Asset Disposition Offer on the Asset Disposition Purchase Date.

For the purposes of this covenant, the following will be deemed to be cash:

(1)

the assumption by the transferee of Indebtedness (other than Senior Subordinated Indebtedness, Subordinated Obligations or Disqualified Stock) of the Company or Indebtedness of a Wholly-Owned Subsidiary (other than Guarantor Senior Subordinated Indebtedness, Guarantor Subordinated Obligations or Disqualified Stock of any Wholly-Owned Subsidiary that is a Subsidiary Guarantor) and the release of the Company or the Restricted Subsidiary from all liability on such Indebtedness in connection with the Asset Disposition; and

(2)

securities, notes or other obligations received by the Company or any Restricted Subsidiary from the transferee that are converted by the Company or such Restricted Subsidiary into cash within 60 days after consummation of the Asset Disposition.

The Company may not, and may not permit any Restricted Subsidiary to, engage in any Asset Swaps, unless:

(1)	at the time of entering into the Asset Swap and immediately after giving effect to the Asset Swap, no Default or Event of Default shall have occurred and be continuing or would occur as a consequence thereof;
(2)	in the event the Asset Swap involves the transfer by the Company or any Restricted Subsidiary of assets having an aggregate fair market value, as determined by the Board of Directors of the Company in good faith, in excess of $10 million, the terms of the Asset Swap have been approved by a majority of the members of the Board of Directors of the Company; and
(3)	in the event the Asset Swap involves the transfer by the Company or any Restricted Subsidiary of assets having an aggregate fair market value, as determined by the Board of Directors of the Company in good faith, in excess of $25 million, the Company has received a written opinion from an independent investment banking firm of nationally recognized standing that the Asset Swap is fair to the Company or the Restricted Subsidiary, as the case may be, from a financial point of view.

The Company will comply, to the extent applicable, with the requirements of Section 14(e) of the Exchange Act and any other securities laws or regulations in connection with the repurchase of Notes pursuant to the Indenture. To the extent that the provisions of any securities laws or regulations conflict with provisions of this covenant, the Company will comply with the applicable securities laws and regulations and will be deemed not to have breached its obligations under the Indenture by virtue of such compliance.

Limitation on affiliate transactions

The Company may not, and may not permit any of its Restricted Subsidiaries to, directly or indirectly, enter into or conduct any transaction (including the purchase, sale, lease or

S-90

exchange of any property or the rendering of any service) with any Affiliate of the Company (an “Affiliate Transaction”) unless:

(1)	the terms of the Affiliate Transaction are not materially less favorable to the Company or the Restricted Subsidiary, as the case may be, than those that might reasonably have been obtained in a comparable transaction at the time of such transaction on an arm’s-length basis from a Person that is not an Affiliate of the Company;
(2)	in the event the Affiliate Transaction involves an aggregate consideration in excess of $10 million, the terms of the transaction have been approved by a majority of the members of the Board of Directors of the Company having no personal stake in the transaction, if any (and such majority determines that the Affiliate Transaction satisfies the criteria in clause (1) above); and
(3)	in the event the Affiliate Transaction involves an aggregate consideration in excess of $25 million, the Company has received a written opinion from an independent investment banking, accounting or appraisal firm of nationally recognized standing to the effect that the terms of the Affiliate Transaction is not materially less favorable than those that might reasonably have been obtained in a comparable transaction at the time of such transaction on an arm’s-length basis from a Person that is not an Affiliate of the Company.

The preceding paragraph will not apply to:

(1)	any Restricted Payment (other than a Restricted Investment) permitted to be made pursuant to the covenant described under “Limitation on restricted payments;”
(2)	any issuance of securities, or other payments, awards or grants in cash, securities or otherwise pursuant to, or the funding of, employment agreements and other compensation arrangements, options to purchase Capital Stock of the Company, restricted stock plans, long-term incentive plans, stock appreciation rights plans, participation plans or similar employee plans and/or insurance and indemnification arrangements provided to or for the benefit of employees and directors approved by the Board of Directors of the Company;
(3)	loans or advances to employees, officers or directors in the ordinary course of business of the Company or any of its Restricted Subsidiaries, but in any event not to exceed $2.5 million in the aggregate outstanding at any one time with respect to all loans or advances made since the Issue Date;
(4)	any transaction between the Company and a Restricted Subsidiary or between Restricted Subsidiaries and Guarantees issued by the Company or a Restricted Subsidiary for the benefit of the Company or a Restricted Subsidiary, as the case may be, in accordance with the covenant described under “Limitations on indebtedness;”
(5)	the performance of obligations of the Company or any of its Restricted Subsidiaries under the terms of any agreement to which the Company or any of its Restricted Subsidiaries is a party as of or on the Issue Date, as these agreements may be amended, modified, supplemented, extended or renewed from time to time; provided, however, that any future amendment, modification, supplement, extension or renewal entered into after the Issue Date will be so excluded only if its terms are not more disadvantageous to the holders of the Notes than the terms of the agreements in effect on the Issue Date.

S-91

Limitation on sale of capital stock of restricted subsidiaries

The Company may not, and may not permit any Restricted Subsidiary to, transfer, convey, sell, lease or otherwise dispose of any Capital Stock of any Restricted Subsidiary or to issue any of the Capital Stock of a Restricted Subsidiary (other than, if necessary, shares of its Voting Stock constituting directors’ qualifying shares) to any Person except:

(1)	to the Company or a Wholly-Owned Subsidiary; or
(2)	in compliance with the covenant described under “Limitation on sales of assets and subsidiary stock” and if immediately after giving effect to such issuance or sale, such Restricted Subsidiary would continue to be a Restricted Subsidiary.

Notwithstanding the preceding paragraph, the Company or any Restricted Subsidiary may sell all of the Capital Stock of a Restricted Subsidiary as long as the Company complies with the terms of the covenant described under “Limitation on sales of assets and subsidiary stock.”

SEC reports

Notwithstanding that the Company may not be subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act, the Company will file with the SEC (to the extent the SEC will accept such filing), and make available to the Trustee and the registered holders of the Notes, the annual reports and the information, documents and other reports (or copies of such portions of any of the foregoing as the SEC may by rules and regulations prescribe) that are specified in Sections 13 and 15(d) of the Exchange Act. If the SEC will not accept such filings, the Company will nevertheless make available such Exchange Act information to the Trustee and the holders of the Notes as if the Company were subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act.

If the Company has designated any of its Subsidiaries as Unrestricted Subsidiaries and any such Unrestricted Subsidiary has $10 million of net assets and its assets exceed its liabilities by more than 5% of the amount by which the consolidated assets of the Company and its subsidiaries exceed consolidated liabilities of the Company and its subsidiaries, then the quarterly and annual financial information required by the preceding paragraph shall include a reasonably detailed presentation, either on the face of the financial statements or in the footnotes to the financial statements and in Management’s Discussion and Analysis of Results of Operations and Financial Condition, of the financial condition and results of operations of the Company and its Restricted Subsidiaries.

Merger and consolidation

The Company may not consolidate with or merge with or into any other Person, or transfer all or substantially all its properties and assets to another Person, unless:

(1)

the Company is the continuing or surviving Person in the consolidation or merger; or

(2)

the Person (if other than the Company) formed by the consolidation or into which the Company is merged or to which all or substantially all of the Company’s properties and assets are transferred is a corporation, partnership, limited liability company, business trust, trust or other legal entity organized and validly existing under the laws of the United States, any State thereof, or the District of Columbia, and expressly assumes, by a supplemental indenture, all of the Company’s obligations under the Notes and the Indenture; and

S-92

(3)	immediately after the transaction and the Incurrence or anticipated Incurrence of any Indebtedness to be Incurred in connection therewith, no Event of Default exists; and
(4)	immediately after giving effect to such transaction, the continuing or surviving Person would be able to Incur at least an additional $1.00 of Indebtedness pursuant to the first paragraph of the “Limitation on indebtedness” covenant; and
(5)	each Subsidiary Guarantor shall have by supplemental indenture confirmed that its Subsidiary Guarantee shall apply to such Person’s obligations (if other than the Company) in respect of the Indenture and the Notes shall continue to be in effect;
(6)	an officer’s certificate is delivered to the Trustee to the effect that the conditions set forth above have been satisfied and an opinion of counsel has been delivered to the Trustee to the effect that the conditions set forth above have been satisfied.

For purposes of this covenant, the sale, lease, conveyance, assignment, transfer, or other disposition of all or substantially all of the properties and assets of one or more Subsidiaries of the Company, which properties and assets, if held by the Company instead of its Subsidiaries, would constitute all or substantially all of the properties and assets of the Company on a consolidated basis, shall be deemed to be the transfer of all or substantially all of the properties and assets of the Company.

The continuing, surviving or successor person will succeed to and be substituted for the Company with the same effect as if it had been named in the Indenture as a party thereof, and thereafter the predecessor Person will be relieved of all obligations and covenants under the Indenture and the Notes.

Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve “all or substantially all” of the property or assets of a Person.

Notwithstanding the preceding clauses (3) and (4) above and clause (1)(b) below, (x) any Restricted Subsidiary may consolidate with, merge into or transfer all or part of its properties and assets to the Company or another Restricted Subsidiary and (y) the Company may merge with an Affiliate incorporated solely for the purpose of reincorporating the Company in another jurisdiction; provided that, in the case of a Restricted Subsidiary that merges into the Company, the Company will not be required to comply with clause (5) above.

In addition, the Company may not permit any Subsidiary Guarantor to consolidate with or merge with or into any Person (other than another Subsidiary Guarantor) and may not permit the conveyance, transfer or lease of substantially all of the assets of any Subsidiary Guarantor (other than another Subsidiary Guarantor) unless:

(1)  (a) the Person formed by the consolidation or into which the Subsidiary Guarantor merged or to which all, or substantially all of the Subsidiary Guarantor’s properties and assets are transferred is a corporation, partnership, limited liability company, business trust, trust or other legal entity organized and validly existing under the laws of the United States, any State thereof, or the District of Columbia and such Person (if not such Subsidiary Guarantor) will expressly assume, by supplemental indenture, all the obligations of such Subsidiary Guarantor under its Subsidiary Guarantee; (b) immediately after the transaction and the Incurrence or anticipated Incurrence of any Indebtedness to be Incurred in connection therewith, no Event of Default exists;

S-93

	and (c) the Company will deliver to the Trustee an officers’ certificate and an opinion of counsel, each to the effect that the conditions set forth above have been satisfied; and
(2)	the transaction is made in compliance with the covenant described under “Limitation on sales of assets and subsidiary stock.”

Future subsidiary guarantors

The Company will cause each Restricted Subsidiary (other than a Foreign Subsidiary or a Special Entity) created or acquired by the Company or one or more of its Restricted Subsidiaries after the Issue Date to execute and deliver to the Trustee a Subsidiary Guarantee pursuant to which such Subsidiary Guarantor will unconditionally Guarantee, on a joint and several basis, the full and prompt payment of the principal of, premium, if any and interest on the Notes on a senior subordinated basis.

Limitation on lines of business

The Company may not, and may not permit any Restricted Subsidiary to, engage in any business other than the Oil and Gas Business.

Payments for consent

Neither the Company nor any of its Restricted Subsidiaries will, directly or indirectly, pay or cause to be paid any consideration, whether by way of interest, fees or otherwise, to any holder of any Notes for or as an inducement to any consent, waiver or amendment of any of the terms or provisions of the Indenture or the Notes unless such consideration is offered to be paid or is paid to all holders of the Notes that consent, waive or agree to amend in the time frame set forth in the solicitation documents relating to such consent, waiver or amendment.

Events of default

The following are Events of Default under the Indenture with respect to Notes:

(1)	failure to pay principal of or premium, if any, on any Note when due at its Stated Maturity;
(2)	failure to pay any interest on any Note when due, which failure continues for 30 calendar days;
(3)	failure by the Company or any Subsidiary Guarantor to comply with its obligations under “Certain covenants— Merger and consolidation”;
(4)	failure by the Company to comply with any of its obligations under the provisions described under “Change of control” above or under the covenants described under “Certain covenants” above (in each case, other than a failure to purchase Notes which will constitute an Event of Default under clause (5) below and other than a failure to comply with “Certain covenants— Merger and consolidation” which is covered by clause (3)), which failure or breach continues for 30 calendar days after written notice thereof has been given to the Company as provided in the Indenture;
(5)	failure to redeem or repurchase any Note when required to do so under the terms thereof;

S-94

(6)	failure to perform, or breach of, any other covenant of the Company in the Indenture (other than a covenant included in the Indenture solely for the benefit of a series of debt securities other than the Notes), which failure or breach continues for 60 calendar days after written notice thereof has been given to the Company as provided in the Indenture;
(7)	any nonpayment at maturity or other default (beyond any applicable grace period) under any agreement or instrument relating to any other Indebtedness of the Company or a Significant Subsidiary, the unpaid principal amount of which is not less than $15 million, which default results in the acceleration of the maturity of the Indebtedness prior to its stated maturity or occurs at the final maturity thereof;
(8)	specified events of bankruptcy, insolvency, or reorganization involving the Company or a Significant Subsidiary;
(9)	failure by the Company or any Significant Subsidiary or group of Restricted Subsidiaries that, taken together (as of the latest audited consolidated financial statements for the Company and its Restricted Subsidiaries), would constitute a Significant Subsidiary to pay final judgments aggregating in excess of $15 million (net of any amounts that a reputable and creditworthy insurance company has acknowledged liability for in writing), which judgments are not paid, discharged or stayed for a period of 60 days; or

(10)  any Subsidiary Guarantee of a Significant Subsidiary or group of Subsidiary Guarantors that taken together as of the latest audited consolidated financial statements for the Company and its Restricted Subsidiaries would constitute a Significant Subsidiary ceases to be in full force and effect (except as contemplated by the terms of the Indenture) or is declared null and void in a judicial proceeding or any Subsidiary Guarantor that is a Significant Subsidiary or group of Subsidiary Guarantors that taken together as of the latest audited consolidated financial statements of the Company and its Restricted Subsidiaries would constitute a Significant Subsidiary denies or disaffirms its obligations under the Indenture or its Subsidiary Guarantee.

Pursuant to the Trust Indenture Act, the Trustee is required, within 90 calendar days after the occurrence of a Default in respect of the Notes, to give to the holders of the Notes notice of all uncured Defaults known to it, except that:

•  in the case of a Default in the performance of any covenant of the character contemplated in clause (4) above, no notice will be given until at least 30 calendar days after the occurrence of the Default; and

•  other than in the case of a Default of the character contemplated in clause (1) or (2) above, the Trustee may withhold notice if and so long as it in good faith determines that the withholding of notice is in the interests of the holders of the Notes.

If an Event of Default described in clause (8) above occurs, the principal of, premium, if any, and accrued interest on the Notes will become immediately due and payable without any declaration or other act on the part of the Trustee or any holder of the Notes. If any other Event of Default with respect to Notes occurs and is continuing, either the Trustee or the holders of at least 25% in principal amount of the Notes may declare the principal amount of all Notes to be due and payable immediately. However, at any time after a declaration of acceleration with respect to the Notes has been made, but before a judgment or decree based

S-95

on such acceleration has been obtained, the holders of a majority in principal amount of the Notes may, under specified circumstances, rescind and annul such acceleration.

Subject to the duty of the Trustee to act with the required standard of care during an Event of Default, the Trustee will have no obligation to exercise any of its rights or powers under the Indenture at the request or direction of the holders of the Notes, unless holders of the Notes shall have furnished to the Trustee reasonable security or indemnity. Subject to the provisions of the Indenture, including those requiring security or indemnification of the Trustee, the holders of a majority in principal amount of the Notes will have the right to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee, or exercising any trust or power conferred on the Trustee, with respect to the Notes.

No holder of a Note will have any right to institute any proceeding with respect to the Indenture or for any remedy thereunder unless:

•  the holder has previously given to the Trustee written notice of a continuing Event of Default;

•  the holders of at least 25% in aggregate principal amount of the outstanding Notes have requested the Trustee to institute a proceeding in respect of the Event of Default;

•  the holder or holders have furnished reasonable indemnity to the Trustee to institute the proceeding as Trustee;

•  the Trustee has not received from the holders of a majority in principal amount of the outstanding Notes a direction inconsistent with the request; and

•  the Trustee has failed to institute the proceeding within 60 calendar days.

However, the limitations described above do not apply to a suit instituted by a holder of a Note for enforcement of payment of the principal of and interest on or after the applicable due dates for the payment of such principal and interest.

We are required to furnish to the Trustee annually a statement as to our performance of our obligations under the Indenture and as to any default in our performance.

Modification and waiver

In general, modifications and amendments of the Indenture or the Notes may be made by the Company and the Trustee with the consent of the holders of not less than a majority in principal amount of the Notes. However, no modification or amendment of the Indenture or the Notes may, without the consent of each holder of an outstanding Note affected thereby:

•  reduce the principal amount of, the rate of interest on, or the premium, if any, payable upon the redemption or repurchase of, the Notes;

•  change the Stated Maturity of, or any installment of principal of, or interest on, the Notes;

•  change the time at which any Note may be redeemed or repurchased as described above under “Optional redemption,” “Change of control” or “Certain covenants— Limitation on sales of assets and subsidiary stock”;

•  change the place or currency of payment of principal of, or premium, if any, or interest on the Notes;

S-96

•  impair the right to institute suit for the enforcement of any payment on or with respect to the Notes on or after the Stated Maturity or prepayment date thereof;

•  reduce the percentage in principal amount of the Notes required for modification or amendment of the Indenture or the Notes or for waiver of compliance with certain provisions of the Indenture or the Notes or for waiver of certain defaults; or

•  modify the Subsidiary Guarantees in any manner adverse to the holders of the Notes.

The holders of at least a majority in principal amount of the Notes may, on behalf of the holders of all of the Notes, waive our compliance with specified covenants of the Indenture. The holders of at least a majority in principal amount of the Notes may, on behalf of the holders of all of the Notes, waive any past default under the Indenture with respect to the Notes, except:

•  a default in the payment of the principal of, or premium, if any, or interest on, the Notes; or

•  a default of a provision of the Indenture that cannot be modified or amended without the consent of the each holder of the Notes.

No amendment may be made to the subordination provisions of the Indenture that adversely affects the rights of any holder of Senior Indebtedness then outstanding unless the holders of such Senior Indebtedness (or any group or representative thereof authorized to give a consent) consent to such change. In addition, any amendment to the subordination provisions of the Indenture that adversely affects the rights of any holder of the Notes will require the consent of the holders of at least 66²/3% in aggregate principal amount of the Notes then outstanding.

Defeasance

Upon compliance with the applicable requirements described below, the Company:

(1)	will be deemed to have been discharged from our obligations with respect to the Notes; or
(2)	will be released from its obligations to comply with certain covenants in the Indenture with respect to the Notes, and the occurrence of an event described in any of clauses (3), (4), (7), (9) and (10) under “Events of default” above will no longer be an Event of Default with respect to the Notes

except to the limited extent described below.

Following any defeasance described in clause (1) or (2) above, the Company will continue to have specified obligations under the Indenture, including obligations to register the transfer or exchange of Notes; replace destroyed, stolen, lost, or mutilated debt securities of the applicable series; maintain an office or agency in respect of the Notes; and hold funds for payment to holders of Notes in trust. In the case of any defeasance described in clause (2) above, any failure by the Company to comply with its continuing obligations may constitute an Event of Default with respect to the Notes as described in clause (6) under “Events of default” above.

In order to effect any defeasance described in clause (1) or (2) above, the Company must irrevocably deposit with the Trustee, in trust, money or specified government obligations (or depositary receipts therefor) that through the payment of principal and interest in accordance with their terms will provide money in an amount sufficient to pay all of the principal of,

S-97

premium, if any, and interest on the Notes on the dates such payments are due in accordance with the terms of the Notes. In addition:

•  no Event of Default or event which with the giving of notice or lapse of time, or both, would become an Event of Default under the Indenture shall have occurred and be continuing on the date of such deposit;

•  no Event of Default described in clause (8) under “Events of default” above or event that with the giving of notice or lapse of time, or both, would become an Event of Default described in such clause (8) shall have occurred and be continuing at any time on or prior to the 90th calendar day following the date of deposit;

•  in the event of any defeasance described in clause (1) above, the Company shall have delivered an opinion of counsel, stating that (a) the Company has received from, or there has been published by, the IRS a ruling or (b) there has been a change in applicable federal law, in either case to the effect that, among other things, the holders of the Notes will not recognize gain or loss for United States federal income tax purposes as a result of such deposit or defeasance and will be subject to United States federal income tax in the same manner as if such defeasance had not occurred;

•  in the event of any defeasance described in clause (2) above, the Company shall have delivered an opinion of counsel to the effect that, among other things, the holders of the Notes will not recognize gain or loss for United States federal income tax purposes as a result of such deposit or defeasance and will be subject to United States federal income tax in the same manner as if such defeasance had not occurred;

•  the Company shall have delivered to the Trustee a certificate from a nationally recognized firm of independent accountants or other Person acceptable to the Trustee expressing their opinion that the payments of principal and interest when due and without reinvestment on the deposited U.S. Government Obligations plus any deposited money without investment will provide the case at such times and in such amounts as will be sufficient to pay the principal of and any premium and interest when due on the Notes on the Stated Maturity of the Notes or on any earlier date on which the Notes shall be subject to redemption; and

•  such defeasance must not result in a breach or violation of, or constitute a default under, any other agreement to which the Company is a party.

If the Company fails to comply with its remaining obligations under the Indenture with respect to the Notes following a defeasance described in clause (2) above and the Notes are declared due and payable because of the occurrence of any undefeased Event of Default, the amount of money and government obligations on deposit with the Trustee may be insufficient to pay amounts due on the Notes at the time of the acceleration resulting from such Event of Default. However, the Company will remain liable in respect of such payments.

No personal liability of directors, officers, employees and stockholders

No director, officer, employee, incorporator or stockholder of the Company or any Subsidiary Guarantor, as such, shall have any liability for any obligations of the Company or any Subsidiary Guarantor under the Notes, the Indenture or the Subsidiary Guarantees or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each holder by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities

S-98

under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

Concerning the trustee

JPMorgan Chase Bank, National Association, is the Trustee under the Indenture and has been appointed by the Company as registrar and paying agent with regard to the Notes.

Governing law

The Indenture provides that it and the Notes will be governed by, and construed in accordance with, the laws of the State of New York.

Certain definitions

“Acquired Indebtedness” means Indebtedness (i) of a Person or any of its Subsidiaries existing at the time such Person becomes a Restricted Subsidiary or (ii) assumed in connection with the acquisition of assets from such Person, in each case whether or not Incurred by such Person in connection with, or in anticipation or contemplation of, such Person becoming a Restricted Subsidiary or such acquisition. Acquired Indebtedness shall be deemed to have been Incurred, with respect to clause (i) of the preceding sentence, on the date such Person becomes a Restricted Subsidiary and, with respect to clause (ii) of the preceding sentence, on the date of consummation of such acquisition of assets.

“Additional Assets” means:

(1)	any property or assets (other than Indebtedness and Capital Stock) to be used by the Company or a Restricted Subsidiary in the Oil and Gas Business;
(2)	capital expenditures by the Company or a Restricted Subsidiary in the Oil and Gas Business;
(3)	the Capital Stock of a Person that becomes a Restricted Subsidiary as a result of the acquisition of such Capital Stock by the Company or a Restricted Subsidiary; or
(4)	Capital Stock constituting a minority interest in any Person that at such time is a Restricted Subsidiary;

provided, however, that, in the case of clauses (3) and (4), such Restricted Subsidiary is primarily engaged in the Oil and Gas Business.

“Adjusted Consolidated Net Tangible Assets” means (without duplication), as of the date of determination, the remainder of:

(a)  the sum of:

 (i)  estimated discounted future net revenues from proved oil and gas reserves of the Company and its Restricted Subsidiaries calculated in accordance with SEC guidelines before any provincial, territorial, state, federal or foreign income taxes, as estimated by the Company in a reserve report prepared as of the end of the Company’s most recently completed fiscal year for which audited financial statements are available, as increased by, as of the date of determination, the estimated discounted future net revenues from

S-99

(A)  estimated proved oil and gas reserves acquired since such year end, which reserves were not reflected in such year end reserve report, and

(B)

estimated oil and gas reserves attributable to upward revisions of estimates of proved oil and gas reserves since such year end due to exploration, development, exploitation or other activities, in each case calculated in accordance with SEC guidelines (utilizing the prices for the fiscal quarter ending prior to the date of determination), and decreased by, as of the date of determination, the estimated discounted future net revenues from development, exploitation or other activities, in each case calculated in accordance with SEC guidelines (utilizing the prices for the fiscal quarter ending prior to the date of determination), and decreased by, as of the date of determination, the estimated discounted future net revenues from

(C)

estimated proved oil and gas reserves included therein that shall have been produced or disposed of since such year end, and

(D)  estimated oil and gas reserves included therein that are subsequently removed from the proved oil and gas reserves of the Company and its Restricted Subsidiaries as so calculated due to downward revisions of estimates of proved oil and gas reserves since such year end due to changes in geological conditions or other factors which would, in accordance with standard industry practice, cause such revisions, in each case calculated on a pre-tax basis and substantially in accordance with SEC guidelines (utilizing the prices for the fiscal quarter ending prior to the date of determination), in each case as estimated by the Company’s petroleum engineers or any independent petroleum engineers engaged by the Company for that purpose;

(ii)	the capitalized costs that are attributable to oil and gas properties of the Company and its Restricted Subsidiaries to which no proved oil and gas reserves are attributable, based on the Company’s books and records as of a date no earlier than the date of the Company’s latest available consolidated annual or quarterly financial statements;
(iii)	the Net Working Capital on a date no earlier than the date of the Company’s latest annual or quarterly consolidated financial statements; and

(iv)  the greater of

(A)  the net book value of other tangible assets of the Company and its Restricted Subsidiaries, as of a date no earlier than the date of the Company’s latest annual or quarterly consolidated financial statement, and

(B)  the appraised value, as estimated by independent appraisers, of other tangible assets of the Company and its Restricted Subsidiaries, as of a date no earlier than the date of the Company’s latest audited financial statements (provided that the Company shall not be required to obtain any appraisal of any assets); minus

(b)  the sum of:

 (i)  any amount included in (a)(i) through (a)(iv) above that is attributable to Minority Interests;

S-100

(ii)	any net gas balancing liabilities of the Company and its Restricted Subsidiaries reflected in the Company’s latest audited consolidated financial statements;
(iii)	to the extent included in (a)(i) above, the estimated discounted future net revenues, calculated in accordance with SEC guidelines (utilizing the prices utilized in the Company’s year end reserve report), attributable to reserves which are required to be delivered to third parties to fully satisfy the obligations of the Company and its Restricted Subsidiaries with respect to Volumetric Production Payments (determined, if applicable, using the schedules specified with respect thereto); and
(iv)	to the extent included in (a)(i) above, the estimated discounted future net revenues, calculated in accordance with SEC guidelines, attributable to reserves subject to Dollar-Denominated Production Payments which, based on the estimates of production and price assumptions included in determining the estimated discounted future net revenues specified in (a)(i) above, would be necessary to fully satisfy the payment obligations of the Company and its Restricted Subsidiaries with respect to Dollar-Denominated Production Payments (determined, if applicable, using the schedules specified with respect thereto).

If the Company changes its method of accounting from the full cost method of accounting to the successful efforts or a similar method, “Adjusted Consolidated Net Tangible Assets” will continue to be calculated as if the Company were still using the full cost method of accounting.

“Affiliate” of any specified Person means any other Person, that directly or indirectly, is in Control of, is Controlled by, or is under common Control with, such Person.

“Asset Disposition” means any direct or indirect sale, lease (other than an operating lease entered into in the ordinary course of the Oil and Gas Business), transfer, issuance or other disposition, or a series of related sales, leases, transfers, issuances or dispositions that are part of a common plan, of shares of Capital Stock of a Subsidiary (other than directors’ qualifying shares), property or other assets (each referred to for the purposes of this definition as a “disposition”) by the Company or any of its Restricted Subsidiaries, including any disposition by means of a merger, consolidation or similar transaction.

Notwithstanding the preceding, the following items shall not be deemed to be Asset Dispositions:

(1)	a disposition by a Restricted Subsidiary to the Company or by the Company or a Restricted Subsidiary to a Wholly-Owned Subsidiary;
(2)	the sale of Cash Equivalents in the ordinary course of business;
(3)	a disposition of Hydrocarbons or mineral products in the ordinary course of the Oil and Gas Business;
(4)	a disposition of obsolete or worn out equipment or equipment that is no longer useful in the conduct of the business of the Company and its Restricted Subsidiaries and that is disposed of in each case in the ordinary course of business;
(5)	transactions permitted by the covenant described under “Certain covenants— Merger and consolidation;”

S-101

(6)	an issuance of Capital Stock by a Restricted Subsidiary to the Company or to a Wholly-Owned Subsidiary;
(7)	for purposes of the covenant described under “Certain covenants— Limitation on sales of assets and subsidiary stock” only, the making of a Permitted Investment or a disposition subject to the covenant described under “Certain covenants— Limitation on restricted payments;”
(8)	an Asset Swap effected in compliance with the covenant described under “Certain covenants— Limitation on sales of assets and subsidiary stock;”
(9)	dispositions of assets with an aggregate fair market value since the Issue Date of less than $5 million;

(10)	dispositions in connection with the creation, Incumbrance or existence of Permitted Liens or the exercise of any rights or remedies with respect thereof;
(11)	dispositions of receivables in connection with the compromise, settlement or collection thereof in the ordinary course of business or in bankruptcy or similar proceedings and exclusive of factoring or similar arrangements;
(12)	the licensing or sublicensing of intellectual property or other general intangibles and licenses, leases or subleases of other property in the ordinary course of business and which do not materially interfere with the business of the Company and its Restricted Subsidiaries;
(13)	any Production Payments and Reserve Sales, provided that any such Production Payments and Reserve Sales, other than incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologists, geophysicists and other providers of technical services to the Company or a Restricted Subsidiary, shall have been created, Incurred, issued, assumed or Guaranteed in connection with the acquisition or financing of, and no later than 60 days after the acquisition of, the property that is subject thereto;
(14)	the sale or transfer (whether or not in the ordinary course of the Oil and Gas Business) of oil and/or gas properties or direct or indirect interests in real property; provided, that at the time of such sale or transfer such properties do not have associated with them any proved reserves capable of being produced in material economic quantities; and
(15)	the abandonment, farm-out, exchange, lease or sublease of developed or undeveloped oil and/or gas properties or interests therein in the ordinary course of business or in exchange for oil and/or gas properties or interests therein owned or held by another Person.

“Asset Swap” means concurrent purchase and sale or exchange of oil and gas properties or interests therein or other assets or properties used or useful in the Oil and Gas Business, including Capital Stock of any Person who holds any such properties, interests or assets, between the Company or any of its Restricted Subsidiaries and another Person; provided that any cash received must be applied in accordance with “Limitation on sales of assets and subsidiary stock.”

“Attributable Indebtedness” in respect of a Sale/ Leaseback Transaction means, as at the time of determination, the present value (discounted at the interest rate borne by the Notes,

S-102

compounded semi-annually) of the total obligations of the lessee for rental payments during the remaining term of the lease included in such Sale/ Leaseback Transaction (including any period for which such lease has been extended).

“Average Life” means, as of the date of determination, with respect to any Indebtedness or Preferred Stock, the quotient obtained by dividing (1) the sum of the products of the numbers of years from the date of determination to the dates of each successive scheduled principal payment of such Indebtedness or redemption or similar payment with respect to such Preferred Stock multiplied by the amount of such payment by (2) the sum of all such payments.

“Bank Indebtedness” means any and all amounts, whether outstanding on the Issue Date or Incurred after the Issue Date, payable by the Company under or in respect of a Credit Facility, including the Senior Secured Credit Agreement, and any related notes, collateral documents, letters of credit and guarantees and any Interest Rate Agreement entered into in connection with the Credit Facility, including principal, premium, if any, interest (including interest accruing on or after the filing of any petition in bankruptcy or for reorganization relating to the Company at the rate specified therein, whether or not a claim for post-filing interest is allowed in such proceedings), fees, charges, expenses, reimbursement obligations, guarantees and all other amounts payable thereunder or in respect thereof.

“Board of Directors” means, as to any Person, the board of directors of such Person or a duly authorized committee of such board of directors.

“Capital Lease” means, with respect to any Person, any lease of property (whether real, personal, or mixed) by such Person or its Subsidiaries as lessee that would be capitalized on a balance sheet of such Person or its Subsidiaries prepared in conformity with GAAP, other than, in the case of such Person or its Subsidiaries, any such lease under which such Person or any of its Subsidiaries is the lessor.

“Capital Lease Obligations” means, with respect to any Person, the capitalized amount of all obligations of such Person and its Subsidiaries under Capital Leases, as determined on a consolidated basis in conformity with GAAP.

“Capital Stock” of any Person means any and all shares, interests, rights to purchase, warrants, options, participation or other equivalents of or interests in (however designated) equity of such Person, including any Preferred Stock, but excluding any debt securities convertible into such equity.

“Cash Equivalents” means:

(1)

securities issued or directly and fully guaranteed or insured by the United States Government or any agency or instrumentality of the United States (provided that the full faith and credit of the United States is pledged in support thereof), having a maturity within one year after the date of acquisition thereof;

(2)

marketable general obligations issued by any state of the United States of America or any political subdivision of any such state or any public instrumentality thereof maturing within one year after the date of acquisition thereof and, at the time of such acquisition, having a credit rating of at least “A” or the equivalent thereof from either Standard & Poor’s Ratings Services or Moody’s Investors Service, Inc. (or an equivalent rating by another nationally recognized rating agency if both of the two named rating agencies cease publishing ratings of investments);

S-103

(3)	certificates of deposit, time deposits, eurodollar time deposits, overnight bank deposits or bankers’ acceptances having maturities of not more than one year after the date of acquisition thereof issued by any commercial bank the long-term debt of which is rated at the time of acquisition at least “A” or the equivalent thereof by Standard & Poor’s Ratings Services, or “A” or the equivalent thereof by Moody’s Investors Service, Inc. (or an equivalent rating by another nationally recognized rating agency if both of the two named rating agencies cease publishing ratings of investments), and having combined capital and surplus in excess of $500 million;
(4)	repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (1), (2) and (3) entered into with any bank meeting the qualifications specified in clause (3) above;
(5)	commercial paper rated at the time of acquisition thereof at least “A-2” or the equivalent thereof by Standard & Poor’s Ratings Services or “P-2” or the equivalent thereof by Moody’s Investors Service, Inc. (or an equivalent rating by another nationally recognized rating agency if both of the two named rating agencies cease publishing ratings of investments), and in any case maturing within one year after the date of acquisition thereof; and
(6)	interests in any investment company or money market fund which invests 95% or more of its assets in instruments of the type specified in clauses (1) through (5) above.

“Change of Control” means:

(1)	Any “person” or “group” of related persons (as such terms are used in Sections 13(d) and 14(d) of the Exchange Act), other than one or more Permitted Holders, is or becomes the beneficial owner (as defined in Rules 13d-3 and 13d-5 under the Exchange Act, except that such person or group shall be deemed to have “beneficial ownership” of all shares that such person or group has the right to acquire, whether such right is exercisable immediately or only after the passage of time), directly or indirectly, of more than 50% of the total voting power of the Voting Stock of the Company (or its successor by merger, consolidation or purchase of all or substantially all of its assets) (for the purposes of this clause, such person or group shall be deemed to beneficially own any Voting Stock of the Company held by a parent entity of the Company, if such person or group “beneficially owns” (as defined above), directly or indirectly, more than 50% of the voting power of the Voting Stock of such parent entity); or
(2)	the first day on which a majority of the members of the Board of Directors of the Company are not Continuing Directors; or
(3)	the sale, lease, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the assets of the Company and its Restricted Subsidiaries taken as a whole to any “person” (as such term is used in Sections 13(d) and 14(d) of the Exchange Act) other than a Permitted Holder; or
(4)	the adoption by the stockholders of the Company of a plan or proposal for the liquidation or dissolution of the Company.

“Commodity Agreements” means, in respect of any Person, any futures contract, forward contract, commodity swap agreement, commodity option agreement or other similar agree-

S-104

ment or arrangement in respect of Hydrocarbons purchased, used, produced, processed or sold by such Person and designed to protect such Person against fluctuations in Hydrocarbon prices.

“Common Stock” means with respect to any Person, any and all shares, interests or other participations in, and other equivalents (however designated and whether voting or nonvoting) of such Person’s common stock whether or not outstanding on the Issue Date, and includes, without limitation, all series and classes of such common stock.

“Consolidated Coverage Ratio” means as of any date of determination, the ratio of (x) the aggregate amount of Consolidated EBITDA for the period of the most recent four consecutive fiscal quarters ending prior to the date of such determination for which consolidated financial statements of the Company are in existence to (y) Consolidated Interest Expense for such four fiscal quarters; provided, however, that:

(1)  if the Company or any Restricted Subsidiary:

(a)  has Incurred any Indebtedness since the beginning of such period that remains outstanding on such date of determination or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio is an Incurrence of Indebtedness, Consolidated EBITDA and Consolidated Interest Expense for such period will be calculated after giving effect on a pro forma basis to such Indebtedness as if such Indebtedness had been Incurred on the first day of such period (except that in making such computation, the amount of Indebtedness under any revolving credit facility outstanding on the date of such calculation will be deemed to be (i) the average daily balance of such Indebtedness during such four fiscal quarters or such shorter period for which such facility was outstanding or (ii) if such facility was created after the end of such four fiscal quarters, the average daily balance of such Indebtedness during the period from the date of creation of such facility to the date of such calculation) and the discharge of any other Indebtedness repaid, repurchased, defeased or otherwise discharged with the proceeds of such new Indebtedness as if such discharge had occurred on the first day of such period; or

(b)  has repaid, repurchased, defeased or otherwise discharged any Indebtedness since the beginning of the period that is no longer outstanding on such date of determination or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio involves a discharge of Indebtedness (in each case other than Indebtedness Incurred under any revolving credit facility unless such Indebtedness has been permanently repaid and the related commitment terminated), Consolidated EBITDA and Consolidated Interest Expense for such period will be calculated after giving effect on a pro forma basis to such discharge of such Indebtedness, including with the proceeds of such new Indebtedness, as if such discharge had occurred on the first day of such period;

(2)  if since the beginning of such period the Company or any Restricted Subsidiary shall have made any Asset Disposition or the transaction giving rise to the need to calculate the Consolidated Coverage Ratio is such an Asset Disposition:

(a)  the Consolidated EBITDA for such period will be reduced by an amount equal to the Consolidated EBITDA (if positive) directly attributable to the assets which are the subject of such Asset Disposition for such period or increased by an amount equal to the absolute value of the Consolidated EBITDA (if negative) directly attributable thereto for such period; and

S-105

(b)  Consolidated Interest Expense for such period will be reduced by an amount equal to the Consolidated Interest Expense directly attributable to any Indebtedness of the Company or any Restricted Subsidiary repaid, repurchased, defeased or otherwise discharged with respect to the Company and its continuing Restricted Subsidiaries in connection with such Asset Disposition for such period (or, if the Capital Stock of any Restricted Subsidiary is sold, the Consolidated Interest Expense for such period directly attributable to the Indebtedness of such Restricted Subsidiary to the extent the Company and its continuing Restricted Subsidiaries are no longer liable for such Indebtedness after such sale);

(3)

if since the beginning of such period the Company or any Restricted Subsidiary (by merger or otherwise) shall have made an Investment in any Restricted Subsidiary (or any Person which becomes a Restricted Subsidiary or is merged with or into the Company) or an acquisition of assets, including any acquisition of assets occurring in connection with a transaction giving rise to the need to calculate the Consolidated Coverage Ratio, which constitutes all or substantially all of a company, division, operating unit, segment, business, group of related assets or line of business, Consolidated EBITDA and Consolidated Interest Expense for such period will be calculated after giving pro forma effect thereto (including the Incurrence of any Indebtedness) as if such Investment or acquisition occurred on the first day of such period; and

(4)

if since the beginning of such period any Person that subsequently became a Restricted Subsidiary or was merged with or into the Company or any Restricted Subsidiary since the beginning of such period shall have Incurred any Indebtedness or discharged any Indebtedness, made any Asset Disposition or any Investment or acquisition of assets that would have required an adjustment pursuant to clause (2) or (3) above if made by the Company or a Restricted Subsidiary during such period, Consolidated EBITDA and Consolidated Interest Expense for such period will be calculated after giving pro forma effect thereto as if such Asset Disposition or Investment or acquisition of assets occurred on the first day of such period.

For purposes of this definition, whenever pro forma effect is to be given to any calculation under this definition, the pro forma calculations will be determined in good faith by a responsible financial or accounting officer of the Company (including pro forma expense and cost reductions calculated on a basis consistent with Regulation S-X under the Securities Act). If any Indebtedness bears a floating rate of interest and is being given pro forma effect, the interest expense on such Indebtedness will be calculated as if the rate in effect on the date of determination had been the applicable rate for the entire period (taking into account any Interest Rate Agreement applicable to such Indebtedness if such Interest Rate Agreement has a remaining term in excess of 12 months). If any Indebtedness that is being given pro forma effect bears an interest rate at the option of the Company, the interest rate shall be calculated by applying such optional rate chosen by the Company.

“Consolidated EBITDA” for any period means, without duplication, the Consolidated Net Income for such period, plus the following to the extent deducted in calculating such Consolidated Net Income:

(1)	Consolidated Interest Expense;
(2)	Consolidated Income Taxes;
(3)	consolidated depletion, depreciation and amortization expenses;

S-106

(4)	consolidated impairment charges recorded in connection with the application of Financial Accounting Standard No. 142 “Goodwill and Other Intangibles;”
(5)	consolidated exploration expenses, if applicable;
(6)	(a) any write-off of deferred financing costs, (b) any capitalized interest, and (c) the interest portion of any deferred payment obligations; and
(7)	other consolidated non-cash charges reducing Consolidated Net Income (excluding any such non-cash charge to the extent it represents an accrual of or reserve for cash charges in any future period or amortization of a prepaid cash expense that was paid in a prior period not included in the calculation);

less, to the extent included in calculating such Consolidated Net Income and in excess of any costs or expenses attributable thereto that were deducted in calculating such Consolidated Net Income, the sum of (x) the amount of deferred revenues that are amortized during such period and are attributable to reserves that are subject to Volumetric Production Payments, and (y) amounts recorded in accordance with GAAP as repayments of principal and interest pursuant to Dollar-Denominated Production Payments.

Notwithstanding the preceding sentence, the items described in clauses (2) through (6) relating to amounts of a Restricted Subsidiary of a Person will be added to Consolidated Net Income to compute Consolidated EBITDA of such Person only to the extent (and in the same proportion) that the net income (loss) of such Restricted Subsidiary was included in calculating the Consolidated Net Income of such Person and, to the extent the amounts set forth in clauses (2) through (6) are in excess of those necessary to offset a net loss of such Restricted Subsidiary or if such Restricted Subsidiary has net income for such period included in Consolidated Net Income, only if a corresponding amount would not be prohibited at the date of determination to be dividended to the Company by such Restricted Subsidiary pursuant to the terms of its charter and all agreements, instruments, judgments, decrees, orders, statutes, rules and governmental regulations applicable to that Restricted Subsidiary or its stockholders, except for restrictions under any Credit Facility.

“Consolidated Income Taxes” means, with respect to any Person for any period, taxes imposed upon such Person or other payments required to be made by such Person by any governmental authority which taxes or other payments are (x) calculated by reference to the income or profits of such Person or such Person and its Subsidiaries, or (y) any franchise taxes or equity taxes (in each case to the extent included in computing Consolidated Net Income for such period), regardless of whether such taxes or payments are required to be remitted to any governmental authority.

“Consolidated Interest Expense” means, for any period, the consolidated interest expense of the Company and its consolidated Restricted Subsidiaries, whether paid or accrued, plus, to the extent not included in such interest expense:

(1)	interest expense attributable to Capital Lease Obligations and the interest portion of rent expense associated with Attributable Indebtedness in respect of the relevant lease giving rise thereto, determined as if such lease were a Capital Lease in accordance with GAAP and the interest component of any deferred payment obligations;
(2)	amortization of debt discount and debt issuance cost (provided that any amortization of bond premium will be credited to reduce Consolidated Interest Expense unless,

S-107

	pursuant to GAAP, such amortization of bond premium has otherwise reduced Consolidated Interest Expense);
(3)	non-cash interest expense;
(4)	commissions, discounts and other fees and charges owed with respect to letters of credit and bankers’ acceptance financing;
(5)	the interest expense on Indebtedness of another Person that is Guaranteed by such Person or one of its Restricted Subsidiaries or secured by a Lien on assets of such Person or one of its Restricted Subsidiaries;
(6)	costs associated with Hedging Obligations (including amortization of fees) provided, however, that if Hedging Obligations result in net benefits rather than costs, such net benefits shall be credited to reduce Consolidated Interest Expense unless, pursuant to GAAP, such net benefits are otherwise reflected in Consolidated Net Income;
(7)	the consolidated interest expense of such Person and its Restricted Subsidiaries that was capitalized during such period;
(8)	the product of (a) all dividends paid or payable, in cash, Cash Equivalents or Indebtedness or accrued during such period on any series of Disqualified Stock of such Person or on Preferred Stock of its Restricted Subsidiaries payable to a party other than the Company or a Wholly-Owned Subsidiary, times (b) a fraction, the numerator of which is one and the denominator of which is one minus the then current combined federal, state, provincial and local statutory tax rate of such Person, expressed as a decimal, in each case, on a consolidated basis and in accordance with GAAP;
(9)	Receivables Fees; and

(10)  the cash contributions to any employee stock ownership plan or similar trust to the extent such contributions are used by such plan or trust to pay interest or fees to any Person (other than the Company) in connection with Indebtedness Incurred by such plan or trust.

For the purpose of calculating the Consolidated Coverage Ratio in connection with the Incurrence of any Indebtedness described in the final paragraph of the definition of “Indebtedness,” the calculation of Consolidated Interest Expense shall include all interest expense (including any amounts described in clauses (1) through (10) above) relating to any Indebtedness of the Company or any Restricted Subsidiary described in the final paragraph of the definition of “Indebtedness.”

For purposes of the foregoing, total interest expense will be determined (i) after giving effect to any net payments made or received by the Company and its Subsidiaries with respect to Interest Rate Agreements and (ii) exclusive of amounts classified as other comprehensive income in the balance sheet of the Company. Notwithstanding anything to the contrary contained herein, commissions, discounts, yield and other fees and charges Incurred in connection with any transaction pursuant to which the Company or its Restricted Subsidiaries may sell, convey or otherwise transfer or grant a security interest in any accounts receivable or related assets shall be included in Consolidated Interest Expense.

S-108

“Consolidated Net Income” means, for any period, the net consolidated income (loss) of the Company and its consolidated Restricted Subsidiaries determined in accordance with GAAP; provided, however, that there will not be included in such Consolidated Net Income:

(1)  any net income (loss) of any Person (other than the Company) if such Person is not a Restricted Subsidiary, except that:

(a)  subject to the limitations contained in clauses (3), (4) and (5) below, the Company’s equity in the net income of any such Person for such period will be included in such Consolidated Net Income up to the aggregate amount of cash actually distributed by such Person during such period to the Company or a Restricted Subsidiary as a dividend or other distribution (subject, in the case of a dividend or other distribution to a Restricted Subsidiary, to the limitations contained in clause (2) below); and

(b)  the Company’s equity in a net loss of any such Person (other than an Unrestricted Subsidiary) for such period will be included in determining such Consolidated Net Income to the extent such loss has been funded with cash from the Company or a Restricted Subsidiary;

(2)  any net income (but not loss) of any Restricted Subsidiary if such Subsidiary is subject to restrictions, directly or indirectly, on the payment of dividends or the making of distributions by such Restricted Subsidiary, directly or indirectly, to the Company, except that:

(a)  subject to the limitations contained in clauses (3), (4) and (5) below, the Company’s equity in the net income of any such Restricted Subsidiary for such period will be included in such Consolidated Net Income up to the aggregate amount of cash that could have been distributed by such Restricted Subsidiary during such period to the Company or another Restricted Subsidiary as a dividend (subject, in the case of a dividend to another Restricted Subsidiary, to the limitation contained in this clause; provided, however, that the net income of a Special Entity that does not Guarantee the Notes will not be included in such Consolidated Net Income except for the amount of cash actually distributed by such Special Entity during such period to the Company or a Restricted Subsidiary as a dividend or other distribution (subject, in the case of a dividend or other distribution to a Restricted Subsidiary, to the limitation contained in this clause); and

(b)  the Company’s equity in a net loss of any such Restricted Subsidiary for such period will be included in determining such Consolidated Net Income;

(3)	any after tax gain (loss) realized upon the sale or other disposition of any property, plant or equipment of the Company or its consolidated Restricted Subsidiaries (including pursuant to any Sale/ Leaseback Transaction) which is not sold or otherwise disposed of in the ordinary course of business and any gain (loss) realized upon the sale or other disposition of any Capital Stock of any Person;
(4)	any after tax extraordinary gain or loss;
(5)	the cumulative effect of a change in accounting principles;
(6)	any asset impairment writedowns on Oil and Gas Properties under GAAP or SEC guidelines; and

S-109

(7)  any unrealized non-cash gains or losses on charges in respect of Hedging Obligations (including those resulting from the application of SFAS 133).

“Continuing Directors” means the individuals who, as of the Issue Date, are directors of the Company and any individual becoming a director of the Company subsequent to the Issue Date whose election, nomination for election by the Company’s stockholders or appointment, was approved by a majority of the then Continuing Directors (either by a specific vote or by approval of the proxy statement of the Company in which such individual is named as a nominee for election as a director, without objection to such nomination).

“Control” of a Person means the power to direct the management and policies of such Person, directly or indirectly, whether through the ownership of voting securities, by contract or otherwise; and the terms “Controlling” and “Controlled” have meanings correlative of the foregoing.

“Credit Facility” means, with respect to the Company or any Subsidiary Guarantor, one or more credit facilities (including, without limitation, the Senior Secured Credit Agreement) or commercial paper facilities with banks or other institutional lenders providing for revolving credit loans, term loans, receivables financing (including through the sale of receivables to such lenders or to special purpose entities formed to borrow from such lenders against such receivables) or letters of credit, in each case, as amended, restated, modified, renewed, refunded, replaced or refinanced in whole or in part from time to time (including successive amendments, restatements, modifications, renewals, refunds, replacements or refinancings and whether or not with the original administrative agent and lenders or another administrative agent or agents or other lenders and whether provided under the original Senior Secured Credit Agreement or any other credit or other agreement or indenture).

“Currency Agreement” means in respect of a Person any foreign exchange contract, currency swap agreement, futures contract, option contract or other similar agreement as to which such Person is a party or a beneficiary.

“Default” means any event which, with notice or passage of time or both, would constitute an Event of Default.

“Designated Senior Indebtedness” means (1) the Bank Indebtedness (to the extent such Bank Indebtedness constitutes Senior Indebtedness), including the Senior Secured Credit Agreement, and (2) any other Senior Indebtedness which, at the date of determination, has an aggregate principal amount outstanding of, or under which, at the date of determination, the holders thereof are committed to lend up to, at least $25 million and is specifically designated in the instrument evidencing or governing such Senior Indebtedness as “Designated Senior Indebtedness” for purposes of the Indenture.

“Disqualified Stock” means, with respect to any Person, any Capital Stock of such Person which by its terms (or by the terms of any security into which it is convertible or for which it is exchangeable) or upon the happening of any event:

(1)	matures or is mandatorily redeemable pursuant to a sinking fund obligation or otherwise;
(2)	is convertible or exchangeable for Indebtedness or Disqualified Stock (excluding Capital Stock which is convertible or exchangeable solely at the option of the Company or a Restricted Subsidiary); or
(3)	is redeemable at the option of the holder of the Capital Stock in whole or in part,

S-110

in each case on or prior to the date that is 91 days after the earlier of the date (a) of the Stated Maturity of the Notes or (b) the first date after the Issue Date on which there are no Notes outstanding, provided that only the portion of Capital Stock which so matures or is mandatorily redeemable, is so convertible or exchangeable or is so redeemable at the option of the holder thereof prior to such date will be deemed to be Disqualified Stock; provided, further that any Capital Stock that would constitute Disqualified Stock solely because the holders thereof have the right to require the Company to repurchase such Capital Stock upon the occurrence of a change of control or asset disposition (each defined in a substantially identical manner to the corresponding definitions in the Indenture) shall not constitute Disqualified Stock if the terms of such Capital Stock (and all such securities into which it is convertible or for which it is ratable or exchangeable) provide that the Company may not repurchase or redeem any such Capital Stock (and all such securities into which it is convertible or for which it is ratable or exchangeable) pursuant to such provision prior to compliance by the Company with the provisions of the Indenture described under the captions “Change of control” and “Limitation on sales of assets and subsidiary stock” and such repurchase or redemption complies with “Certain covenants— Restricted payments.”

“Dollar-Denominated Production Payments” means production payment obligations recorded as liabilities in accordance with GAAP, together with all undertakings and obligations in connection therewith.

“Domestic Subsidiary” means any Restricted Subsidiary that is organized under the laws of the United States of America or any state thereof or the District of Columbia.

“Foreign Subsidiary” means any Restricted Subsidiary that is not organized under the laws of the United States of America or any state thereof or the District of Columbia and any Subsidiary of such Restricted Subsidiary.

“GAAP” means generally accepted accounting principles in the United States of America as in effect as of the date of the Indenture, including those set forth in the opinions and pronouncements of the Accounting Principles Board of the American Institute of Certified Public Accountants and statements and pronouncements of the Financial Accounting Standards Board or in such other statements by such other entity as approved by a significant segment of the accounting profession. All ratios and computations based on GAAP contained in the Indenture will be computed in conformity with GAAP.

“Guarantee” means any obligation, contingent or otherwise, of any Person directly or indirectly guaranteeing any Indebtedness of any other Person and any obligation, direct or indirect, contingent or otherwise, of such Person:

(1)	to purchase or pay (or advance or supply funds for the purchase or payment of) such Indebtedness of such other Person (whether arising by virtue of partnership arrangements, or by agreement to keep-well, to purchase assets, goods, securities or services, to take-or-pay, or to maintain financial statement conditions or otherwise); or
(2)	entered into for purposes of assuring in any other manner the obligee of such Indebtedness of the payment thereof or to protect such obligee against loss in respect thereof (in whole or in part);

provided, however, that the term “Guarantee” will not include endorsements for collection or deposit in the ordinary course of business. The term “Guarantee” used as a verb has a corresponding meaning.

S-111

“Guarantor Senior Indebtedness” means, with respect to a Subsidiary Guarantor, the following obligations, whether outstanding on the Issue Date or thereafter issued, without duplication:

(1)

any Guarantee of the Bank Indebtedness by such Subsidiary Guarantor and all other Guarantees by such Subsidiary Guarantor of Senior Indebtedness of the Company or Guarantor Senior Indebtedness of any other Subsidiary Guarantor; and

(2)

all obligations consisting of principal of and premium, if any, accrued and unpaid interest on, and fees and other amounts relating to, all other Indebtedness of the Subsidiary Guarantor. Guarantor Senior Indebtedness includes interest accruing on or after the filing of any petition in bankruptcy or for reorganization relating to the Subsidiary Guarantor regardless of whether post-filing interest is allowed in such proceeding.

Notwithstanding anything to the contrary in the preceding paragraph, Guarantor Senior Indebtedness will not include:

(1)	any Indebtedness Incurred in violation of the Indenture;
(2)	any obligations of such Subsidiary Guarantor to the Company or another Subsidiary;
(3)	any liability for federal, state, local, foreign or other taxes owed or owing by such Subsidiary Guarantor;
(4)	any accounts payable or other liability to trade creditors arising in the ordinary course of business (including Guarantees thereof or instruments evidencing such liabilities);
(5)	any Indebtedness, Guarantee or obligation of such Subsidiary Guarantor that is expressly subordinate or junior in right of payment to any other Indebtedness, Guarantee or obligation of such Subsidiary Guarantor, including, without limitation, any Guarantor Senior Subordinated Indebtedness and Guarantor Subordinated Obligations of such Guarantor; or
(6)	any Capital Stock.

“Guarantor Senior Subordinated Indebtedness” means, with respect to a Subsidiary Guarantor, the obligations of such Subsidiary Guarantor under the Subsidiary Guarantee and any other Indebtedness of such Subsidiary Guarantor (whether outstanding on the Issue Date or thereafter Incurred) that specifically provides that such Indebtedness is to rank equally in right of payment with the obligations of such Subsidiary Guarantor under the Subsidiary Guarantee and is not expressly subordinated by its terms in right of payment to any Indebtedness of such Subsidiary Guarantor which is not Guarantor Senior Indebtedness of such Subsidiary Guarantor.

“Guarantor Subordinated Obligation” means, with respect to a Subsidiary Guarantor, any Indebtedness of such Subsidiary Guarantor (whether outstanding on the Issue Date or thereafter Incurred) which is expressly subordinate in right of payment to the obligations of such Subsidiary Guarantor under its Subsidiary Guarantee pursuant to a written agreement.

“Hedging Obligations” of any Person means the obligations of such Person pursuant to any Interest Rate Agreement or Currency Agreement or Commodity Agreement.

“Holder” means a Person in whose name a Note is registered in the Security Register Registrar’s books.

“Hydrocarbons” means oil, gas, casinghead gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons, and all products, by-products and all

S-112

other substances refined, separated, settled or derived therefrom or the processing thereof, and all other minerals and substances, including, but not limited to, liquified petroleum gas, natural gas, kerosene, sulphur, lignite, coal, uranium, thorium, iron, geothermal steam, water, carbon dioxide, helium, and any and all other minerals, ores, or substances of value, and the products and proceeds therefrom, including, without limitation, all gas resulting from the in-situ combustion of coal or lignite.

“Incur” means issue, create, assume, Guarantee, incur or otherwise become liable for; provided, however, that any Indebtedness or Capital Stock of a Person existing at the time such person becomes a Restricted Subsidiary (whether by merger, consolidation, acquisition or otherwise) will be deemed to be Incurred by such Restricted Subsidiary at the time it becomes a Restricted Subsidiary; and the terms “Incurred” and “Incurrence” have meanings correlative to the foregoing.

“Indebtedness” means, as applied to any Person, without duplication:

(1)	all obligations of such Person for borrowed money;
(2)	all obligations of such Person for the deferred purchase price of property or services (other than property and services purchased, and expense accruals and deferred compensation items arising, in the ordinary course of business);
(3)	all obligations of such Person evidenced by notes, bonds, debentures, mandatorily redeemable preferred stock or other similar instruments (other than performance, surety and appeals bonds arising in the ordinary course of business);
(4)	all payment obligations created or arising under any conditional sale, deferred price or other title retention agreement with respect to property acquired by such Person (unless the rights and remedies of the seller or lender under such agreement in the event of default are limited to repossession or sale of such property);
(5)	any Capital Lease Obligation of such Person, other than obligations under oil and gas leases entered into in the ordinary course of business;
(6)	all reimbursement, payment or similar obligations, contingent or otherwise, of such Person under acceptance, letter of credit or similar facilities (other than letters of credit in support of trade obligations or incurred in connection with public liability insurance, workers’ compensation, unemployment insurance, old-age pensions and other social security benefits other than in respect of employee benefit plans subject to ERISA);
(7)	all obligations of such Person, contingent or otherwise, under any guarantee by such Person of the obligations of another Person of the type referred to in clauses (1) through (6) above; and
(8)	the principal component or liquidation preference of all obligations of such Person with respect to the redemption, repayment or other repurchase of any Disqualified Stock or, with respect to any Subsidiary that is not a Subsidiary Guarantor, any Preferred Stock (but excluding, in each case, any accrued dividends);
(9)	to the extent not otherwise included in this definition, net obligations of such Person under Commodity Agreements, Currency Agreements and Interest Rate Agreements (the amount of any such obligations to be equal at any time to the termination value

S-113

of such agreement or arrangement giving rise to such obligation that would be payable by such Person at such time); and

(10)  all obligations referred to in clauses (1) through (6) above secured by (or for which the holder of such Indebtedness has an existing right, contingent or otherwise, to be secured by) any mortgage or security interest in property (including without limitation accounts, contract rights and general intangibles) owned by such Person and as to which such Person has not assumed or become liable for the payment of such obligations other than to the extent of the property subject to such mortgage or security interest;

except that Indebtedness of the type referred to in clauses (7) and (10) above will be included within the definition of “Indebtedness” only to the extent of the least of (a) the amount of the underlying Indebtedness referred to in the applicable clause (1) through (6) above; (b) in the case of clause (7), the limit on recoveries, if any, from such Person under obligations of the type referred to in clause (7) above, and (c) in the case of clause (10), the aggregate value (as determined in good faith by the board of directors or similar governing body of such Person) of the property of such Person subject to such mortgage or security interest.

In addition, “Indebtedness” of any Person shall include Indebtedness described in the preceding paragraph that would not appear as a liability on the balance sheet of such Person if:

(1)	such Indebtedness is the obligation of a partnership or joint venture that is not a Restricted Subsidiary (a “Joint Venture”);
(2)	such Person or a Restricted Subsidiary of such Person is a general partner of the Joint Venture (a “General Partner”); and
(3)	there is recourse, by contract or operation of law, with respect to the payment of such Indebtedness to property or assets of such Person or a Restricted Subsidiary of such Person;

in which case, such Indebtedness shall be included in an amount not to exceed:

(a)  the lesser of (i) the net assets of the General Partner and (ii) the amount of such obligations to the extent that there is recourse, by contract or operation of law, to the property or assets of such Person or a Restricted Subsidiary of such Person; or

(b)  if less than the amount determined pursuant to clause (a) immediately above, the actual amount of such Indebtedness that is recourse to such Person or a Restricted Subsidiary of such Person, if the Indebtedness is evidenced by a writing and is for a determinable amount.

“Interest Rate Agreement” means with respect to any Person any interest rate protection agreement, interest rate futures contracts, interest rate option agreement, interest rate swap agreement, interest rate cap agreement, interest rate collar agreement, interest rate hedge agreement or other similar agreement or arrangement as to which such Person is party or a beneficiary.

“Investment” means, with respect to any Person, all investments by such Person in other Persons (including Affiliates) in the form of any direct or indirect advance, loan (other than advances or extensions of credit to employees, directors or customers in the ordinary course of business) or other extensions of credit (including by way of Guarantee or similar arrangement, but excluding any debt or extension of credit represented by a bank deposit other than a time

S-114

deposit) or capital contribution to (by means of any transfer of cash or other property or any payment for property or services), or any purchase or acquisition of Capital Stock, Indebtedness or other similar instruments issued by, such Person and all other items that are or would be classified as investments on a balance sheet prepared in accordance with GAAP; provided that none of the following will be deemed to be an Investment:

(1)	Hedging Obligations Incurred in the ordinary course of business and in compliance with the Indenture;
(2)	endorsements of negotiable instruments and documents in the ordinary course of business; and
(3)	an acquisition of assets, Capital Stock or other securities by the Company or a Subsidiary for consideration to the extent such consideration consists of Common Stock of the Company.

For purposes of “Certain covenants— Limitation on restricted payments,”

(1)

“Investment” will include the portion (proportionate to the Company’s equity interest in a Restricted Subsidiary to be designated as an Unrestricted Subsidiary) of the fair market value of the net assets of such Restricted Subsidiary at the time that such Restricted Subsidiary is designated an Unrestricted Subsidiary; provided, however, that upon a redesignation of such Subsidiary as a Restricted Subsidiary, the Company will be deemed to continue to have a permanent “Investment” in an Unrestricted Subsidiary in an amount (if positive) equal to (a) the Company’s “Investment” in such Subsidiary at the time of such redesignation less (b) the portion (proportionate to the Company’s equity interest in such Subsidiary) of the fair market value of the net assets (as conclusively determined by the Board of Directors of the Company in good faith) of such Subsidiary at the time that such Subsidiary is so re-designated a Restricted Subsidiary; and

(2)

any property transferred to or from an Unrestricted Subsidiary will be valued at its fair market value at the time of such transfer, in each case as determined in good faith by the Board of Directors of the Company.

“Investment Grade Rating” means a rating equal to or higher than Baa3 (or the equivalent) by Moody’s Investors Service, Inc. and BBB- (or the equivalent) by Standard & Poor’s Ratings Services (or an equivalent rating by another nationally recognized rating agency if both of the two named rating agencies cease publishing ratings of investments), in each case, with a stable or better outlook.

“Issue Date” means                     , 2006.

“Lien” means any mortgage, pledge, security interest, encumbrance, lien or similar charge of any kind (including any conditional sale or other title retention agreement or lease in the nature thereof).

“Minority Interest” means the percentage interest represented by any shares of stock of any class of Capital Stock of a Restricted Subsidiary that are not owned by the Company or a Restricted Subsidiary.

“Net Available Cash” from an Asset Disposition means cash payments received (including any cash payments received by way of deferred payment of principal pursuant to a note or installment receivable or otherwise and net proceeds from the sale or other disposition of any

S-115

securities received as consideration, but only as and when received, but excluding any other consideration received in the form of assumption by the acquiring person of Indebtedness or other obligations relating to the properties or assets that are the subject of such Asset Disposition or received in any other non-cash form) therefrom, in each case net of:

(1)	all legal, accounting, investment banking, title and recording tax expenses, commissions and other fees and expenses Incurred, and all Federal, state, provincial, foreign and local taxes required to be paid or accrued as a liability under GAAP (after taking into account any available tax credits or deductions and any tax sharing agreements), as a consequence of such Asset Disposition;
(2)	all payments made on any Indebtedness which is secured by any assets subject to such Asset Disposition, in accordance with the terms of any Lien upon such assets, or which must by its terms, or in order to obtain a necessary consent to such Asset Disposition, or by applicable law be repaid out of the proceeds from such Asset Disposition;
(3)	all distributions and other payments required to be made to minority interest holders in Subsidiaries or joint ventures as a result of such Asset Disposition; and
(4)	amounts accrued in accordance with GAAP in respect of liabilities associated with the assets disposed of in such Asset Disposition and retained by the Company or any Restricted Subsidiary after such Asset Disposition or liabilities incurred in connection with such Asset Disposition.

“Net Cash Proceeds,” with respect to any issuance or sale of Capital Stock, means the cash proceeds of such issuance or sale net of attorneys’ fees, accountants’ fees, underwriters’ or placement agents’ fees, listing fees, discounts or commissions and brokerage, consultant and other fees and charges actually Incurred in connection with such issuance or sale and net of taxes paid or payable as a result of such issuance or sale (after taking into account any available tax credit or deductions and any tax sharing arrangements).

“Net Working Capital” means (a) all current assets of the Company and its Restricted Subsidiaries except current assets under Commodity Agreements, less (b) all current liabilities of the Company and its Restricted Subsidiaries, except current liabilities included in Indebtedness and any current liabilities under Commodity Agreements, in each case as set forth in the consolidated financial statements of the Company prepared in accordance with GAAP.

“Non-Recourse Debt” means Indebtedness of a Person:

(1)	as to which neither the Company nor any Restricted Subsidiary (a) provides any Guarantee or credit support of any kind (including any undertaking, guarantee, indemnity, agreement or instrument that would constitute Indebtedness) or (b) is directly or indirectly liable (as a guarantor or otherwise);
(2)	no default with respect to which (including any rights that the holders thereof may have to take enforcement action against an Unrestricted Subsidiary) would permit (upon notice, lapse of time or both) any holder of any other Indebtedness of the Company or any Restricted Subsidiary to declare a default under such other Indebtedness or cause the payment thereof to be accelerated or payable prior to its stated maturity; and
(3)	the explicit terms of which provide there is no recourse against any of the assets of the Company or its Restricted Subsidiaries.

S-116

“Oil and Gas Business” means (a) the business of acquiring, exploring, exploiting, developing, producing, operating and disposing of interests in oil, gas, liquid natural gas and other hydrocarbon properties, (b) the business of gathering, marketing, treating, processing, storing, refining, selling and transporting any production from such interests or properties and products produced therefrom or in association therewith, (c) any business or activity relating to, arising from, or necessary, appropriate or incidental to the activities described in the foregoing clauses (a) and (b) of this definition.

“Oil and Gas Properties” means all properties, including equity or other ownership interests therein, owned by such Person which contain or are believed to contain “proved oil and gas reserves” as defined in Rule 4-10 of Regulation S-X of the Securities Act.

“Opinion of Counsel” means a written opinion from legal counsel who is acceptable to the Trustee. The counsel may be an employee of or counsel to the Company or the Trustee.

“Pari Passu Indebtedness” means Indebtedness that ranks equally in right of payment to the Notes.

“Permitted Business Investment” means any Investment made in the ordinary course of the business of the Company or any Restricted Subsidiary or that is of a kind or character that is customarily made in the conduct of the Oil and Gas Business, including investments or expenditures for actively exploiting, exploring for, acquiring, developing, producing, processing, refining, gathering, marketing or transporting Hydrocarbons through agreements, transactions, interests or arrangements which permit one to share risks or costs, comply with regulatory requirements regarding local ownership or satisfy other objectives customarily achieved through the conduct of the Oil and Gas Business jointly with third parties, including:

(1)

ownership interests in oil and gas properties, liquid natural gas facilities, refineries, drilling operations, processing facilities, gathering systems, pipelines or ancillary real property interests; and

(2)

Investments in the form of or pursuant to oil and gas leases, operating agreements, gathering agreements, processing agreements, farm-in agreements, farm-out agreements, development agreements, area of mutual interest agreements, unitization or pooling designations, declarations, orders and agreements, gas balancing or deferred production agreements, joint bidding agreements, service contracts, joint venture agreements, partnership agreements (whether general or limited), subscription agreements, stock purchase agreements and other similar agreements (including for limited liability companies) with third parties.

“Permitted Holders” means the following:

(1)	the Company or any Subsidiary of the Company;
(2)	a trustee or other fiduciary holding securities under any employee benefit plan (or related trust) sponsored or maintained by the Company or any Subsidiary of the Company; and
(3)	Mercury Exploration Company, Quicksilver Energy, L.P., The Discovery Fund, Pennsylvania Avenue Limited Partnership, Pennsylvania Management Company, the estate of Frank Darden, Lucy Darden, Anne Darden Self, Glenn Darden or Thomas Darden, and their respective successors, assigns, designees, heirs, beneficiaries, trusts, estates or Controlled affiliates.

S-117

“Permitted Investment” means an Investment by the Company or any Restricted Subsidiary in:

(1)	a Restricted Subsidiary (other than a Special Entity that does not Guarantee the Notes) or a Person which will, upon the making of such Investment, become a Restricted Subsidiary (other than a Special Entity that does not Guarantee the Notes); provided, however, that the primary business of such Restricted Subsidiary is the Oil and Gas Business;
(2)	another Person if as a result of such Investment such other Person is merged or consolidated with or into, or transfers or conveys all or substantially all its assets to, the Company or a Restricted Subsidiary; provided, however, that such Person’s primary business is the Oil and Gas Business;
(3)	cash and Cash Equivalents;
(4)	receivables owing to the Company or any Restricted Subsidiary created or acquired in the ordinary course of the Oil and Gas Business and payable or dischargeable in accordance with customary trade terms; provided, however, that such trade terms may include such concessionary trade terms as the Company or any such Restricted Subsidiary deems reasonable under the circumstances;
(5)	payroll, travel and similar advances to cover matters that are expected at the time of such advances ultimately to be treated as expenses for accounting purposes and that are made in the ordinary course of business;
(6)	loans or advances to employees and directors made in the ordinary course of business of the Company or such Restricted Subsidiary;
(7)	Capital Stock, obligations or securities received in settlement of debts created in the ordinary course of business and owing to the Company or any Restricted Subsidiary or in satisfaction of judgments or pursuant to any plan of reorganization or similar arrangement upon the bankruptcy or insolvency of a debtor;
(8)	Investments made as a result of the receipt of non-cash consideration from an Asset Disposition that was made pursuant to and in compliance with “Certain covenants— Limitation on sales of assets and subsidiary stock;”
(9)	Investments in existence on the Issue Date or made pursuant to agreements or commitments in effect on the Issue Date;

(10)	Commodity Agreements, Currency Agreements, Interest Rate Agreements and related Hedging Obligations, which transactions or obligations are Incurred in compliance with “Certain covenants— Limitation on indebtedness;”
(11)	Investments by the Company or any of its Restricted Subsidiaries, together with all other Investments pursuant to this clause (11), in an aggregate amount at the time of such Investment not to exceed $10 million outstanding at any one time (with the fair market value of such Investment being measured at the time made and without giving effect to subsequent changes in value);
(12)	Guarantees made in accordance with “Certain covenants— Limitations on indebtedness;”
(13)	Investments in a Special Entity that does not Guarantee the Notes in an aggregate amount not to exceed 10% of Adjusted Consolidated Net Tangible Assets (with

S-118

	Adjusted Consolidated Net Tangible Assets and the fair market value of such Investment being measured at the time such Investment is made and without giving effect to subsequent changes in value);
(14)	Permitted Business Investments in an aggregate amount not to exceed 5% of Adjusted Consolidated Net Tangible Assets (with Adjusted Consolidated Net Tangible Assets and the fair market value of such Investment being measured at the time such Investment is made and without giving effect to subsequent changes in value); and
(15)	any Asset Swap made in accordance with “Certain covenants— Limitation on asset swaps.”

In order to be a Permitted Investment, an Investment need not be permitted solely by one subsection of this definition but may be permitted in part of one such subsection and in part by one or more other subsections of this definition. In the event an Investment meets the criteria of one or more of the subsections of this definition, the Company, in its sole discretion, may classify (or subsequently reclassify) all or any portion of such Investment as being permitted by any one or more of such subsections.

“Permitted Liens” means, with respect to any Person:

(1)	Liens securing Indebtedness and other obligations under a Credit Facility, including the Senior Secured Credit Agreement and related Hedging Obligations and other Senior Indebtedness and liens on assets of Restricted Subsidiaries securing Guarantees of Indebtedness and other obligations of the Company under a Credit Facility and other Guarantor Senior Indebtedness permitted to be Incurred under the Indenture under the covenants described in clause (1) of the second paragraph under “Certain covenants— Limitation on indebtedness;”
(2)	pledges or deposits by such Person under workmen’s compensation laws, unemployment insurance laws or similar legislation, or earnest money, good faith or similar deposits in connection with bids, tenders, contracts (other than for the payment of Indebtedness) or leases to which such Person is a party, or deposits to secure public, regulatory or statutory obligations of such Person or deposits of cash or Cash Equivalents to secure surety or appeal bonds to which such Person is a party, or deposits as security for contested taxes or import or customs duties or for the payment of rent, in each case Incurred in the ordinary course of business;
(3)	Liens imposed by law, including carriers’, warehousemen’s, suppliers’, materialmen’s and mechanics’ Liens, in each case for sums not yet due or being contested in good faith by appropriate proceedings if appropriate reserves or other provisions required by GAAP, if any, shall have been made in respect thereof;
(4)	Liens for taxes, assessments or other governmental charges not yet subject to penalties for non-payment or which are being contested in good faith by appropriate proceedings if appropriate reserves or other provisions required by GAAP shall have been made in respect thereof;
(5)	Liens in favor of issuers of surety or performance bonds or letters of credit or bankers’ acceptances issued pursuant to the request of and for the account of such Person in the ordinary course of its business; provided, however, that such letters of credit do not constitute Indebtedness;

S-119

(6)	encumbrances, easements or reservations of, or rights of others for, licenses, rights of way, servitudes, permits, sewers, electric lines, telegraph and telephone lines and other similar purposes, or zoning, building codes or surface leases and other similar rights in respect of surface operations or other restrictions (including, without limitation, minor defects or irregularities in title and similar encumbrances) as to the use of real properties or liens incidental to the conduct of the business of such Person or to the ownership of its properties which do not in the aggregate materially adversely affect the value of said properties or materially impair their use in the operation of the business of such Person;
(7)	Liens securing Hedging Obligations;
(8)	leases, licenses, subleases and sublicenses of assets (including, without limitation, real property and intellectual property rights) which do not materially interfere with the ordinary conduct of the business of the Company or any of its Restricted Subsidiaries;
(9)	judgment Liens not giving rise to an Event of Default so long as such Lien is adequately bonded and any appropriate legal proceedings which may have been duly initiated for the review of such judgment have not been finally terminated or the period within which such proceedings may be initiated has not expired;

(10)  Liens for the purpose of securing the payment of all or a part of the purchase price of, or Capital Lease Obligations, purchase money obligations or other payments Incurred to finance the acquisition, improvement or construction of, assets or property acquired or constructed in the ordinary course of business; provided that:

(a)  the aggregate principal amount of Indebtedness secured by such Liens is otherwise permitted to be Incurred under the Indenture and does not exceed the cost of the assets or property so acquired or constructed; and

(b)  such Liens are created within 180 days of construction or acquisition of such assets or property and do not encumber any other assets or property of the Company or any Restricted Subsidiary other than such assets or property and assets affixed or appurtenant thereto;

(11)  Liens arising solely by virtue of any statutory or common law provisions relating to banker’s Liens, rights of set-off or similar rights and remedies as to deposit accounts or other funds maintained with a depositary institution; provided that:

(a)  such deposit account is not a dedicated cash collateral account and is not subject to restrictions against access by the Company in excess of those set forth by regulations promulgated by the Federal Reserve Board; and

(b)  such deposit account is not intended by the Company or any Restricted Subsidiary to provide collateral to the depository institution;

(12)	Liens arising from Uniform Commercial Code financing statement filings regarding operating leases entered into by the Company and its Restricted Subsidiaries in the ordinary course of business;
(13)	Liens existing on the Issue Date;
(14)	Liens on property or shares of stock of a Person at the time such Person becomes a Restricted Subsidiary; provided, however, that such Liens are not created, Incurred or assumed in connection with, or in contemplation of, such other Person becoming a

S-120

	Restricted Subsidiary; provided further, however, that any such Lien may not extend to any other property owned by the Company or any Restricted Subsidiary;
(15)	Liens on property at the time the Company or a Restricted Subsidiary acquired the property, including any acquisition by means of a merger or consolidation with or into the Company or any Restricted Subsidiary; provided, however, that such Liens are not created, Incurred or assumed in connection with, or in contemplation of, such acquisition; provided further, however, that such Liens may not extend to any other property owned by the Company or any Restricted Subsidiary;
(16)	Liens securing Indebtedness or other obligations of a Restricted Subsidiary owing to the Company or a Wholly-Owned Subsidiary;
(17)	Liens securing the Notes and Subsidiary Guarantees;
(18)	Liens securing Refinancing Indebtedness Incurred to refinance Indebtedness that was previously so secured, provided that any such Lien is limited to all or part of the same property or assets (plus improvements, accessions, proceeds or dividends or distributions in respect thereof) that secured (or, under the written arrangements under which the original Lien arose, could secure) the Indebtedness being refinanced or is in respect of property that is the security for a Permitted Lien hereunder;
(19)	any interest or title of a lessor under any Capital Lease Obligation or operating lease;
(20)	Liens in respect of Production Payments and Reserve Sales, which Liens shall be limited to the oil and gas property or other interest that is subject to such Production Payments and Reserve Sales;
(21)	Liens arising under oil and gas leases, farm-out agreements, farm-in agreements, division orders, contracts for the sale, purchase, exchange, transportation, gathering or processing of Hydrocarbons, partnership agreements, joint venture agreements, unitizations and pooling designations, declarations, orders and agreements, development agreements, operating agreements, production sales contracts, area of mutual interest agreements, gas balancing or deferred production agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or geophysical permits or agreements, and other agreements which are customary in the Oil and Gas Business; provided, however, in all instances that such Liens are limited to the assets that are subject to the relevant agreement, program, order or contract;
(22)	Liens on pipelines or pipeline facilities that arise by operation of law; and
(23)	Liens securing Indebtedness (other than Subordinated Obligations and Guarantor Subordinated Obligations) in an aggregate principal amount outstanding at any one time not to exceed $10 million.

“Person” means any individual, partnership, corporation, limited liability company, joint stock company, business trust, trust, unincorporated association, joint venture, or other entity, or government or political subdivision or agency.

“Preferred Stock,” as applied to the Capital Stock of any corporation, means Capital Stock of any class or classes (however designated) which is preferred as to the payment of dividends, or as to the distribution of assets upon any voluntary or involuntary liquidation or dissolution of such corporation, over shares of Capital Stock of any other class of such corporation.

S-121

“Production Payments and Reserve Sales” means the grant or transfer by the Company or a Restricted Subsidiary to any Person of a royalty, overriding royalty, net profits interest, production payment (whether volumetric or dollar denominated), partnership or other interest in oil and gas properties or the right to receive all or a portion of the production or the proceeds from the sale of production attributable to such properties, where the grantee or transferee thereof has recourse solely to such production or proceeds of production, subject to the obligation of the grantor or transferor to operate and maintain, or cause to be operated and maintained, the related oil and gas properties or other related interests in a reasonably prudent manner or other customary standard or subject to the obligation of the grantor or transferor to indemnify for environmental, title or other matters customary in the Oil and Gas Business, including any such grants or transfers pursuant to incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologists, geophysicists or other providers of technical services to the Company or a Restricted Subsidiary.

“Rating Agency” means Standard & Poor’s Ratings Group, Inc. and Moody’s Investors Service, Inc. or if Standard & Poor’s Ratings Group, Inc. or Moody’s Investors Service, Inc. or both shall not make a rating on the Notes publicly available, a nationally recognized statistical rating agency or agencies, as the case may be, selected by the Company (as certified by a resolution of the Board of Directors or a committee thereof) which shall be substituted for Standard & Poor’s Ratings Group, Inc. or Moody’s Investors Service, Inc. or both, as the case may be.

“Receivables” means a right to receive payment arising from a sale or lease of goods or the performance of services by a Person pursuant to an arrangement with another Person pursuant to which such other Person is obligated to pay for goods or services under terms that permit the purchase of such goods and services on credit and shall include, in any event, any items of property that would be classified as an “account,” “chattel paper,” “payment intangible” or “instrument” under the Uniform Commercial Code as in effect in the State of New York and any “supporting obligations” as so defined.

“Receivables Fees” means any fees or interest paid to purchasers or lenders providing the financing in connection with a factoring agreement or other similar agreement, including any such amounts paid by discounting the face amount of Receivables or participations therein transferred in connection with a factoring agreement or other similar arrangement, regardless of whether any such transaction is structured as on-balance sheet or off-balance sheet or through a Restricted Subsidiary or an Unrestricted Subsidiary.

“Refinancing Indebtedness” means Indebtedness that is Incurred to refund, refinance, replace, exchange, renew, repay or extend (including pursuant to any defeasance or discharge mechanism) (collectively, “refinance,” “refinances,” and “refinanced” shall have a correlative meaning) any Indebtedness existing on the Issue Date or Incurred in compliance with the Indenture (including Indebtedness of the Company that refinances Indebtedness of any Restricted Subsidiary and Indebtedness of any Restricted Subsidiary that refinances Indebtedness of another Restricted Subsidiary) including Indebtedness that refinances Refinancing Indebtedness, provided, however, that:

(1)  (a) if the Stated Maturity of the Indebtedness being refinanced is earlier than the Stated Maturity of the Notes, the Refinancing Indebtedness has a Stated Maturity no earlier than the Stated Maturity of the Indebtedness being refinanced or (b) if the Stated Maturity of the Indebtedness being refinanced is later than the Stated Maturity of the Notes, the Refinancing Indebtedness has a Stated Maturity at least 91 days later than the Stated Maturity of the Notes;

S-122

(2)	the Refinancing Indebtedness has an Average Life at the time such Refinancing Indebtedness is Incurred that is equal to or greater than the Average Life of the Indebtedness being refinanced;
(3)	such Refinancing Indebtedness is Incurred in an aggregate principal amount (or if issued with original issue discount, an aggregate issue price) that is equal to or less than the sum of the aggregate principal amount (or if issued with original issue discount, the aggregate accreted value) then outstanding of the Indebtedness being refinanced (plus, without duplication, any additional Indebtedness Incurred to pay interest or premiums required by the instruments governing such existing Indebtedness and fees and expenses Incurred in connection therewith); and
(4)	if the Indebtedness being refinanced is subordinated in right of payment to the Notes or the Subsidiary Guarantee, such Refinancing Indebtedness is subordinated in right of payment to the Notes or the Subsidiary Guarantee on terms at least as favorable to the holders as those contained in the documentation governing the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded.

“Representative” means any trustee, agent or representative (if any) of an issue of Senior Indebtedness; provided that when used in connection with the Senior Secured Credit Agreements, the term “Representative” shall refer to the global administrative agent under the Senior Secured Credit Agreements.

“Restricted Investment” means any Investment other than a Permitted Investment.

“Restricted Subsidiary” means any Subsidiary of the Company other than an Unrestricted Subsidiary.

“Sale/ Leaseback Transaction” means an arrangement relating to property now owned or hereafter acquired whereby the Company or a Restricted Subsidiary transfers such property to a Person and the Company or a Restricted Subsidiary leases it from such Person.

“Second Lien Mortgage Notes” means the Company’s Senior Subordinated Second Lien Mortgage Notes due December 31, 2006.

“Senior Indebtedness” means, whether outstanding on the Issue Date or thereafter issued, created, Incurred or assumed, the Bank Indebtedness and all amounts payable by the Company under or in respect of all other Indebtedness of the Company, including premiums and accrued and unpaid interest (including interest accruing on or after the filing of any petition in bankruptcy or for reorganization relating to the Company at the rate specified in the documentation with respect thereto whether or not a claim for post-filing interest is allowed in such proceeding) and fees relating thereto; provided, however, that Senior Indebtedness will not include:

(1)	any Indebtedness Incurred in violation of the Indenture;
(2)	any obligation of the Company to any Subsidiary;
(3)	any liability for Federal, state, foreign, local or other taxes owed or owing by the Company;
(4)	any accounts payable or other liability to trade creditors arising in the ordinary course of business (including Guarantees thereof or instruments evidencing such liabilities);

S-123

(5)	any Indebtedness, Guarantee or obligation of the Company that is expressly subordinate or junior in right of payment to any other Indebtedness, Guarantee or obligation of the Company, including, without limitation, any Senior Subordinated Indebtedness and any Subordinated Obligations; or
(6)	any Capital Stock.

“Senior Secured Credit Agreement” means (1) the Credit Agreement, dated as of July 28, 2004, among Quicksilver Resources Inc., as Borrower, JP Morgan Chase Bank, N.A (successor by merger to Bank One, NA), Global Administrative Agent, and the other agents and financial institutions from time to time party thereto, as amended; (2) the Credit Agreement, dated as of July 28, 2004, among MGV Energy, Inc., as Borrower, JP Morgan Chase Bank, N.A., Toronto Branch (successor by merger to Bank One, NA, Canada Branch), Canadian Administrative Agent, Bank One, NA, Global Administrative Agent, and the financial institutions from time to time party thereto, as amended; and (3) each such agreement as the same may be amended, restated, renewed, extended, supplemented, increased, replaced or otherwise modified from time to time.

“Senior Subordinated Indebtedness” means the Notes, the Second Lien Mortgage Notes and any other Indebtedness of the Company that specifically provides that such Indebtedness is to rank equally with the Notes in right of payment and is not subordinated by its terms in right of payment to any Indebtedness or other obligation of the Company which is not Senior Indebtedness.

“Significant Subsidiary” means any Restricted Subsidiary that would be a “Significant Subsidiary” of the Company within the meaning of Rule 1-02 under Regulation S-X promulgated by the SEC.

“Special Entity” means any Restricted Subsidiary that is not a Wholly-Owned Subsidiary that (i) is classified as a pass-through entity for U.S. federal, state, local and foreign income tax purposes and (ii) has no Indebtedness; provided, however, that neither Saginaw Bay Lateral Limited Partnership nor Terra Hayes Pipeline Company shall be a Special Entity.

“Stated Maturity” means, with respect to any security, the date specified in such security as the fixed date on which the payment of principal of such security is due and payable, including pursuant to any mandatory redemption provision, but shall not include any contingent obligations to repay, redeem or repurchase any such principal prior to the date originally scheduled for the payment thereof.

“Subordinated Obligation” means any Indebtedness of the Company (whether outstanding on the Issue Date or thereafter Incurred) that is subordinate or junior in right of payment to the Notes pursuant to a written agreement.

“Subsidiary” of any Person means (a) any corporation, association or other business entity (other than a partnership, joint venture, limited liability company or similar entity) of which more than 50% of the total ordinary voting power of shares of Capital Stock entitled (without regard to the occurrence of any contingency) to vote in the election of directors, managers or trustees thereof (or persons performing similar functions) or (b) any partnership, joint venture limited liability company or similar entity of which more than 50% of the capital accounts, distribution rights, total equity and voting interests or general or limited partnership interests, as applicable, is, in the case of clauses (a) and (b), at the time owned or controlled, directly or indirectly, by (1) such Person, (2) such Person and one or more Subsidiaries of such Person or

S-124

(3) one or more Subsidiaries of such Person. Unless otherwise specified herein, each reference to a Subsidiary will refer to a Subsidiary of the Company.

“Subsidiary Guarantee” means, individually, any Guarantee of payment of the Notes by a Subsidiary Guarantor pursuant to the terms of the Indenture and any supplemental indenture thereto, and, collectively, all such Guarantees. Each such Subsidiary Guarantee will be in the form prescribed by the Indenture.

“Subsidiary Guarantor” means (i) Mercury Michigan Inc., Terra Energy Ltd., GTG Pipeline Corporation, Cowtown Pipeline Funding, Inc., Cowtown Pipeline Management, Inc., Terra Pipeline Company, Beaver Creek Pipeline, L.L.C., Cowtown Pipeline LP and Cowtown Gas Processing L.P., and (ii) any Restricted Subsidiary (other than a Foreign Subsidiary and, except to the extent it Guarantees the Notes, a Special Entity) created or acquired by the Company or one or more of its Restricted Subsidiaries after the Issue Date.

“Unrestricted Subsidiary” means

(1)	Saginaw Bay Lateral Limited Partnership;
(2)	any other Subsidiary of the Company that at the time of determination shall be designated an Unrestricted Subsidiary by the Board of Directors of the Company in the manner provided below; and
(3)	any Subsidiary of an Unrestricted Subsidiary.

The Board of Directors of the Company may designate any Subsidiary of the Company (including any newly acquired or newly formed Subsidiary or a Person becoming a Subsidiary through merger or consolidation or Investment therein) to be an Unrestricted Subsidiary only if:

(1)	such Subsidiary or any of its Subsidiaries does not own any Capital Stock or Indebtedness of or have any Investment in, or own or hold any Lien on any property of, any other Subsidiary of the Company which is not a Subsidiary of the Subsidiary to be so designated or otherwise an Unrestricted Subsidiary;
(2)	all the Indebtedness of such Subsidiary and its Subsidiaries shall, at the date of designation and at all times thereafter, consist of Non-Recourse Debt;
(3)	such designation and the Investment of the Company in such Subsidiary complies with “Certain covenants— Limitation on restricted payments;”
(4)	such Subsidiary, either alone or in the aggregate with all other Unrestricted Subsidiaries, does not operate, directly or indirectly, all or substantially all of the business of the Company and its Subsidiaries;
(5)	such Subsidiary is a Person with respect to which neither the Company nor any of its Restricted Subsidiaries has any direct or indirect obligation:

(a)  to subscribe for additional Capital Stock of such Person; or

(b)  to maintain or preserve such Person’s financial condition or to cause such Person to achieve any specified levels of operating results; and

(6)  on the date such Subsidiary is designated an Unrestricted Subsidiary, such Subsidiary is not a party to any agreement, contract, arrangement or understanding with the Company or any Restricted Subsidiary with terms materially less favorable to the

S-125

Company than those that might have been reasonably obtained from Persons that are not Affiliates of the Company.

Any such designation by the Board of Directors of the Company shall be evidenced to the Trustee by filing with the Trustee a resolution of the Board of Directors of the Company giving effect to such designation and an Officers’ Certificate certifying that such designation complies with the foregoing conditions. If, at any time, any Unrestricted Subsidiary would fail to meet the foregoing requirements as an Unrestricted Subsidiary, it shall thereafter cease to be an Unrestricted Subsidiary for purposes of the Indenture and any Indebtedness of such Subsidiary shall be deemed to be Incurred as of such date.

The Board of Directors of the Company may designate any Unrestricted Subsidiary to be a Restricted Subsidiary; provided that immediately after giving effect to such designation, no Default or Event of Default shall have occurred and be continuing or would occur as a consequence thereof and the Company could Incur at least $1.00 of additional Indebtedness under the first paragraph of the “Limitation on indebtedness” covenant on a pro forma basis taking into account such designation.

“U.S. Government Obligations” means securities that are (a) direct obligations of the United States of America for the timely payment of which its full faith and credit is pledged or (b) obligations of a Person controlled or supervised by and acting as an agency or instrumentality of the United States of America the timely payment of which is unconditionally guaranteed as a full faith and credit obligation of the United States of America, which, in either case, are not callable or redeemable at the option of the issuer thereof, and shall also include a depositary receipt issued by a bank (as defined in Section 3(a)(2) of the Securities Act), as custodian with respect to any such U.S. Government Obligations or a specific payment of principal of or interest on any such U.S. Government Obligations held by such custodian for the account of the holder of such depositary receipt; provided that (except as required by law) such custodian is not authorized to make any deduction from the amount payable to the holder of such depositary receipt from any amount received by the custodian in respect of the U.S. Government Obligations or the specific payment of principal of or interest on the U.S. Government Obligations evidenced by such depositary receipt.

“Volumetric Production Payments” means production payment obligations recorded as deferred revenue in accordance with GAAP, together with all undertakings and obligations in connection therewith.

“Voting Stock” of a corporation means all classes of Capital Stock of such corporation then outstanding and normally entitled to vote in the election of directors.

“Wholly-Owned Subsidiary” means a Restricted Subsidiary, all of the Capital Stock of which (other than directors’ qualifying shares) is owned by the Company or another Wholly-Owned Subsidiary.

S-126

Certain U.S. federal income tax considerations

General

The following is a summary of certain U.S. federal income tax considerations relating to the purchase, ownership and disposition of the notes by initial holders. It is not a complete analysis of all the potential tax considerations relating to the notes. This summary is based upon the provisions of the Internal Revenue Code of 1986, as amended, or the Code, Treasury Regulations promulgated under the Code, and currently effective administrative rulings and judicial decisions. These authorities may be changed, perhaps with retroactive effect, so as to result in U.S. federal income tax consequences different from those set forth below. We have not sought any ruling from the Internal Revenue Service, or I.R.S., or an opinion of counsel with respect to the statements made herein concerning the notes, and we cannot assure you that the I.R.S will agree with such statements.

This summary assumes that the notes are held as capital assets and holders purchase the notes upon their initial issuance pursuant to this prospectus at the notes’ initial offering price. This summary does not address the tax considerations arising under the laws of any foreign, state or local jurisdiction. In addition, this discussion does not address all tax considerations that may be applicable to holders’ particular circumstances or to holders that may be subject to special tax rules, such as, for example:

•  holders subject to the alternative minimum tax;

•  banks, insurance companies, or other financial institutions;

•  tax-exempt organizations;

•  dealers in securities or commodities;

•  expatriates;

•  traders in securities that elect to use a mark-to-market method of accounting for their securities holdings;

•  holders whose functional currency is not the U.S. dollar;

•  persons that will hold the notes as a position in a hedging transaction, straddle, conversion transaction or other risk reduction transaction;

•  persons deemed to sell the notes under the constructive sale provisions of the Code; or

•  partnerships or other pass-through entities.

If a partnership holds notes, the tax treatment of a partner in the partnership will generally depend upon the status of the partner and the activities of the partnership. If you are a partner of a partnership holding our notes, you should consult your tax advisor regarding the tax consequences of the purchase, ownership and disposition of the notes.

This summary of certain U.S. federal income tax considerations is for general information only and is not tax advice. You are urged to consult your tax advisor with respect to the application of U.S. federal income tax laws to your particular situation, as well as any tax consequences arising under the U.S. federal estate or gift tax rules or under the laws of any state, local, foreign or other taxing jurisdiction or under any applicable tax treaty.

S-127

Consequences to U.S. Holders

The following is a summary of the general U.S. federal income tax consequences that will apply to you if you are a “U.S. Holder” of the notes. Certain consequences to “Non-U.S. Holders” of the notes are described under ‘— Consequences to Non-U.S. Holders,” below. “U.S. Holder” means a beneficial owner of a note that is, for U.S. federal income tax purposes:

•  an individual citizen or resident of the United States;

•  a corporation (or other entity treated as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States or any political subdivision of the United States;

•  an estate the income of which is subject to U. S. federal income taxation regardless of its source; or

•  a trust that (1) is subject to the supervision of a court within the United States and the control of one or more “United States person” (as defined in the Code) or (2) has a valid election in effect under applicable Treasury Regulations to be treated as a United States person.

Payments of interest

Stated interest on the notes will generally be taxable to a U.S. Holder as ordinary income at the time it is paid or accrued in accordance with the holder’s regular method of accounting for U.S. federal income tax purposes. We do not anticipate that the notes will bear original issue discount, or OID, for U.S. federal income tax purposes. Therefore, we do not expect that holders of the notes will be required to recognize OID as interest income over the term of the notes under OID tax regulations.

Disposition of notes

Upon the sale, exchange, redemption or other taxable disposition of a note, a U.S. Holder generally will recognize taxable gain or loss equal to the difference between the amount realized on such disposition (except to the extent any amount realized is attributable to accrued but unpaid interest, which is treated as interest as described above) and the holder’s adjusted tax basis in the note. A U.S. Holder’s adjusted tax basis in a note generally will equal the cost of the note to such holder.

Gain or loss recognized on the disposition of a note generally will be capital gain or loss, and will be long-term capital gain or loss if, at the time of such disposition, the U.S. Holder’s holding period for the note is more than 12 months. The deductibility of capital losses by U.S. Holders is subject to certain limitations.

Information reporting and backup withholding

In general, information reporting requirements will apply to certain payments of principal, premium (if any) and interest on and the proceeds of certain sales of notes unless the U.S. Holder is an exempt recipient. A backup withholding tax may apply to such payments if the U.S. Holder fails to provide its taxpayer identification number or certification of exempt status or has been notified by the I.R.S. that payments to the U.S. Holder are subject to backup withholding.

S-128

Any amounts withheld under the backup withholding rules will generally be allowed as a refund or a credit against a holder’s U.S. federal income tax liability provided that the U.S. Holder furnishes the required information to the I.R.S. on a timely basis.

Consequences to Non-U.S. Holders

The following is a summary of the U.S. federal income tax consequences that will generally apply to you if you are a Non-U.S. Holder of notes. The term “Non-U.S. Holder” means a beneficial owner of a note that is, for U.S. federal income tax purposes, a nonresident alien individual or a corporation, estate or trust that is not a U.S. Holder.

Special rules may apply to certain Non-U.S. Holders such as “controlled foreign corporations” and “passive foreign investment companies,” as such terms are defined in the Code. If you are a Non-U.S. Holder, we encourage you to consult your tax advisors to determine the U.S. federal, state, local and other tax consequences that may be relevant to you.

Payments of interest

The 30% U.S. federal withholding tax (or lower applicable treaty rate) generally will not apply to any payment to a Non-U.S. Holder of interest on a note that is not effectively connected with a U.S. trade or business provided that:

•  the Non-U.S. Holder does not actually or constructively (under applicable attribution rules) own 10% or more of the total combined voting power of our voting stock, within the meaning of Section 871(h)(3) of the Code;

•  the Non-U.S. Holder is not a controlled foreign corporation that is related to us directly or indirectly through stock ownership; and

•  (a) the Non-U.S. Holder provides its name and address, and certifies, under penalties of perjury, that it is not a United States person (which certification may be made on an I.R.S. Form W-8BEN) or (b) a securities clearing organization, bank, or other financial institution that holds customers’ securities in the ordinary course of its business holds the note on a Non-U.S. Holder’s behalf and certifies, under penalties of perjury, either that it has received I.R.S. Form W-8BEN from the holder or from another qualifying financial institution intermediary or that it is permitted to establish and has established the holder’s foreign status through other documentary evidence, and otherwise complies with applicable requirements. If the notes are held by or through certain foreign intermediaries or certain foreign partnerships, such foreign intermediaries or partnerships must also satisfy the certification requirements of applicable Treasury Regulations.

If a Non-U.S. Holder cannot satisfy the requirements described above, payments of interest will be subject to the 30% U.S. federal withholding tax, unless the holder provides us with a properly executed (1) I.R.S. Form W-8BEN claiming an exemption from or reduction in withholding under an applicable tax treaty or (2) I.R.S. Form W-8ECI stating that interest paid on the note is not subject to withholding tax because it is effectively connected with the holder’s conduct of a trade or business in the United States.

If a Non-U.S. Holder is engaged in a trade or business in the United States and interest on a note is effectively connected with the conduct of that trade or business, it will instead be required to pay U.S. federal income tax on that interest on a net income basis in the same manner as if the holder were a U.S. Holder, except as otherwise provided by an applicable tax

S-129

treaty. In addition, if a Non-U.S. Holder is a foreign corporation, it may be subject to a branch profits tax equal to 30% (or lower applicable treaty rate) of its earnings and profits for the taxable year, subject to adjustments, that are effectively connected with its conduct of a trade or business in the United States. For this purpose, interest on the notes which is effectively connected with your conduct of a trade or business in the United States would be included in your earnings and profits.

Disposition of notes

Any gain recognized upon the sale, exchange, redemption or other taxable disposition of a note (except with respect to accrued and unpaid interest, which would be taxable as such) will not be subject to the 30% U.S. federal withholding tax. Such gain also generally will not be subject to U.S. federal income tax unless:

•  that gain is effectively connected with a Non-U.S. Holder’s conduct of a trade or business in the United States; or

•  the Non-U.S. Holder is an individual who is present in the United States for 183 days or more in the taxable year of the disposition, and certain other conditions are met.

A Non-U.S. Holder described in the first bullet point above will generally be required to pay U.S. federal income tax on the net gain derived from the sale, except as otherwise required by an applicable tax treaty, and if such holder is a foreign corporation, it may also be required to pay a branch profits tax at a 30% rate or a lower rate if so specified by an applicable tax treaty.

Information reporting and backup withholding

In general, we must report to the I.R.S. and to each Non-U.S. Holder the amount of interest on the notes paid to such Non-U.S. Holder and the amount of tax, if any, withheld with respect to those payments. Copies of the information returns reporting such interest payments and any withholding may also be made available to the tax authorities in the country in which the Non-U.S. Holder resides under the provisions of an applicable tax treaty. Backup withholding may apply to certain payments of principal, premium (if any) and interest on the notes to Non-U.S. Holders, as well as to the proceeds of certain sales of notes made through brokers, unless the holder has made appropriate certifications as to its foreign status, or has otherwise established an exemption. The certification of foreign status described above under ‘— Payments of interest” is generally effective to establish an exemption from backup withholding.

Any amounts withheld under the backup withholding rules will generally be allowed as a refund or a credit against a Non-U.S. Holder’s U.S. federal income tax liability provided that it furnishes the required information to the I.R.S. on a timely basis.

S-130

Underwriting

Subject to the terms and conditions in the underwriting agreement between us and the underwriters, we have agreed to sell to each underwriter, and each underwriter has severally agreed to purchase from us, the principal amount of notes that appears opposite its name in the table below:

Underwriter	Principal amount
J.P. Morgan Securities Inc.	$
Credit Suisse Securities (USA) LLC
Banc of America Securities LLC
BNP Paribas Securities Corp.
Goldman, Sachs & Co.
Total	$	300,000,000

The underwriters have agreed to purchase all of the notes if any of them are purchased.

The underwriters initially propose to offer the notes to the public at the public offering price that appears on the cover page of this prospectus. After the initial offering, the underwriters may change the public offering price and any other selling terms. The underwriters may offer and sell notes through certain of their affiliates.

In the underwriting agreement, we have agreed that:

•  We will not offer or sell any of our debt securities (other than the notes) for a period of 90 days after the date of this prospectus supplement without the prior consent of J.P. Morgan Securities Inc. and Credit Suisse Securities (USA) LLC.

•  We will indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933.

The notes are new issues of securities with no established trading market. We do not intend to apply for the notes to be listed on any securities exchange or to arrange for the notes to be quoted on any quotation system. The underwriters have advised us that they intend to make a market in the notes. However, they are not obligated to do so and they may discontinue any market making at any time in their sole discretion. Therefore, we cannot assure you that a liquid trading market will develop for the notes, that you will be able to sell your notes at a particular time or that the prices that you receive when you sell will be favorable.

In connection with this offering of the notes, the underwriters may engage in overallotments, stabilizing transactions and short covering transactions in accordance with Regulation M under the Securities Exchange Act of 1934. Overallotment involves sales in excess of the offering size, which creates a short position for the underwriters. Stabilizing transactions involve bids to purchase the notes in the open market for the purpose of pegging, fixing or maintaining the price of the notes, as applicable. Short covering transactions involve purchases of the notes in the open market after the distribution has been completed in order to cover short positions. Stabilizing transactions and short covering transactions may cause the price of the notes to be higher than it would otherwise be in the absence of those transactions. If either underwriter engages in stabilizing or short covering transactions, it may discontinue them at any time.

S-131

Certain of the underwriters and their affiliates have in the past and may in the future provide investment banking, commercial banking and financial advisory services to us and our affiliates in the ordinary course of business. In particular, an affiliate of J.P. Morgan Securities Inc. and Banc of America Securities LLC are lenders to the company under its senior secured revolving credit facilities. We intend to use a portion of the net proceeds of the offering to repay amounts outstanding under the senior secured credit facilities. See “Use of proceeds.”

S-132

Legal matters

The validity of the notes offered hereby will be passed upon for Quicksilver by Jones Day. Certain legal matters will be passed upon for the underwriters by Simpson Thacher & Bartlett LLP, New York, New York.

Experts

The consolidated financial statements as of December 31, 2005 and 2004 and for each of the three years in the period ended December 31, 2005 and management’s report on the effectiveness of internal control over financial reporting as of December 31, 2005 included and incorporated into this prospectus by reference from our Annual Report on Form 10-K for the year ended December 31, 2005 have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their reports (which report on the consolidated financial statements expresses an unqualified opinion and includes an explanatory paragraph related to the adoption of Statement of Financial Accounting Standard No. 143, Accounting for Asset Retirement Obligations, on January 1, 2003), which are herein included and incorporated by reference, and have been so included and incorporated in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing.

Reserve engineers

Certain information contained in the documents we incorporate by reference regarding estimated quantities of natural gas and crude oil reserves owned by us, the future net revenues from those reserves and their present value is based on estimates of the reserved and present values prepared by or derived from estimates prepared by Schlumberger Data and Consulting Services, Netherland, Sewell & Associates, Inc. and LaRoche Petroleum Consultants, Ltd. All of such information has been incorporated into this prospectus by reference in reliance upon the authority of these firms as experts in such matters.

S-133

Glossary of certain oil and natural gas terms

In this prospectus supplement, the following terms have the meanings specified below.

All-in average F&D cost	All-in average F&D cost is calculated by dividing (x) development, exploitation, exploration and acquisition capital expenditures for the period, plus unevaluated capital expenditures as of the beginning of the period, less unevaluated capital expenditures as of the end of the period, by (y) reserve additions for the period.
Bbl	One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.
Bcf	One billion cubic feet.
Bcfe	One billion cubic feet of natural gas equivalents, based on a ratio of 6 Mcf for each barrel of oil, which reflects the relative energy content.
Dry hole	A well found to be incapable of producing oil or natural gas in sufficient economic quantities.
Exploitation	Optimization of the recovery of reserves.
Exploratory well or prospect	A well drilled to find oil or gas in an unproved area, to find a new reservoir in an existing field or to extend a known reservoir.
F&D cost	F&D cost is calculated by dividing (x) development, exploitation and exploration capital expenditures for the period, plus unevaluated capital expenditures as of the beginning of the period, less unevaluated capital expenditures as of the end of the period, by (y) reserve additions excluding purchases for the period.
Gross acres or gross wells	The total acres or wells, as the case may be, in which a working interest is owned.
Infill well	A well drilled between known producing wells to better exploit the reservoir
MBbl	One thousand barrels of crude oil or other liquid hydrocarbons.
Mcf	One thousand cubic feet of gas.
Mcf per day	One thousand cubic feet of gas per day.
Mcfe	One thousand cubic feet of natural gas equivalents, based on a ratio of 6 Mcf for each barrel of oil or NGL, which reflects relative energy content.
Mmbbl	One million barrels of crude oil or other liquid hydrocarbons.
Mmbtu	One million British thermal units. A British thermal unit is the heat required to raise the temperature of one-pound of water one degree Fahrenheit.

S-134

MMcf	One million cubic feet of gas.
MMcfe	One million cubic feet of gas equivalents.
Net acres or net wells	The sum of the fractional working interests owned in gross acres or gross wells.
Productive well	A well that is producing oil or natural gas or that is capable of production.
Proved developed reserves	Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved reserves	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.
Proved undeveloped reserves	Proved 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 recompletion.
Recompletion	The completion for production of another formation in an existing well bore.
Reserve life	Proved reserves at a point in time divided by the then annual production rate.
Reserve replacement ratio	The reserve replacement ratio is calculated by dividing the sum of reserve additions from all sources (revisions, purchases, extensions and discoveries) for a specified period by the actual production for the period.
Working interest	The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production, subject to all royalties, overriding royalties and other burdens, and to all costs of exploration, development and operations, and all risks in connection therewith.

S-135

Quicksilver Resources Inc.

Index to consolidated financial statements

	Page
Management’s statement of responsibilities		F-1
Report of independent registered public accounting firm		F-3
Consolidated balance sheets as of December 31, 2005 and 2004		F-4
Consolidated statements of income and comprehensive income for the years ended December 31, 2005, 2004 and 2003		F-5
Consolidated statements of stockholders’ equity for the years ended December 31, 2005, 2004 and 2003		F-6
Consolidated statements of cash flows for the years ended December 31, 2005, 2004 and 2003		F-7
Notes to consolidated financial statements for the years ended December 31, 2005, 2004 and 2003		F-8

Management’s statement of responsibilities

To the Stockholders of Quicksilver Resources Inc.:

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

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

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

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

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

F-1

December 31, 2005, the Company’s system of internal control over financial reporting was effective.

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

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

Fort Worth, Texas

March 1, 2006

F-2

Report of independent registered public accounting firm

To the Board of Directors and Stockholders of

Quicksilver Resources Inc.

Fort Worth, Texas

We have audited the accompanying consolidated balance sheets of Quicksilver Resources Inc. and subsidiaries (the “Company”) as of December 31, 2005 and 2004 and the related consolidated statements of income and comprehensive income, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

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

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

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

/s/ Deloitte & Touche LLP

Fort Worth, Texas

March 1, 2006

F-3

Quicksilver Resources Inc.

Consolidated balance sheets

as of December 31, 2005 and 2004

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

(1) Share and per share amounts have been adjusted to reflect a three-for-two stock split effected in the form of a stock dividend in June 2005. The split did not affect treasury shares.

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

F-4

Quicksilver Resources Inc.

Consolidated statements of income and comprehensive income

for the years ended December 31, 2005, 2004 and 2003

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

(1) Share and per share amounts have been adjusted to reflect a three-for-two stock split effected in the form of a stock dividend in June 2005. The split did not affect treasury shares.

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

F-5

Quicksilver Resources Inc.

Consolidated statements of stockholders’ equity

for the years ended December 31, 2005, 2004 and 2003

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

(1) Share and per share amounts have been adjusted to reflect a three-for-two stock split effected in the form of a stock dividend in June 2005. The split did not affect treasury shares.

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

F-6

Quicksilver Resources Inc.

Consolidated statements of cash flows

for the years end December 31, 2005, 2004 and 2003

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

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

F-7

Quicksilver Resources Inc.

Notes to consolidated financial statements

for the years ended December 31, 2005, 2004 and 2003

1. Nature of operations

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

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

2. Significant accounting policies

Stock split

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

On June 1, 2004, Quicksilver announced that its Board of Directors declared a two-for-one stock split of Quicksilver’s outstanding common stock effected in the form of a stock dividend. The stock dividend was payable on June 30, 2004, to holders of record at the close of business on June 15, 2004. The split did not affect treasury shares.

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

Principles of consolidation

The Consolidated Financial Statements include the accounts of Quicksilver and its subsidiaries (collectively, the “Company”). The Company accounts for its ownership in unincorporated partnerships and companies under the equity method of accounting as it has significant influence over those entities, but because of terms of the ownership agreements Quicksilver does not meet the criteria for control which would require consolidation of the entities. The

F-8

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

Company also consolidates its pro-rata share of oil and gas joint ventures. All significant inter-company transactions are eliminated.

Use of estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during each reporting period. Management believes its estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties, which may cause actual results to differ materially from the Company’s estimates. Significant estimates underlying these financial statements include the estimated quantities of proved natural gas and crude oil reserves used to compute depletion of natural gas and crude oil properties and the related present value of estimated future net cash flows therefrom (see Supplemental Information beginning on page F-42 ), estimates of current revenues based upon expectations for actual deliveries and prices received, the estimated fair value of financial derivative instruments and the estimated fair value of asset retirement obligations.

Cash and cash equivalents

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

Accounts receivable

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

Hedging

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

F-9

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

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

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

Parts and supplies

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

Investments in equity affiliates

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

Properties, plant, and equipment

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

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

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

F-10

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

tax basis of the natural gas and crude oil properties. Such limitations are imposed separately for the U.S. and Canadian cost centers.

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

Revenue recognition

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

Environmental compliance and remediation

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

Income taxes

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

Disclosure of fair value of financial instruments

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

Foreign currency translation

The Company’s Canadian subsidiary, MGV, uses the Canadian dollar as its functional currency. All balance sheet accounts of Canadian operations are translated into U.S. dollars at the year-end rate of exchange and statement of income items are translated at the weighted average

F-11

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

exchange rates for the year. The resulting translation adjustments are made directly to a separate component of accumulated other comprehensive income within stockholders’ equity. Gains and losses from foreign currency transactions are included in the consolidated statement of income.

Earnings per share

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

F-12

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

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

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

F-13

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

Stock-based employee compensation

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

		Years ended December 31,
(in thousands, except per share data)		2005			2004			2003
Net income		$	87,434		$	31,272		$	16,208
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of income taxes			(11,359	)		(4,524	)		(423	)
Pro forma net income		$	76,075		$	26,748		$	15,785
Net income
	Basic – as reported	$	1.15		$	0.42		$	0.24
	Basic—pro forma	$	1.00		$	0.36		$	0.23
	Diluted—as reported	$	1.08		$	0.41		$	0.24
	Diluted—pro forma	$	0.95		$	0.35		$	0.23

Recently issued accounting standards

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

F-14

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

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

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

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

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

F-15

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

3. Discontinued drilling operations

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

4. Hedging

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

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

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

The change in carrying value of the Company’s derivatives, firm sale and purchase commitments accounted for as hedges and interest rate swaps in the Company’s balance sheet since December 31, 2004 resulted from the expiration of fixed price commodity swaps and all interest rate hedges, as well as an increase in market prices for natural gas and crude oil. The change in fair value of all cash flow hedges was reflected in accumulated other comprehensive income, net of deferred tax effects. Natural gas and crude oil derivative assets and liabilities reflected as current in the December 31, 2005 balance sheet represent the estimated fair value of contract settlements scheduled to occur over the subsequent twelve-month period based on

F-16

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

market prices for natural gas and crude oil as of the balance sheet date. These settlement amounts are not due and payable until the monthly period in which the related underlying hedged gas or oil sales transaction occurs. Settlement of the underlying hedged transactions occurs in the following 25 to 60 days.

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

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

The fair value of all natural gas and crude derivatives and firm sale and purchase commitments accounted for as hedges as of December 31, 2005 and 2004 was estimated based on market prices of natural gas and crude oil for the periods covered by the derivatives. The net differential between the prices in each derivative and market prices for future periods, as adjusted for estimated basis, has been applied to the volumes stipulated in each contract to arrive at an estimated future value. This estimated future value was discounted on each contract at rates commensurate with federal treasury instruments with similar contractual lives. The fair value of the interest rate swap was based upon counterparty estimates of the fair value of such swaps. As a result, the fair value of the Company’s derivatives and commitments does not necessarily represent the value a third party would pay or expect to receive to assume the Company’s contract positions. Derivatives assets of $0.6 million and $40.6 million of total derivative liabilities of $45.3 million have been classified as current at December 31, 2005 based on the maturity of the derivative instruments, resulting in $25.4 million of after-tax losses to be reclassified from accumulated other comprehensive income in 2006.

F-17

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

5. Financial instruments

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

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

Commodity price risk

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

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

F-18

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

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

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

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

Commodity price fluctuations affect the remaining natural gas and crude oil volumes as well as the Company’s NGL volumes. Natural gas volumes of 4.5 MMcfd are committed at market price through May 2006 and an additional 16.5 MMcfd of natural gas is committed at market price

F-19

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

through September 2008. During 2005, over 7.2 MMcfd of Quicksilver’s natural gas production was sold under these contracts. Almost 9.3 MMcfd sold under these contracts were third-party volumes controlled by the Company.

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

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

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

The fair values of fixed price and floating price natural gas and crude oil derivatives and associated firm commitments as of December 31, 2005 and 2004 were estimated based on market prices of natural gas and crude oil for the periods covered by the contracts. The net differential between the prices in each contract and market prices for future periods, as adjusted for estimated basis, has been applied to the volumes stipulated in each contract to arrive at an estimated future value. This estimated future value was discounted on each contract at rates commensurate with federal treasury instruments with similar contractual lives.

F-20

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

As a result, the natural gas and crude oil financial swap and firm commitment fair value does not necessarily represent the value a third party would pay or expect to receive to assume the Company’s contract positions.

Interest rate risk

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

On September 10, 2003, the Company entered into an interest rate swap to hedge the $40.0 million of fixed-rate second lien notes issued on June 27, 2003. The swap converted the debt’s 7.5% fixed-rate debt to a floating six-month LIBOR base. The asset associated with the swap was $50,000 at December 31, 2003. In January 2004, the swap position was cancelled and the Company received a cash settlement of $0.3 million that is being recognized over the original term of the swap, which ends December 31, 2006. The deferred gain remaining at December 31, 2005 is $0.1 million.

Credit risk

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

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

Performance risk

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

F-21

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

Foreign currency risk

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

6. Accounts receivable

Accounts receivable consist of the following:

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

7. Other current assets

Other current assets consist of:

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

F-22

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

8. Properties, plant and equipment

Property and equipment includes the following:

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

Unevaluated natural gas and crude oil properties excluded from depletion

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

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

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

F-23

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

Capitalized costs

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

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

9. Other assets

Other assets consist of:

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

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

10. Accrued liabilities

Accrued liabilities include the following:

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

F-24

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

11. Notes payable and long-term debt

Long-term debt consists of:

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

Maturities are as follows, in thousands of dollars:

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

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

F-25

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

interest, taxes, depreciation, depletion and amortization, non-cash income and expense, and exploration costs) to interest expense ratio. The Company was in compliance with all such covenants at December 31, 2005. The senior credit facility was also used to issue letters of credit. At December 31, 2005, the Company had $1.0 million in letters of credit and $242.2 million available under the senior revolving credit facility.

On November 1, 2004, the Company sold $150 million $1.875% convertible subordinated debentures due November 1, 2024, which are contingently convertible into shares of Quicksilver’s common stock (subject to adjustment). As of December 31, 2005, the debentures were convertible into 4,908,128 shares of Quicksilver’s common stock. Each $1,000 debenture was issued at 98.5% of par and bears interest at an annual rate of 1.875% payable semi-annually on May 1 and November 1 of each year. Holders of the debentures can require the Company to repurchase all or a portion of their debentures on November 1, 2011, 2014 or 2019 at a price equal to the principal amount thereof plus accrued and unpaid interest. The debentures are convertible into Quicksilver common stock at a rate of 32.7209 shares for each $1,000 debenture, subject to adjustment. Generally, except upon the occurrence of specified events, holders of the debentures are not entitled to exercise their conversion rights unless the closing price of Quicksilver’s stock price for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter is $36.67 (120 % of the conversion price per share). Upon conversion, the Company has the option to deliver in lieu of Quicksilver common stock, cash or a combination of cash and Quicksilver common stock. At December 31, 2005, the fair value of the $150 million in principal amount of contingently convertible debentures was $227.7 million.

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

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

F-26

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

on the swap settlement will be amortized through the original term of the swap, December 31, 2006.

12. Asset retirement obligations

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

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

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

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

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

F-27

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

13. Commitments and contingencies

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

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

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

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

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

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

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

F-28

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

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

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

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

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

14. Income taxes

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

F-29

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

current U.S. federal income tax of approximately $0.8 million was accrued on this dividend distribution in 2004 and paid in 2005. No other deferred taxes have been accrued on MGV’s undistributed earnings and the Company continues to expect that the balance of MGV’s undistributed earnings will be permanently reinvested for use in the development of its oil and gas reserves.

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

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

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

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

F-30

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

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

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

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

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

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

15. Employee benefits

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

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

F-31

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

16. Stockholders’ equity

Stock split

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

On June 1, 2004, Quicksilver announced that its Board of Directors declared a two-for-one stock split of Quicksilver’s outstanding common stock effected in the form of a stock dividend. The stock dividend was payable on June 30, 2004, to holders of record at the close of business on June 15, 2004. The split did not affect treasury shares.

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

Common stock, preferred stock and treasury stock

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

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

	Common		Treasury
	shares issued		shares held
Opening Balance January 1, 2003		65,849,337		2,570,502
Stock options exercised		429,800		8,402
Stock issuance		10,500,000		—
Balance at December 31, 2003		76,779,137		2,578,902
Stock options exercised		973,014		(10,293	)
Balance at December 31, 2004		77,752,151		2,568,611
Stock options exercised		747,988		—
Stock issuance		149,971		2,458
Balance at December 31, 2005		78,650,110		2,571,069

Stockholder rights plan

On March 11, 2003, the Company’s board of directors declared a dividend distribution of one preferred share purchase right for each outstanding share of common stock of the Company outstanding on March 26, 2003. As amended through December 31, 2005, each right, when it becomes exercisable, entitles stockholders to buy one one-thousandth of a share of the Company’s Series A Junior Participating Preferred Stock at an exercise price of $180.00.

F-32

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

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

If an Acquiring Person acquires 15% or more of the outstanding common stock of the Company, each right will entitle its holder to purchase, at the right’s then-current exercise price, a number of common shares of the Company having a market value of twice such price. If Quicksilver is acquired in a merger or other business combination transaction after an Acquiring Person has acquired 15% or more of the outstanding common stock of the Company, each right will entitle its holder to purchase, at the right’s then-current exercise price, a number of the acquiring company’s common shares having a market value of twice such price.

Prior to the acquisition by an Acquiring Person of beneficial ownership of fifteen percent or more of the common stock of Quicksilver, the rights are redeemable for $0.01 per right at the option of the board of directors of the Company.

Employee stock plans

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

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

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

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

F-33

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

Plan for a total of 2,960 shares at a price of $33.78. The non-employee directors’ stock awards vest over a twelve-month period.

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

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

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

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

F-34

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

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

	Options outstanding					Options exercisable
			Wtd avg
			remaining	Wtd avg				Wtd avg
Range of			contractual	exercise				exercise
exercisable prices	Shares		life	price		Shares		price
$ 3-6		176,269	0.8	$	4.91		176,269	$	4.91
6-11		113,556	2.1		7.65		88,222		7.73
11-16		679,557	4.1		11.17		110,577		12.00
16-22		1,775,135	3.0		20.85		1,775,135		20.85
22-25		93,722	4.5		23.78		38,635		23.71
30-35		2,456	9.2		33.09		1,841		33.09
		2,840,695	3.1	$	17.13		2,190,679	$	18.65

17. Other revenue

Other revenue consists of the following:

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

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

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

On July 3, 2003, Quicksilver repurchased interests owned by the bank as a result of the Company’s tax credit sales. Quicksilver paid $6.3 million to acquire all such interests in the

F-35

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

Section 29 tax-eligible properties. As a result of the repurchase, the Company recorded, in the first quarter of 2003, a $0.5 million reduction of deferred revenue previously recognized.

18. Condensed consolidating financial information

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

Condensed consolidating balance sheets

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

F-36

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

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

Condensed consolidating statement of income

		Year ended December 31, 2005
												Quicksilver
		Quicksilver		Guarantor			Non-guarantor					Resources Inc.
(amounts in thousands)		Resources Inc.		Subsidiaries			Subsidiaries		Eliminations			Consolidated
Revenues		$	165,194	$	52,678		$	97,044	$	(4,468	)	$	310,448
Operating expenses			111,552		18,243			36,906		(4,468	)		162,233
Income from equity affiliates			62		852			—		—			914
	Income from operations		53,704		35,287			60,138		—			149,129
Equity in net earnings of subsidiaries			61,716		—			—		(61,716	)		—
Interest expense and other			14,174		(43	)		7,024		—			21,155
Income tax provision			13,974		12,366			14,362		—			40,702
Net income from continuing operations			87,272		22,964			38,752		(61,716	)		87,272
Gain from discontinued operations, net			162		—			—		—			—
Net income		$	87,434	$	22,964		$	38,752	$	(61,716	)	$	87,434

F-37

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

Year ended December 31, 2004
												Quicksilver
		Quicksilver		Guarantor			Non-guarantor					Resources Inc.
(amounts in thousands)		Resources Inc.		Subsidiaries			Subsidiaries		Eliminations			Consolidated
Revenues		$	100,126	$	38,099		$	42,925	$	(1,421	)	$	179,729
Operating expenses			87,179		13,641			20,815		(1,421	)		120,214
Income from equity affiliates			75		1,103			—		—			1,178
	Income from operations		13,022		25,561			22,110		—			60,693
	Equity in net earnings of subsidiaries		32,539		—			—		(32,539	)		—
Interest expense and other			13,600		(14	)		1,661		—			15,247
Income tax provision			689		8,951			4,534		—			14,174
Net income		$	31,272	$	16,624		$	15,915	$	(32,539	)	$	31,272

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

F-38

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

Condensed consolidating statements of cash flows

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

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

F-39

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

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

19. Supplemental cash flow information

Cash paid for interest and income taxes is as follows:

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

Other non-cash transactions are as follows:

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

F-40

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

20. Related party transactions

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

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

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

F-41

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

21. Segment information

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

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

22. Supplemental information (unaudited)

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

F-42

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

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

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

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

F-43

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

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

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

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

(in thousands)		United		Canada		Consolidated
		States
2005
Proved acreage		$	821	$	1,620	$	2,441
Unproved acreage			48,419		3,784		52,203
Development costs			24,007		82,388		106,395
Exploration costs			109,148		9,829		118,977
	Total	$	182,395	$	97,621	$	280,016
2004
Proved acreage		$	11,907	$	2,942	$	14,849
Unproved acreage			31,857		7,144		39,001
Development costs			45,213		71,094		116,307
Exploration costs			25,673		22,631		48,304
	Total	$	114,650	$	103,811	$	218,461

F-44

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

		United
(in thousands)		States		Canada		Consolidated
2003
Proved acreage		$	3,215	$	3,388	$	6,603
Unproved acreage			24,063		6,739		30,802
Development costs			37,682		41,820		79,502
Exploration costs			9,411		17,066		26,477
	Total	$	74,371	$	69,013	$	143,384

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

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

The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves (“Standardized Measure”) does not purport to present the fair market value of the Company’s natural gas and crude oil properties. An estimate of

F-45

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

such value should consider, among other factors, anticipated future prices of natural gas and crude oil, the probability of recoveries in excess of existing proved reserves, the value of probable reserves and acreage prospects, and perhaps different discount rates. It should be noted that estimates of reserve quantities, especially from new discoveries, are inherently imprecise and subject to substantial revision.

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

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

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

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

	United
(in thousands)	States			Canada			Consolidated
2005
Future revenues	$	7,387,151		$	2,487,289		$	9,874,440
Future production costs		(1,974,844	)		(494,056	)		(2,468,900	)
Future development costs		(179,141	)		(145,303	)		(324,444	)
Future income taxes		(1,719,136	)		(539,167	)		(2,258,303	)
Future net cash flows		3,514,030			1,308,763			4,822,793
10% discount— calculated difference		(2,283,052	)		(715,609	)		(2,998,661	)
Standardized measure of discounted future net cash flows relating to proved reserves	$	1,230,978		$	593,154		$	1,824,132

F-46

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

	United
(in thousands)	States			Canada			Consolidated
2004
Future revenues	$	4,241,385		$	1,306,819		$	5,548,204
Future production costs		(1,456,005	)		(295,443	)		(1,751,448	)
Future development costs		(116,559	)		(145,297	)		(261,856	)
Future income taxes		(836,557	)		(238,141	)		(1,074,698	)
Future net cash flows		1,832,264			627,938			2,460,202
10% discount— calculated difference		(1,133,990	)		(355,481	)		(1,489,471	)
Standardized measure of discounted future net cash flows relating to proved reserves	$	698,274		$	272,457		$	970,731
2003
Future revenues	$	4,125,685		$	746,722		$	4,872,407
Future production costs		(1,342,167	)		(122,164	)		(1,464,331	)
Future development costs		(117,330	)		(60,696	)		(178,026	)
Future income taxes		(851,337	)		(162,636	)		(1,013,973	)
Future net cash flows		1,814,851			401,226			2,216,077
10% discount— calculated difference		(1,120,056	)		(247,280	)		(1,367,336	)
Standardized measure of discounted future net cash flows relating to proved reserves	$	694,795		$	153,946		$	848,741

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

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

F-47

Quicksilver Resources Inc.

Notes to consolidated financial statements—continued

23. Selected quarterly data (unaudited)

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

F-48

PROSPECTUS

QUICKSILVER RESOURCES INC.

$350,000,000

Senior Debt Securities

Subordinated Debt Securities

Guarantees of Debt Securities

Common Stock

Preferred Stock

Depositary Shares

Warrants

Purchase Contracts

Units

        We may offer from time to time to sell senior or subordinated debt securities, common stock, preferred stock, either separately or represented by depositary shares, warrants and purchase contracts, as well as units that include any of these securities or securities of other entities. This prospectus also covers guarantees, if any, of our payment obligations under any debt securities, which may be given from time to time by one or more of our direct or indirect domestic subsidiaries, on terms to be determined at the time of the offering. Such securities may be offered and sold by us in one or more offerings with a total aggregate principal amount or initial purchase price not to exceed $350,000,000. The debt securities, preferred stock, warrants and purchase contracts may be convertible into or exercisable or exchangeable for common or preferred stock or other of our securities or securities of one or more other entities. Shares of our common stock are traded on the New York Stock Exchange under the symbol “KWK.”

      We may offer and sell these securities to or through one or more underwriters, dealers and agents, or directly to purchasers, on a continuous or delayed basis.

      This prospectus describes some of the general terms that may apply to these securities. The specific terms of any securities to be offered will be described in a supplement to this prospectus.

      Neither the Securities and Exchange Commission nor any other regulatory body has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

The date of this prospectus is March 2, 2006

TABLE OF CONTENTS

	Page
About This Prospectus		2
Where You Can Find More Information		2
Incorporation By Reference		2
Forward-Looking Statements		3
Description of Debt Securities		3
Description of Capital Stock		11
Description of Depositary Shares		15
Description of Warrants		15
Description of Purchase Contracts		16
Description of Units		16
Ratio of Earnings to Fixed Charges		17
Use of Proceeds		17
Certain Legal Matters		17
Experts		17
Reserve Engineers		17

      The registration statement containing this prospectus, including the exhibits to the registration statement, provides additional information about us and the securities offered under this prospectus. The registration statement, including the exhibits and the documents incorporated herein by reference, can be read on the SEC website or at the SEC offices mentioned under the heading “Where You Can Find More Information.”

1

ABOUT THIS PROSPECTUS

      We may from time to time sell the securities in one or more offerings up to a total aggregate principal amount or initial purchase price of $350,000,000. This prospectus provides you with a general description of the securities. Each time we offer the securities, we will provide a prospectus supplement that will contain specific information about the terms of that offering. The prospectus supplement may also supplement, modify, or supersede other information contained in this prospectus. You should read both this prospectus and any prospectus supplement together with the information incorporated by reference as described below under the heading “Incorporation by Reference.”

      You should rely only on the information provided in this prospectus and in any prospectus supplement, including the information incorporated by reference. We have not authorized anyone to provide you with different information. We are not offering the securities in any state where the offer is not permitted. You should not assume that the information in this prospectus, or any supplement to this prospectus, is accurate at any date other than the date indicated on the cover page of these documents.

WHERE YOU CAN FIND MORE INFORMATION

      We file annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission, or SEC. Our SEC filings are available to the public from the SEC’s website 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 in Washington, D.C., located at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room. Information about us is also available at our website at www.qrinc.com. However, the information on our website is not part of this prospectus.

INCORPORATION BY REFERENCE

      The SEC allows us to “incorporate by reference” in this prospectus the information in the documents that we file with it, which means that we can disclose important information to you by referring you to those documents. The information incorporated by reference is considered to be a part of this prospectus. Any information that is part of this prospectus or any prospectus supplement that speaks as of a later date than any other information that is part of this prospectus or any prospectus supplement updates or supersedes such other information. We incorporate by reference in this prospectus the documents listed below and any documents or portions thereof that we file with the SEC after March 2, 2006 under Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934 until we sell all of the securities that may be offered by this prospectus.

•  Our Annual Report on Form 10-K for the fiscal year ended December 31, 2005;

•  Our Current Reports on Form 8-K filed on January 19, 2006, January 31, 2006, February 1, 2006 and February 22, 2006;

•  The description of our common stock, par value $0.01 per share, contained in our Registration Statement on Form 8-A filed on October 11, 2001, including any amendments thereto; and

•  The description of our rights to purchase our Series A Junior Participating Preferred Stock contained in our Registration Statement on Form 8-A filed on March 14, 2003, including any amendments thereto.

      You may obtain, free of charge, a copy of any of these documents (other than exhibits to these documents unless the exhibits are specifically incorporated by reference into these documents or referred to in this prospectus) by writing or calling us at the following address and telephone number:

Diane Weaver

Director of Investor Relations

Quicksilver Resources Inc.

777 West Rosedale Street, Suite 300

Fort Worth, Texas 76104

(817) 665-5000

2

FORWARD-LOOKING STATEMENTS

      Some of the statements made and information contained in this prospectus and the documents we incorporate by reference, excluding historical information, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements give our current expectations or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Any of the following factors may impact the achievement of results:

•  changes in general economic conditions;

•  fluctuations in natural gas and crude oil prices;

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

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

•  effects of hedging natural gas and crude oil prices;

•  competitive conditions in our industry;

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

•  changes in the availability and cost of capital;

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

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

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

•  the effects of existing or future litigation.

      This list of factors is not exhaustive, and new factors may emerge or changes to these factors may occur that would impact our business. Additional information regarding these and other factors may be contained in our filings with the SEC, especially on Forms 10-K, 10-Q and 8-K. All such risk factors are difficult to predict, contain material uncertainties that may affect actual results and may be beyond our control.

DESCRIPTION OF DEBT SECURITIES

General

      The debt securities that we may offer by this prospectus consist of unsecured notes, debentures, or other evidences of indebtedness of Quicksilver, which we refer to as “debt securities.” We may issue debt securities in one or more series under an indenture, dated as of December 22, 2005, between us and JPMorgan Chase Bank, as trustee. A copy of the indenture is filed as Exhibit 4.7 to the registration statement of which this prospectus is a part and is incorporated herein by reference. Except as otherwise defined in this prospectus, capitalized terms used in this prospectus have the meanings given to them in the indenture.

      The provisions of the indenture will generally be applicable to all of the debt securities. Selected provisions of the indenture are described in this prospectus. Additional or different provisions that are applicable to a particular series of debt securities will, if material, be described in a prospectus supplement

3

relating to the offering of debt securities of that series. These provisions may include, among other things and to the extent applicable, the following:

•  the title of the debt securities;

•  the extent, if any, to which the debt securities are subordinated in right of payment to other indebtedness of Quicksilver;

•  any limit on the aggregate principal amount of the debt securities;

•  any guarantees applicable to the debt securities, and any subordination provisions or other limitations applicable to any such guarantees;

•  the persons to whom any interest on the debt securities will be payable, if other than the registered holders thereof on the regular record date therefor;

•  the date or dates on which the principal of the debt securities will be payable;

•  the rate or rates at which the debt securities will bear interest, if any, and the date or dates from which interest will accrue;

•  the dates on which interest will be payable and the regular record dates for interest payment dates;

•  the place or places where the principal of and any premium and interest on the debt securities will be payable;

•  the period or periods, if any, within which, and the price or prices at which, the debt securities may be redeemed, in whole or in part, at our option;

•  our obligation, if any, to redeem or purchase the debt securities pursuant to sinking fund or similar provisions and the terms and conditions of any such redemption or purchase;

•  the denominations in which the debt securities will be issuable, if other than denominations of $1,000 and any integral multiple thereof;

•  the currency, currencies or currency units, if other than currency of the United States of America, in which payment of the principal of and any premium or interest on the debt securities will be payable, and the terms and conditions of any elections that may be made available with respect thereto;

•  any index or formula used to determine the amount of payments of principal of and any premium or interest on the debt securities;

•  whether the debt securities are to be issued in whole or in part in the form of one or more global securities and, if so, the identity of the depositary, if any, for the global securities;

•  the terms and conditions, if any, pursuant to which the debt securities are convertible into or exchangeable for the common stock or other securities of Quicksilver or any other person;

•  the principal amount (or any portion of the principal amount) of the debt securities which will be payable upon any declaration of acceleration of the maturity of the debt securities pursuant to an event of default; and

•  the applicability to the debt securities of the provisions described in “— Defeasance” below.

      We may issue debt securities at a discount from their stated principal amount. Federal income tax considerations and other special considerations applicable to any debt security issued with original issue discount (an “original issue discount security”) may be described in an applicable prospectus supplement.

      If the purchase price of any series of the debt securities is payable in a foreign currency or currency unit or if the principal of or any premium or interest on any series of the debt securities is payable in a foreign currency or currency unit, the restrictions, elections, general tax considerations, specific terms, and other information with respect to the debt securities and the applicable foreign currency or currency unit will be set forth in an applicable prospectus supplement.

4

      Unless otherwise indicated in an applicable prospectus supplement:

•  the debt securities will be issued only in fully registered form (without coupons) in denominations of $1,000 or integral multiples thereof; and

•  payment of principal, premium, if any, and interest on the debt securities will be payable, and the exchange, conversion, and transfer of debt securities will be registrable, at our office or agency maintained for those purposes and at any other office or agency maintained for those purposes. No service charge will be made for any registration of transfer or exchange of the debt securities, but we may require payment of a sum sufficient to cover any tax or other governmental charge imposed in connection therewith.

Guarantees

      Debt securities may be guaranteed by one or more of our direct or indirect domestic subsidiaries, if so provided in the applicable prospectus supplement. The prospectus supplement relating to the debt securities of a particular series may describe the terms of any guarantees, including, among other things, the method for determining the identity of the guarantors and the conditions under which guarantees will be added or released. Any guarantees may be joint and several obligations of the guarantors.

Global Securities

      The debt securities of a series may be issued in whole or in part in the form of one or more global securities that will be deposited with, or on behalf of, a depositary or its nominee identified in an applicable prospectus supplement. Unless and until it is exchanged in whole or in part for debt securities in registered form, a global security may not be registered for transfer or exchange except:

•  by the depositary to a nominee of the depositary;

•  by a nominee of the depositary to the depositary or another nominee of the depositary;

•  by the depositary or any nominee of the depositary to a successor depositary or a nominee of the successor depositary; or

•  in any other circumstances described in an applicable prospectus supplement.

      The specific terms of the depositary arrangement with respect to any debt securities to be represented by a global security will be described in an applicable prospectus supplement. We expect that the following provisions will apply to depositary arrangements.

      Unless otherwise specified in an applicable prospectus supplement, any global security that represents debt securities will be registered in the name of the depositary or its nominee. Upon the deposit of a global security with or on behalf of the depositary for the global security, the depositary will credit, on its book-entry registration and transfer system, the respective principal amounts of the debt securities represented by the global security to the accounts of institutions that are participants in such system. The accounts to be credited will be designated by the underwriters or agents of the debt securities or by us, if the debt securities are offered and sold directly by us.

      Ownership of beneficial interests in debt securities represented by a global security will be limited to participants in the book-entry registration and transfer system of the applicable depositary or persons that may hold interests through those participants. Ownership of those beneficial interests by participants will be shown on, and the transfer of ownership will be effected only through, records maintained by the depositary or its nominee for such global security. Ownership of such beneficial interests by persons that hold through such participants will be shown on, and the transfer of such ownership will be effected only through, records maintained by the participants. The laws of some jurisdictions require that specified purchasers of securities take physical delivery of their securities in definitive form. These laws may impair your ability to transfer beneficial interests in a global security.

5

      So long as the depositary for a global security, or its nominee, is the registered owner of the global security, the depositary or the nominee, as the case may be, will be considered the sole owner or holder of the debt securities represented by the global security for all purposes under the indenture. Unless otherwise specified in an applicable prospectus supplement, owners of beneficial interests in the global security will not be entitled to have any of the debt securities represented by the global security registered in their names, will not receive or be entitled to receive physical delivery of any such debt securities in certificated form, and will not be considered the owners or holders of the debt securities for any purpose under the indenture. Accordingly, each person owning a beneficial interest in debt securities represented by a global security must rely on the procedures of the applicable depositary and, if the person is not a participant in the book-entry registration and transfer system of the applicable depositary, on the procedures of the participant through which the person owns its interest, to exercise any rights of an owner or holder of debt securities under the indenture.

      We understand that, under existing industry practices, if an owner of a beneficial interest in debt securities represented by a global security desires to give any notice or take any action that an owner or holder of debt securities is entitled to give or take under the indenture:

•  the applicable depositary would authorize its participants to give the notice or take the action; and

•  the participants would authorize persons owning the beneficial interests through the participants to give the notice or take the action or would otherwise act upon the instructions of the persons owning the beneficial interests.

      Principal of and any premium and interest on debt securities represented by a global security will be payable in the manner described in an applicable prospectus supplement. Payment of principal of, and any premium or interest on, debt securities represented by a global security will be made to the applicable depositary or its nominee, as the case may be, as the registered owner or the holder of the global security. None of us, the trustee, any paying agent, or the registrar for debt securities represented by a global security will have any responsibility or liability for any aspect of the records relating to or payments made on account of beneficial ownership interests in those debt securities or for maintaining, supervising, or reviewing any records relating to those beneficial ownership interests.

Certain Covenants of Quicksilver

      Maintenance of Office or Agency. We will be required to maintain an office or agency in each place of payment for each series of debt securities for notice and demand purposes and for the purposes of presenting or surrendering debt securities for payment, registration of transfer, or exchange.

      Paying Agents, Etc. If we act as our own paying agent with respect to any series of debt securities, on or before each due date of the principal of or interest on any of the debt securities of that series, we will be required to segregate and hold in trust for the benefit of the persons entitled to payment a sum sufficient to pay the amount due and to notify the trustee promptly of our action or failure to act. If we have one or more paying agents for any series of debt securities, prior to each due date of the principal of or interest on any debt securities of that series, we will be required to deposit with a paying agent a sum sufficient to pay the amount due and, unless the paying agent is the trustee, to promptly notify the trustee of our action or failure to act. All moneys paid by us to a paying agent for the payment of principal of or interest on any debt securities that remain unclaimed for two years after the principal or interest has become due and payable may be repaid to us, and thereafter the holder of those debt securities may look only to us for payment thereof.

      Existence. We will be required to, and will be required to cause our subsidiaries to, preserve and keep in full force and effect our and their existence, charter rights, statutory rights, and franchises, except to the extent that the failure to do so would not have a Material Adverse Effect.

      Restrictive Covenants. Any restrictive covenants applicable to any series of debt securities will be described in an applicable prospectus supplement.

6

Events of Default

      The following are Events of Default under the indenture with respect to debt securities of any series:

      (1) failure to pay principal of or premium, if any, on any debt security of that series when due;

      (2) failure to pay any interest on any debt security of that series when due, which failure continues for 30 calendar days;

      (3) failure to make any sinking fund payment when and as due by the terms of any debt security of that series;

      (4) failure to redeem any debt security of that series when required to do so under the terms thereof;

      (5) failure to perform, or breach of, any other of our covenants in the indenture (other than a covenant included in the indenture solely for the benefit of a series of debt securities other than that series), which failure or breach continues for 60 calendar days after written notice thereof has been given to us as provided in the indenture;

      (6) any nonpayment at maturity or other default (beyond any applicable grace period) under any agreement or instrument relating to any other of our or certain of our subsidiaries’ indebtedness, the unpaid principal amount of which is not less than $15 million, which default results in the acceleration of the maturity of the indebtedness prior to its stated maturity or occurs at the final maturity thereof;

      (7) specified events of bankruptcy, insolvency, or reorganization involving us or certain of our subsidiaries; and

      (8) any other Event of Default provided with respect to debt securities of that series.

      Pursuant to the Trust Indenture Act, the trustee is required, within 90 calendar days after the occurrence of a default in respect of any series of debt securities, to give to the holders of the debt securities of that series notice of all uncured defaults known to it, except that:

•  in the case of a default in the performance of any covenant of the character contemplated in clause (5) above, no notice will be given until at least 30 calendar days after the occurrence of the default; and

•  other than in the case of a default of the character contemplated in clause (1), (2), or (3) above, the trustee may withhold notice if and so long as it in good faith determines that the withholding of notice is in the interests of the holders of the debt securities of that series.

      If an Event of Default described in clause (7) above occurs, the principal of, premium, if any, and accrued interest on the debt securities of that series will become immediately due and payable without any declaration or other act on the part of the trustee or any holder of the debt securities of that series. If any other Event of Default with respect to debt securities of any series occurs and is continuing, either the trustee or the holders of at least 25% in principal amount of the debt securities of that series may declare the principal amount of all debt securities of that series to be due and payable immediately. However, at any time after a declaration of acceleration with respect to debt securities of any series has been made, but before a judgment or decree based on such acceleration has been obtained, the holders of a majority in principal amount of the debt securities of that series may, under specified circumstances, rescind and annul such acceleration. See “— Modification and Waiver” below.

      Subject to the duty of the trustee to act with the required standard of care during an Event of Default, the trustee will have no obligation to exercise any of its rights or powers under the indenture at the request or direction of the holders of debt securities, unless holders of debt securities shall have furnished to the trustee reasonable security or indemnity. Subject to the provisions of the indenture, including those requiring security or indemnification of the trustee, the holders of a majority in principal amount of the debt securities of any series will have the right to direct the time, method, and place of conducting any proceeding for any remedy available to the trustee, or exercising any trust or power conferred on the trustee, with respect to the debt securities of that series.

7

      No holder of a debt security of any series will have any right to institute any proceeding with respect to the indenture or for any remedy thereunder unless:

•  the holder has previously given to the trustee written notice of a continuing Event of Default;

•  the holders of at least 25% in aggregate principal amount of the outstanding debt securities of the same series have requested the trustee to institute a proceeding in respect of the Event of Default;

•  the holder or holders have furnished reasonable indemnity to the trustee to institute the proceeding as trustee;

•  the trustee has not received from the holders of a majority in principal amount of the outstanding debt securities of the same series a direction inconsistent with the request; and

•  the trustee has failed to institute the proceeding within 60 calendar days.

      However, the limitations described above do not apply to a suit instituted by a holder of a debt security for enforcement of payment of the principal of and interest on such debt security on or after the applicable due dates for the payment of such principal and interest.

      We are required to furnish to the trustee annually a statement as to our performance of our obligations under the indenture and as to any default in our performance.

      Any additional Events of Default with respect to any series of debt securities, and any variations from the foregoing Events of Default applicable to any series of debt securities, will be described in an applicable prospectus supplement.

Modification and Waiver

      In general, modifications and amendments of the indenture may be made by us and the trustee with the consent of the holders of not less than a majority in principal amount of the debt securities of each series affected thereby. However, no modification or amendment of the indenture may, without the consent of the holder of each debt security affected thereby:

•  change the stated maturity of, or any installment of principal of, or interest on, any debt security;

•  reduce the principal amount of, the rate of interest on, or the premium, if any, payable upon the redemption of, any debt security;

•  reduce the amount of principal of an original issue discount security payable upon acceleration of the maturity thereof;

•  change the place or currency of payment of principal of, or premium, if any, or interest on any debt security;

•  impair the right to institute suit for the enforcement of any payment on or with respect to any debt security on or after the stated maturity or prepayment date thereof; or

•  reduce the percentage in principal amount of debt securities of any series required for modification or amendment of the indenture or for waiver of compliance with certain provisions of the indenture or for waiver of certain defaults.

      The holders of at least a majority in principal amount of the debt securities of any series may, on behalf of the holders of all debt securities of that series, waive our compliance with specified covenants of the indenture. The holders of at least a majority in principal amount of the debt securities of any series may, on behalf of the holders of all debt securities of that series, waive any past default under the indenture with respect to that series, except:

•  a default in the payment of the principal of, or premium, if any, or interest on, any debt security of that series; or

8

•  a default of a provision of the indenture that cannot be modified or amended without the consent of the holder of each debt security of that series.

Defeasance

      Unless otherwise specified in a prospectus supplement applicable to a particular series of debt securities and except as described below, upon compliance with the applicable requirements described below, we:

      (1) will be deemed to have been discharged from our obligations with respect to the debt securities of that series; or

      (2) will be released from our obligations to comply with certain covenants described under “— Certain Covenants of Quicksilver” above with respect to the debt securities of that series, and the occurrence of an event described in any of clauses (3), (4), (5), (6), and (8) under “— Events of Default” above will no longer be an Event of Default with respect to the debt securities of that series except to the limited extent described below.

      Following any defeasance described in clause (1) or (2) above, we will continue to have specified obligations under the indenture, including obligations to register the transfer or exchange of debt securities of the applicable series; replace destroyed, stolen, lost, or mutilated debt securities of the applicable series; maintain an office or agency in respect of the debt securities of the applicable series; and hold funds for payment to holders of debt securities of the applicable series in trust. In the case of any defeasance described in clause (2) above, any failure by us to comply with our continuing obligations may constitute an Event of Default with respect to the debt securities of the applicable series as described in clause (5) under “— Events of Defaults” above.

      In order to effect any defeasance described in clause (1) or (2) above, we must irrevocably deposit with the trustee, in trust, money or specified government obligations (or depositary receipts therefor) that through the payment of principal and interest in accordance with their terms will provide money in an amount sufficient to pay all of the principal of, premium, if any, and interest on the debt securities of such series on the dates such payments are due in accordance with the terms of such debt securities. In addition:

•  no Event of Default or event which with the giving of notice or lapse of time, or both, would become an Event of Default under the indenture shall have occurred and be continuing on the date of such deposit;

•  no Event of Default described in clause (7) under “— Events of Default” above or event that with the giving of notice or lapse of time, or both, would become an Event of Default described in such clause (7) shall have occurred and be continuing at any time on or prior to the 90^th calendar day following the date of deposit;

•  in the event of any defeasance described in clause (1) above, we shall have delivered an opinion of counsel, stating that (a) we have received from, or there has been published by, the IRS a ruling or (b) there has been a change in applicable federal law, in either case to the effect that, among other things, the holders of the debt securities of such series will not recognize gain or loss for United States federal income tax purposes as a result of such deposit or defeasance and will be subject to United States federal income tax in the same manner as if such defeasance had not occurred; and

•  in the event of any defeasance described in clause (2) above, we shall have delivered an opinion of counsel to the effect that, among other things, the holders of the debt securities of such series will not recognize gain or loss for United States federal income tax purposes as a result of such deposit or defeasance and will be subject to United States federal income tax in the same manner as if such defeasance had not occurred.

      If we fail to comply with our remaining obligations under the indenture with respect to the debt securities of the applicable series following a defeasance described in clause (2) above and the debt securities of that series are declared due and payable because of the occurrence of any undefeased Event of Default, the amount of money and government obligations on deposit with the trustee may be insufficient to pay amounts

9

due on the debt securities of that series at the time of the acceleration resulting from such Event of Default. However, we will remain liable in respect of such payments.

Satisfaction and Discharge

      We, at our option, may satisfy and discharge the indenture (except for specified obligations of us and the trustee, including, among others, the obligations to apply money held in trust) when:

•  either:

      (1) all of our debt securities previously authenticated and delivered under the indenture (subject to specified exceptions relating to debt securities that have otherwise been satisfied or provided for) have been delivered to the trustee for cancellation; or

      (2) all of our debt securities not previously delivered to the trustee for cancellation have become due and payable, will become due and payable at their stated maturity within one year, or are to be called for redemption within one year under arrangements satisfactory to the trustee for the giving of notice of redemption by the trustee, and we have deposited or caused to be deposited with the trustee as trust funds for such purpose an amount sufficient to pay and discharge the entire indebtedness on such debt securities, for principal and any premium and interest to the date of such deposit (in the case of debt securities which have become due and payable) or to the stated maturity or redemption date, as the case may be;

•  we have paid or caused to be paid all other sums payable by us under the indenture; and

•  we have delivered to the trustee an officer’s certificate and an opinion of counsel, each to the effect that all conditions precedent relating to the satisfaction and discharge of the indenture have been satisfied.

Limitations on Merger and Other Transactions

      Prior to the satisfaction and discharge of the indenture, we may not consolidate with or merge with or into any other person, or transfer all or substantially all of our properties and assets to another person unless:

•  either

      (1) we are the continuing or surviving person in the consolidation or merger; or

      (2) the person (if other than us) formed by the consolidation or into which we are merged or to which all or substantially all of our properties and assets are transferred is a corporation, partnership, limited liability company, business trust, trust or other legal entity organized and validly existing under the laws of the United States, any State thereof, or the District of Columbia, and expressly assumes, by a supplemental indenture, all of our obligations under the debt securities and the indenture;

•  immediately after the transaction and the incurrence or anticipated incurrence of any indebtedness to be incurred in connection therewith, no Event of Default exists; and

•  an officer’s certificate is delivered to the trustee to the effect that both of the conditions set forth above have been satisfied and an opinion of outside counsel has been delivered to the trustee to the effect that the first condition set forth above has been satisfied.

      The continuing, surviving, or successor person will succeed to and be substituted for us with the same effect as if it had been named in the indenture as a party thereto, and thereafter the predecessor person will be relieved of all obligations and covenants under the indenture and the debt securities.

Governing Law

      The indenture is, and the debt securities will be, governed by, and construed in accordance with, the laws of the State of New York.

10

Regarding the Trustee

      The indenture contains specified limitations on the right of the trustee, should it become our creditor within three months of, or subsequent to, a default by us to make payment in full of principal of or interest on any series of debt securities issued pursuant to the indenture when and as the same becomes due and payable, to obtain payment of claims, or to realize for its own account on property received in respect of any such claim as security or otherwise, unless and until such default is cured. However, the trustee’s rights as our creditor will not be limited if the creditor relationship arises from, among other things:

•  the ownership or acquisition of securities issued under any indenture or having a maturity of one year or more at the time of acquisition by the trustee;

•  specified advances authorized by a receivership or bankruptcy court of competent jurisdiction or by the indenture;

•  disbursements made in the ordinary course of business in its capacity as indenture trustee, transfer agent, registrar, custodian, or paying agent or in any other similar capacity;

•  indebtedness created as a result of goods or securities sold in a cash transaction or services rendered or premises rented; or

•  the acquisition, ownership, acceptance, or negotiation of specified drafts, bills of exchange, acceptances, or other obligations.

      The indenture does not prohibit the trustee from serving as trustee under any other indenture to which we may be a party from time to time or from engaging in other transactions with us. If the trustee acquires any conflicting interest within the meaning of the Trust Indenture Act of 1939 and there is an Event of Default with respect to any series of debt securities, the trustee must eliminate the conflict or resign.

DESCRIPTION OF CAPITAL STOCK

      Our authorized capital stock consists of 100,000,000 shares of common stock, par value $0.01 per share, and 10,000,000 shares of preferred stock, par value $0.01 per share.

Common Stock

      Subject to the restrictions described below, the holders of our common stock are entitled to receive dividends from funds legally available when, as and if declared by our board of directors, and are entitled upon our liquidation, dissolution or winding up to receive pro rata our net assets after satisfaction in full of the prior rights of our creditors and holders of any preferred stock.

      Except as otherwise provided by law and subject to the voting rights of our preferred stock of any series that may be outstanding from time to time, the holders of common stock are entitled to one vote for each share held on all matters as to which stockholders are entitled to vote. The holders of common stock do not have cumulative voting rights. The holders of common stock do not have any preferential, subscriptive or preemptive rights to subscribe to or purchase any new or additional issue of shares of any class of stock or of securities convertible into our stock or any conversion rights with respect to any of our securities. Our common stock is not subject to redemption. All of our issued and outstanding common stock is fully paid and non-assessable.

11

Preferred Stock

      Our restated certificate of incorporation authorizes our board of directors to establish one or more series of preferred stock and to determine, with respect to any series of preferred stock, the terms and rights of the series, including the following:

•  the designation of the series;

•  the rate and time of, and conditions and preferences with respect to, dividends, and whether the dividends will be cumulative;

•  the voting rights, if any, of shares of the series;

•  the price, timing and conditions regarding the redemption of shares of the series and whether a sinking fund should be established for the series;

•  the rights and preferences of shares of the series in the event of voluntary or involuntary dissolution, liquidation or winding up of our affairs; and

•  the right, if any, to convert or exchange shares of the series into or for stock or securities of any other series or class.

      We have designated one share of our authorized preferred stock as special voting stock. As of the date of this prospectus, this share of special voting stock is not issued and outstanding.

      In connection with our stockholder rights agreement, discussed below, we designated 100,000 shares of our authorized preferred stock as Series A junior participating preferred stock. We have not issued any shares of Series A junior participating preferred stock.

Purposes and Effects of Certain Provisions of Our Restated Certificate of Incorporation and Restated Bylaws

General

      Our restated certificate of incorporation and restated bylaws contain provisions that could make more difficult the acquisition of control of our company by means of a tender offer, open market purchases, a proxy contest or otherwise. A description of these provisions is set forth below.

Preferred Stock

      We believe that the availability of the preferred stock under our restated certificate of incorporation will provide us with flexibility in structuring possible future financings and acquisitions and in meeting other corporate needs which might arise. Having these authorized shares available for issuance will allow us to issue shares of preferred stock without the expense and delay of a special stockholders’ meeting. The authorized shares of preferred stock, as well as shares of common stock, will be available for issuance without further action by our stockholders, unless action is required by applicable law or the rules of any stock exchange on which our securities may be listed. The board of directors has the power, subject to applicable law, to issue series of preferred stock that could, depending on the terms of the series, impede the completion of a merger, tender offer or other takeover attempt. For instance, subject to applicable law, series of preferred stock might impede a business combination by including class voting rights which would enable the holder or holders of such series to block a proposed transaction. Our board of directors will make any determination to issue shares based on its judgment as to our and our stockholders’ best interests. Our board of directors, in so acting, could issue preferred stock having terms which could discourage an acquisition attempt or other transaction that some, or a majority, of the stockholders might believe to be in their best interests or in which stockholders might receive a premium for their stock over the then prevailing market price of the stock.

12

Classified Board of Directors; Removable Only for Cause

      Our restated certificate of incorporation divides our board of directors into three classes of directors, with each class serving staggered, three-year terms. In addition, our directors may be removed from office only for cause by a vote of at least 66²/3% in voting power of the then-outstanding shares of our voting stock entitled to vote in the election of directors, voting together as a single group. The classification of our board of directors means that, unless directors are removed for cause, it could require at least two annual meetings of stockholders for a majority of stockholders to make a change of control of the board of directors, because only a portion of the directors will be elected at each meeting. A significant effect of a classified board of directors may be to deter hostile takeover attempts, because an acquiror could experience delay in replacing a majority of the directors. A classified board of directors also makes it more difficult for stockholders to effect a change of control of the board of directors, even if such a change of control were to be sought due to dissatisfaction with the performance of our company’s directors.

Supermajority Voting

      Our restated certificate of incorporation requires the approval of the holders of at least 66²/3% of the then-outstanding shares of our voting stock entitled to vote in the election of directors, voting together as a single group, to amend, alter or repeal any provision of:

•  our restated certificate of incorporation governing the election and removal of directors; and

•  our restated certificate of incorporation prohibiting stockholder actions by written consent.

Limitation of Director Liability

      Our restated certificate of incorporation limits the liability of directors to our company and our stockholders to the fullest extent permitted by Delaware law. Specifically, a director will not be personally liable for monetary damages for breach of his or her fiduciary duty as a director, except for liability for:

•  any breach of the director’s duty of loyalty to our company or our stockholders;

•  acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law;

•  violations under Section 174 of the Delaware General Corporation Law, which relates to unlawful payments of dividends or unlawful stock repurchases or redemptions; or

•  any transaction from which the director derived an improper personal benefit.

      These provisions in our restated certificate of incorporation may have the effect of reducing the likelihood of derivative litigation against our directors and may discourage or deter stockholders or management from bringing a lawsuit against our directors for breach of their duty of care, even though such an action, if successful, might otherwise have benefited our company and its stockholders. These provisions do not limit or affect a stockholder’s ability to seek and obtain relief under federal securities laws.

No Stockholder Action by Written Consent

      Our restated certificate of incorporation provides that any action required or permitted to be taken at any annual or special meeting of stockholders may be taken only at a duly called annual or special meeting of stockholders and may not be effected by a written consent of stockholders in lieu of a meeting of stockholders. This prevents stockholders from initiating or effecting any action by written consent, thereby limiting the ability of stockholders to take actions opposed by our board of directors.

Special Meetings of Stockholders

      Our restated bylaws provide that special meetings of stockholders may be called only by our board of directors, our chairman of the board or our president.

13

Stockholders Rights Agreement

      On March 11, 2003, our board of directors adopted a Rights Agreement (referred to herein as the stockholders rights agreement) between us and Mellon Investor Services LLC, as rights agent, and declared a dividend of one right for each outstanding share of common stock, payable to stockholders of record at the close of business on March 26, 2003. The stockholders rights agreement provides that each share issued after March 26, 2003 and prior to the time that the rights expire, are redeemed or become exercisable (whichever occurs first) will be accompanied by one right. On December 20, 2005, the stockholder rights agreement was amended and restated to, among other things, increase the exercise price of the rights to $180 per right, subject to adjustment as provided in the stockholder rights agreement.

      The rights are not exercisable until the earlier of:

•  the first date of public announcement of a person or group of affiliated or associated persons (referred to herein as an acquiring person) having acquired beneficial ownership of 15% or more of our outstanding common shares, except pursuant to a permitted offer or if such person or group is a grandfathered stockholder; or

•  10 days, or such later date as our board of directors may determine, following the commencement of, or first public announcement of an intention to make, a tender offer or exchange offer, the consummation of which would result in a person or group becoming an acquiring person.

      We are entitled to redeem the rights in exchange for a payment (currently $0.01 per right, but subject to possible adjustment) at any time prior to the earlier to occur of:

•  a person becoming an acquiring person; or

•  the expiration of the rights.

      If the rights become exercisable, a holder of rights (other than rights beneficially owned by an acquiring person, which rights would be void), would be entitled to buy a number of shares of our common stock or, if certain transactions involving an acquisition of our company or its assets have occurred, the common stock of the acquiring company, having a market value of twice the exercise price of each right (currently $180, but subject to possible adjustment). Holders of shares of our common stock who do not exercise their rights in such circumstances will experience dilution of their investment in the company. The rights under the stockholders rights agreement expire on March 11, 2013, unless earlier redeemed or exchanged. Until a right is exercised, the holder has no rights as a stockholder including, without limitation, the right to vote as a stockholder or to receive dividends.

      We are entitled to amend the rights, without restriction and without the approval of any holders of shares of our common stock, at any time or from time to time prior to the rights becoming exercisable. After the rights become exercisable, our ability to amend the rights is subject to specified restrictions.

Section 203 of the Delaware General Corporation Law

      We are subject to Section 203 of the Delaware General Corporation Law. Section 203 prohibits publicly held Delaware corporations from engaging in a “business combination” with an “interested stockholder” for a period of three years following the time of the transaction in which the person or entity became an interested stockholder, unless:

•  prior to that time, either the business combination or the transaction which resulted in the stockholder becoming an interested stockholder is approved by the board of directors of the corporation;

•  upon consummation of the transaction which resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the outstanding voting stock of the corporation, excluding for this purpose shares owned by persons who are directors and also officers of the corporation and by specified employee benefit plans; or

14

•  at or after such time the business combination is approved by the board of directors of the corporation and by the affirmative vote of at least 66²/3% of the outstanding voting stock which is not owned by the interested stockholder.

      For the purposes of Section 203, a “business combination” is broadly defined to include mergers, asset sales and other transactions resulting in a financial benefit to the interested stockholder. An “interested stockholder” is a person who, together with affiliates and associates, owns or within the immediately preceding three years did own 15% or more of the corporation’s voting stock.

Transfer Agent and Registrar

      The transfer agent and registrar for our common stock is Mellon Investor Services LLC.

DESCRIPTION OF DEPOSITARY SHARES

      We may offer depositary shares (either separately or together with other securities) representing fractional shares of preferred stock of any series. In connection with the issuance of any depositary shares, we will enter into a deposit agreement with a bank or trust company, as depositary, which will be named in the applicable prospectus supplement. Depositary shares will be evidenced by depositary receipts issued pursuant to the related deposit agreement. Immediately following our issuance of the security related to the depositary shares, we will deposit the shares of preferred stock with the relevant depositary and will cause the depositary to issue, on our behalf, the related depositary receipts. Subject to the terms of the deposit agreement, each owner of a depositary receipt will be entitled, in proportion to the fraction of a share of preferred stock represented by the related depositary share, to all the rights, preferences and privileges of, and will be subject to all of the limitations and restrictions on, the preferred stock represented by the depositary receipt (including, if applicable, dividend, voting, conversion, exchange, redemption, sinking fund, repayment at maturity, subscription and liquidation rights).

DESCRIPTION OF WARRANTS

      We may issue warrants for the purchase of debt securities, common stock, preferred stock, depositary shares, or any combination thereof. We may issue warrants independently or together with any other securities offered by a prospectus supplement. Warrants may be attached to or separate from such securities. Each series of warrants will be issued under a separate warrant agreement we will enter into with a warrant agent specified in the applicable prospectus supplement. The warrant agent will act solely as our agent in connection with the warrants of a particular series and will not assume any obligation or relationship of agency or trust for or with any holders or beneficial owners of warrants.

      The applicable prospectus supplement will describe the terms of the warrants in respect of which this prospectus is being delivered, including, to the extent applicable, the following:

•  the title of the warrants;

•  the aggregate number of the warrants;

•  the price or prices at which the warrants will be issued;

•  the designation, number or principal amount and terms of the debt securities, common stock, preferred stock, and/or depositary shares purchasable upon exercise of the warrants;

•  the designation and terms of the other securities, if any, with which the warrants are issued and the number of warrants issued with each security;

•  the date, if any, on and after which the warrants and the related underlying securities will be separately transferable;

•  whether the warrants will be issued in registered form or bearer form;

15

•  the price at which each underlying security purchasable upon exercise of the warrants may be purchased;

•  the date on which the right to exercise the warrants will commence and the date on which that right will expire;

•  the identity of the warrant agent;

•  the maximum or minimum number of the warrants that may be exercised at any one time;

•  information with respect to book-entry procedures, if any;

•  a discussion of any material federal income tax considerations; and

•  any other terms of the warrants, including terms, procedures, and limitations relating to the transferability, exchange, and exercise of the warrants.

DESCRIPTION OF PURCHASE CONTRACTS

      We may issue purchase contracts, including contracts obligating holders to purchase from us, and for us to sell to holders, a specific or varying number of debt securities, shares of our common stock or preferred stock, depositary shares, warrants or securities of an entity unaffiliated with us, or any combination of the above, at a future date or dates. Alternatively, the purchase contracts may obligate us to purchase from holders, and obligate holders to sell to us, a specific or varying number of shares of debt securities, shares of our common stock or preferred stock, depositary shares, warrants or other property. The price per share of preferred stock or common stock or price of other securities may be fixed at the time the purchase contracts are issued or may be determined by reference to a specific formula described in the purchase contracts. We may issue purchase contracts separately or as a part of units each consisting of a purchase contract and debt securities, preferred securities, warrants or debt obligations of third parties, including U.S. Treasury securities, securing the holder’s obligations under the purchase contract. The purchase contracts may require us to make periodic payments to holders or vice versa and the payments may be unsecured or pre-funded on some basis. The purchase contracts may require holders to secure the holder’s obligations in a specified manner that we will file with the SEC in connection with a public offering relating to the purchase contracts.

      The applicable prospectus supplement will describe the terms of any purchase contracts in respect of which this prospectus is being delivered, including, to the extent applicable, the following:

•  whether the purchase contracts obligate the holder or us to purchase or sell, or both purchase and sell the securities subject to purchase under the purchase contract, and the nature and amount of each of those securities, or the method of determining those amounts;

•  whether the purchase contracts are to be prepaid or not;

•  whether the purchase contracts are to be settled by delivery, or by reference or linkage to the value, performance or level of the securities subject to purchase under the purchase contract;

•  any acceleration, cancellation, termination or other provisions relating to the settlement of the purchase contracts; and

•  whether the purchase contracts will be issued in fully registered or global form.

DESCRIPTION OF UNITS

      We may issue units comprising one or more securities described in this prospectus in any combination. Units may also include debt obligations of third parties, such as U.S. Treasury securities. Each unit will be issued so that the holder of the unit also is the holder of each security included in the unit. Thus, the unit will have the rights and obligations of a holder of each included security. The unit agreement under which a unit is issued may provide that the securities included in the unit may not be held or transferred separately at any time or at any time before a specified date.

16

      The applicable prospectus supplement will describe the terms of any units in respect of which this prospectus is being delivered, including, to the extent applicable, the following:

•  the designation and terms of the units and the securities comprising the units, including whether and under what circumstances those securities may be held or transferred separately;

•  any provision for the issuance, payment, settlement, transfer or exchange of the units or of the securities comprising the units; and

•  whether the units will be issued in fully registered or global form.

RATIO OF EARNINGS TO FIXED CHARGES

      The following table shows our historical ratio of earnings to fixed charges for each of the five fiscal years ended December 31, 2005, 2004, 2003, 2002 and 2001. For the purposes of calculating the ratio of earnings to fixed charges, “earnings” represents income from continuing operations before income taxes before income from equity investees plus distributed earnings from equity investees and fixed charges. “Fixed charges” consist of interest expense, including amortization of debt issuance costs and that portion of rental expense considered to be a reasonable approximation of interest.

Year Ended December 31,
2005		2004		2003		2002		2001
	6.8x		3.8x		2.4x		2.3x		2.2x

USE OF PROCEEDS

      We intend to use the net proceeds from the sales of the securities as set forth in the applicable prospectus supplement.

CERTAIN LEGAL MATTERS

      In connection with particular offerings of the securities in the future, and if stated in the applicable prospectus supplements, the validity of those securities may be passed upon for us by John C. Cirone, our Senior Vice President, General Counsel and Secretary, or by Jones Day and for any underwriters or agents by counsel named in the applicable prospectus supplement. Certain legal matters in connection with the possible issuance of guarantees by one or more of our subsidiaries may be passed upon for us by Loomis, Ewert, Parsley, Davis & Gotting P.C., with respect to Michigan law, and McGuireWoods LLP, with respect to Virginia law.

EXPERTS

      The consolidated financial statements and management’s report on the effectiveness of internal control over financial reporting incorporated into this prospectus by reference from our Annual Report on Form 10-K for the year ended December 31, 2005 have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their reports (which report on the consolidated financial statements expresses an unqualified opinion and includes an explanatory paragraph related to the adoption of Statement of Financial Accounting Standard No. 143, Accounting for Asset Retirement Obligations, on January 1, 2003), which are incorporated herein by reference, and have been so incorporated in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing.

RESERVE ENGINEERS

      Certain information contained in the documents we incorporate by reference regarding estimated quantities of natural gas and crude oil reserves owned by us, the future net revenues from those reserves and their present value is based on estimates of the reserves and present values prepared by or derived from estimates prepared by Schlumberger Data and Consulting Services, Netherland, Sewell & Associates, Inc. and LaRoche Petroleum Consultants, Ltd. All of such information has been incorporated into this prospectus by reference in reliance upon the authority of these firms as experts in such matters.

17