As Of               Filer                 Filing     As/For/On Docs:Pgs              Issuer               Agent

 3/03/06  Terra Energy Ltd                  424B5                  1:220                                    Bowne of Dallas I..01/FA
          Mercury Michigan/Inc
          GTG Pipeline CORP
          Cowtown Pipeline Management/Inc
          Cowtown Pipeline Funding/Inc
          Beaver Creek Pipeline/L/L/C
          Terra Pipeline CO
          Cowtown Pipeline L/P
          Quicksilver Resources Inc
          Cowtown Gas Processing L/P

Document/Exhibit                   Description                      Pages   Size 

 1: 424B5       Prospectus Supplement                               HTML  1,401K 

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.

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.

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.

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.

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:

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.

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.

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

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.

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

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.

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:

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.

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:

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

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

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

We have a substantial amount of debt and the cost of servicing that debt could adversely affect our business and 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

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:

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:

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:

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.

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.

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:

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:

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.

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.

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.

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.

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.

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

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:

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

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

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

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

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

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.

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

Natural gas price collars have been put in place to hedge 2006 U.S. production of approximately 38 MMcfd and Canadian production of approximately 23 MMcfd. Additionally, the Company has used price collar agreements to hedge approximately 500 Bbld of its crude oil production through the first half of 2006. U.S. and Canadian natural gas production of approximately 20 MMcfd and 10 MMcfd, respectively, has also been hedged for the first quarter of 2007 using price collars. As a result of these various contracts, we believe the Company will have more predictability of its natural gas and crude oil revenues. The following table summarizes our open financial derivative positions as of December 31, 2005 related to natural gas and crude oil production.

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

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

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

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

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

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.

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 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 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

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.

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.

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.

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

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.

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.

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

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

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.

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

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.

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

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.

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.

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

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.

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 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 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.