North Coast Energy 424B3 Prospectus supplement

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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS

FILED PURSUANT TO RULE 424(b)(3)
REGISTRATION NO. 333-113924

PROSPECTUS

EXCO Resources, Inc.

OFFER TO EXCHANGE
Any and all of its outstanding 7¹/4% Senior Notes Due 2011
for $450,000,000 principal amount of its 7¹/4% Senior Notes Due 2011
which have been registered under the Securities Act

•: The exchange offer expires at 5:00 p.m., Eastern Time, on May 28, 2004, unless we extend the offer. We do not currently intend to extend the exchange offer.
•: We will exchange all outstanding notes, which we refer to in this prospectus as the "old notes," that are validly tendered and not validly withdrawn for an equal principal amount of new notes that are registered under the Securities Act, which we refer to in this prospectus as the "new notes."
•: The exchange offer is subject to customary conditions, which we may, but are not required to, waive.
•: You may withdraw tenders of old notes at any time before the exchange offer expires.
•: The exchange of notes will not be a taxable event for U.S. federal income tax purposes.
•: We will not receive any proceeds from the exchange offer.
•: The terms of the new notes are substantially identical to the old notes, except that the new notes will be freely tradeable.
•: You may tender old notes only in denominations of $1,000 and multiples of $1,000.
•: Our affiliates may not participate in the exchange offer.
•: No public market exists for the old notes. We do not intend to list the new notes on any securities exchange or automated dealer quotation system.

See "Risk Factors" beginning on page 17 for a discussion of
factors that you should consider before tendering your old notes.

•: Each broker-dealer that receives new notes pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act.
•: If the broker-dealer acquired the old notes as a result of market making or other trading activities, such broker-dealer may be a statutory underwriter and may use this prospectus for the exchange offer, as supplemented or amended, in connection with the resale of the new notes.
•: We have agreed that, for a period of 180 days after the consummation of the exchange offer, we will make this prospectus available to any broker-dealer for use in connection with any such resale. See "Plan of Distribution."

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of the new notes or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The date of this prospectus is April 22, 2004.

TABLE OF CONTENTS

		Page
Where You Can Find More Information		i
Forward-Looking Statements		ii
Industry and Market Data		iii
Currency Conversion		iii
Prospectus Summary		1
Risk Factors		17
The Exchange Offer		32
Use of Proceeds		45
Capitalization		46
Unaudited Pro Forma Financial Data		47
Selected Consolidated Financial and Operating Data		55
Management's Discussion and Analysis of Financial Condition and Results of Operations		57
Business		78
North Coast Acquisition		96
Management		97
Security Ownership of Certain Beneficial Owners		103
Change of Control Transaction		105
Certain Relationships and Related Transactions		108
Description of Certain Indebtedness		109
Description of the New Notes		111
U.S. Federal Income Tax Considerations		168
Plan of Distribution		172
Notice to Canadian Residents		173
Legal Matters		173
Independent Accountants		173
Change in Accountants		173
Independent Petroleum Engineers		174
Glossary of Oil and Natural Gas Terms		175
Index to Financial Statements		F-1

You should rely only on the information contained in this prospectus or to which we have referred you. We have not authorized anyone to provide you with information that is different. This prospectus may only be used where it is legal to sell these securities. The information in this prospectus may be accurate only on the date of this prospectus.

WHERE YOU CAN FIND MORE INFORMATION

Following completion of this exchange offer, we will be required to file periodic and current reports and other information with the SEC. You may read any of our filings and, for a fee, copy any document that we file with the SEC at the public reference facility maintained by the SEC at Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549. Copies of these documents may also be obtained at prescribed rates from the Public Reference Section of the SEC at Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the Public Reference Room. You may also obtain the documents that we file electronically from the SEC's website at http://www.sec.gov. The indenture requires us to file periodic reports and other information required to be filed under the Securities

Exchange Act of 1934, or the Exchange Act, with the SEC and provide such information to you, upon request, regardless of whether we are subject to the reporting requirements of the Exchange Act. Our reports and other information that we have filed, or may in the future file, with the SEC are not incorporated in and do not constitute part of this prospectus.

We have filed with the SEC a registration statement on Form S-4 with respect to the new notes offered in this prospectus. This prospectus is part of the registration statement and, as permitted by the SEC's rules, does not contain all of the information presented in the registration statement. Whenever a reference is made in this prospectus to one of our contracts or other documents, please be aware that this reference is not necessarily complete and that you should refer to exhibits that are a part of the registration statement for a copy of the contract or other document and a more complete understanding of the contract or document. We refer you to the Form S-4 for further information regarding EXCO and the securities offered in this prospectus.

This prospectus incorporates business and financial information about us that is not included in or delivered with this prospectus. We will provide this information to you at no charge upon written or oral request directed to: EXCO Resources, Inc., 12377 Merit Drive, Suite 1700, Dallas, Texas 75251, (214) 368-2084. To obtain timely delivery of any of our filings, agreements or other documents, you must make your request to us no later than five business days before the expiration date of the exchange offer. The exchange offer will expire at 5:00 p.m., Eastern Time, on May 28, 2004, unless we extend the offer. See the caption "The Exchange Offer" for more detailed information.

FORWARD-LOOKING STATEMENTS

The statements contained in this prospectus regarding our future financial and operating performance and results, business strategy, market prices, future commodity price risk management activities, plans and forecasts and other statements that are not historical facts are forward-looking statements, as defined in Section 27A of the Securities Act of 1933, or the Securities Act, and Section 21E of the Exchange Act. We have based these forward-looking statements on our current assumptions, expectations and projections about future events.

We use the words "may," "will," "expect," "anticipate," "estimate," "believe," "continue," "intend," "plan," "budget" and other similar words to identify forward-looking statements. You should read statements that contain these words carefully because they discuss future expectations, contain projections of results of operations or of our financial condition and/or state other "forward-looking" information. We do not undertake any obligation to update or revise publicly any forward-looking statements. These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially differ from our expectations in this prospectus, including, but not limited to:

•: estimates of reserves;
•: market factors, including demand for our production;
•: market prices, including regional basis differentials, of oil and natural gas;
•: results of future drilling and acquisitions;
•: marketing and commodity price risk management activities;
•: future production and costs;
•: our ability to arrange financing;
•: our ability to service our indebtedness; and
•: all the other factors described herein under "Risk Factors."

We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. When considering our forward-looking statements, keep in mind the risk factors and other cautionary statements in this prospectus.

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for oil and natural gas. Declines in oil or natural gas prices may materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower oil or natural gas prices also may reduce the amount of oil or natural gas that we can produce economically. A decline in oil and/or natural gas prices could have a material adverse effect on the estimated value and estimated quantities of our oil and natural gas reserves, our ability to fund our operations and our financial condition, cash flow, results of operations and access to capital. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.

INDUSTRY AND MARKET DATA

Industry and market data used throughout this prospectus were obtained through internal company research, surveys and studies conducted by third parties and industry and general publications. We have not independently verified market and industry data from third-party sources. While we believe the internal company research is reliable and the market definitions are appropriate, neither such research nor these definitions have been verified by any independent sources.

CURRENCY CONVERSION

For this prospectus, we converted Canadian dollars to U.S. dollars for balance sheet items, including cash, oil and natural gas properties and bank debt, using the exchange rate at the end of the applicable period. The exchange rates of the Canadian dollar to the U.S. dollar were $0.628, $0.636 and $0.771 at December 31, 2001, 2002 and 2003, respectively. For income statement items such as revenue, production costs, general and administrative costs and interest, we converted Canadian dollars to U.S. dollars using the weighted average exchange rate across the applicable period. The weighted average exchange rates of the Canadian dollar to the U.S. dollar for the period from April 2001 (the month in which we acquired our Canadian subsidiary) to December 2001 and for the years ended December 31, 2002 and 2003 were $0.644, $0.637 and $0.716, respectively.

iii

PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. It is not complete and may not contain all of the information that you should consider before participating in the exchange offer. Unless indicated otherwise, the term "notes" refers to the old notes issued on January 20, 2004, the old notes issued on April 13, 2004 and the new notes. Unless otherwise indicated in this prospectus or the context otherwise requires, all references in this prospectus to "EXCO," the "Company," "us," "our" or "we" are to EXCO Resources, Inc. and its consolidated subsidiaries. On July 29, 2003, we consummated a going private transaction whereby we became a wholly owned subsidiary of EXCO Holdings Inc., or EXCO Holdings. All balance sheet information presented in this prospectus at December 31, 2003 and all income statement data for the 156 day period from July 29, 2003 to December 31, 2003 represents the successor basis in accounting. See "—Recent Developments" and "Unaudited Pro Forma Financial Data." On November 26, 2003, we entered into an agreement, as subsequently amended and restated on December 4, 2003, also referred to as the "North Coast Acquisition Agreement," with North Coast Energy, Inc., or North Coast, and Nuon Energy & Water Investments, Inc., or Nuon Energy & Water, to acquire all of the issued and outstanding stock of North Coast pursuant to a tender offer and merger. We closed the North Coast acquisition on January 27, 2004. Throughout this prospectus, we refer to the issuances of the old notes, the North Coast acquisition, the repayment of substantially all of our and North Coast's existing bank debt, the repayment in full of our senior term loan, the repayment of substantially all of our Canadian indebtedness and this exchange offer collectively as the "Transactions." Unless otherwise indicated, the operating results and reserve information presented in this prospectus are those of EXCO and are not adjusted to reflect the pro forma effect of the North Coast acquisition. We have provided definitions for some of the oil and natural gas industry terms used in this prospectus in the "Glossary of Oil and Natural Gas Terms" beginning on page 175.

Our Company

We are an independent energy company engaged in the acquisition, exploration, development and exploitation of oil and natural gas properties. Our primary areas of operations are onshore in Texas, Louisiana, Colorado, Ohio, Pennsylvania, West Virginia and Alberta, Canada. As of December 31, 2003, our pro forma Proved Reserves were approximately 621.4 Bcfe, of which 74% were natural gas and 87% were Proved Developed Reserves. The related PV-10 of our pro forma Proved Reserves was $1.01 billion as of December 31, 2003 and the Standardized Measure of our pro forma Proved Reserves was $718.3 million as of December 31, 2003. For the twelve months ended December 31, 2003, on a pro forma basis we produced 37.0 Bcfe of oil and natural gas, which translates to a Reserve Life of approximately 16.8 years. On a pro forma basis for the twelve month period ended December 31, 2003, we generated $158.5 million of revenues and other income.

The following table sets forth a summary of our pro forma Proved Reserves, the PV-10 of such Proved Reserves and Standardized Measure of such Proved Reserves as of December 31, 2003.

		Proved Reserves(1)				PV-10(1)(2)		Standardized Measure(1)(2)
Area		Natural Gas (Bcf)	Crude Oil (Mmbbl)	NGLs (Mmbbl)	Total (Bcfe)(3)	Amount (in millions)		Amount (in millions)
United States:
EXCO		156.1	10.5	0.8	223.9	$	343.7	$	234.1
North Coast		179.9	1.4	—	188.3		369.5		265.2

	Total U.S. Proved(4)	336.0	11.9	0.8	412.2		713.2		499.3

Canada:
Alberta		126.4	6.8	7.0	209.2		299.6		219.0

	Total U.S. and Canada Proved(4)	462.4	18.7	7.8	621.4	$	1,012.8	$	718.3

Proved Developed(4)		403.5	15.6	7.1	539.7	$	902.0		N/A

(1): The Proved Reserves and the PV-10 of the Proved Reserves for EXCO and North Coast as of December 31, 2003 as used in this table were prepared by Lee Keeling and Associates, Inc., an independent petroleum engineering firm in Tulsa, Oklahoma. The amount of estimated future abandonment costs and the PV-10 of those costs for EXCO and North Coast used in this table were determined by EXCO.
(2): The PV-10 data is based on December 31, 2003 NYMEX spot prices of $6.19 per Mmbtu for natural gas and $32.52 per Bbl for oil adjusted for differentials between NYMEX and local prices.
(3): Mmbbl converted to Bcfe on a one Bbl to six Mcf conversion ratio.
(4): On a pro forma basis as though we had completed the North Coast acquisition as of December 31, 2003.

Our present value of estimated future net revenues, or PV-10, is an estimate of future net revenues from a property at the date indicated, after deducting production and ad valorem taxes, future capital costs and operating expenses, but before deducting federal income taxes. The future net revenues have been discounted at an annual rate of 10% to determine their "present value." The present value is shown to indicate the effect of time on the value of the net revenue stream and should not be construed as being the fair market value of the properties. Estimates have been made using constant oil, natural gas and NGL prices and operating costs at the date indicated. The prices used do not reflect any adjustments for derivatives. We believe that the present value of estimated future net revenues before income taxes, while not in accordance with Generally Accepted Accounting Principles (GAAP), is an important financial measure used by investors and independent oil and natural gas producers for evaluating the relative significance of oil and natural gas properties and acquisitions.

The Standardized Measure represents the PV-10, after giving effect to income taxes, and as calculated in accordance with FAS 69.

North Coast Acquisition

and production of natural gas reserves in the Appalachian Basin. The North Coast acquisition establishes a new core operating area for us in the Appalachian Basin, which positions us to benefit from the attractive qualities of the basin and to capitalize on consolidation opportunities in the area. North Coast's operations have several attractive attributes including:

•: long-life oil and natural gas reserves with a Reserve Life at December 31, 2003 of approximately 16.3 years;
•: significantly developed reserves with approximately 91% classified as Proved Developed Reserves at December 31, 2003;
•: proximity to Midwestern and East coast natural gas markets; and
•: positive average price differential to NYMEX.

For more information on the North Coast acquisition, see "North Coast Acquisition."

Our Competitive Strengths and Business Strategy

We intend to become a leading independent oil and natural gas acquisition, exploitation and production company. We plan to achieve reserve, production and cash flow growth by focusing on our competitive strengths and executing our business strategy as highlighted below.

Quality asset base. We own and plan to maintain a geographically diversified reserve base. Our primary areas of operations are onshore in Texas, Louisiana, Colorado, Ohio, Pennsylvania, West Virginia and Alberta, Canada. Our reserves in these areas are generally characterized by:

•: established histories of production;
•: long reserve lives;
•: low finding and development expenditures;
•: high drilling success rates; and
•: a high concentration of natural gas.

We seek to improve the overall quality of our asset base by exploiting our properties that have potential for value enhancement and growth, while disposing of marginal or non-strategic properties.

Acquisition and exploitation of strategic assets. We maintain a disciplined acquisition process to seek and acquire quality producing properties that have upside potential through low-risk development drilling and exploitation projects, such as infill drilling, workovers, recompletions and secondary recovery projects. From December 1997 to December 31, 2003 and pro forma for our acquisition of North Coast, we completed 111 acquisitions for total consideration of approximately $532.4 million, of which $498.4 million was allocated to acquisition of reserves. We plan to focus our acquisition activities onshore in North America and target natural gas properties with established histories of production, low-risk drilling and exploitation opportunities and long reserve lives, such as the properties in the Appalachian Basin that were acquired in the North Coast acquisition. In addition, our extensive knowledge of our operating areas and our acquisition expertise position us to capitalize on and integrate strategic acquisition opportunities in our core areas. Due to industry trends of consolidation and asset rationalization, we believe we will continue to have opportunities to acquire oil and natural gas properties at attractive rates of return.

Cost-focused operations. As of December 31, 2003, on a pro forma basis, we operate properties that contain approximately 90% of our Proved Reserves. Having operating rights with respect to our properties permits us to manage our operating costs, capital expenditures and the timing of development and exploitation of our properties. For the twelve months ended December 31, 2003, our

pro forma lease operating expense, not including production and ad valorem taxes, per Mcfe was $0.95. Using our estimate of Proved Reserves at the time of the acquisitions, we acquired 576.1 Bcfe of Proved Reserves in 111 acquisitions between December 1997 and December 31, 2003, and pro forma for our acquisition of North Coast, at an average cost of approximately $0.87 per Mcfe. Between January 1, 2000 and December 31, 2003, we invested approximately $356.6 million in acquisition, development and exploitation activities, adding 489.6 Bcfe to our Proved Reserves and replacing approximately 693% of our net production at an average "all-in" cost, including revisions, of $0.73 per Mcfe. During the same period we drilled 136 developmental wells, achieved a drilling success rate of 89% and did not participate in any exploratory wells. We expect further improvement of our corporate efficiencies through the development and operation of a larger asset base from acquisitions.

Experienced, incentivized management team. With an average industry work experience of 23 years, our management team has considerable experience in acquiring and operating oil and natural gas properties. Since members of our management team first purchased a significant ownership interest in us in December 1997 and assumed positions in our senior management, we have achieved substantial growth in our reserves, production and cash flow through a strategy of acquiring producing properties with development and exploitation potential. From December 31, 1997 to December 31, 2003 and pro forma for our acquisition of North Coast, we increased our Proved Reserves from 4.7 Bcfe to 621.4 Bcfe. In addition, members of our management team and key employees own approximately 16% of the voting capital stock of EXCO Holdings.

Comprehensive commodity price risk management program. We employ a comprehensive commodity price risk management program which better enables us to execute our business plan over the entire commodity price cycle. In connection with the incurrence of debt related to our acquisition activities, our objective in entering into these commodity price risk management transactions is to manage price fluctuations and achieve more predictable cash flows. In anticipation of the additional reserves to be acquired in the North Coast acquisition and the increase in quoted future commodity pricing, we entered into additional commodity price risk management contracts. The following table sets forth our commodity price risk management contracts as of April 15, 2004.

	Swaps						Floors			Ceilings
	Gas-Mmmbtu	Average contract- $/Mmbtu		Oil-Mbbls	Average contract- $/Bbl		Gas-Mmmbtu	Average contract- $/Mmbtu		Gas-Mmmbtu	Average contract- $/Mmbtu
2004	13,054	$	4.76	764	$	24.52	9,921	$	4.05	6,700	$	6.01
2005	15,622		4.93	329		25.65	1,059		4.25	—		—
2006	10,403		4.82	—		—	—		—	—		—
2007	6,388		4.60	—		—	—		—	—		—
2008	2,745		4.55	—		—	—		—	—		—
2009	1,825		4.51	—		—	—		—	—		—
2010	1,825		4.51	—		—	—		—	—		—
2011	1,825		4.51	—		—	—		—	—		—
2012	1,830		4.51	—		—	—		—	—		—
2013	1,825		4.51	—		—	—		—	—		—

See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Our Liquidity, Capital Resources and Capital Commitments—Derivative Financial Instruments" for more information regarding our commodity price risk management activities.

Recent Developments

North Coast Acquisition. On January 27, 2004, we closed the North Coast acquisition. See "North Coast Acquisition" for more information on the North Coast Acquisition Agreement and related transactions.

Amended and Restated Credit Facilities. Concurrent with the closing of the North Coast acquisition, we amended and restated our existing credit facilities. The amended and restated credit facilities provide for a maximum committed amount of $325.0 million and an initial borrowing base of $225.0 million. Our recent amendment to the amended and restated credit facilities permitted, among other things, the issuance of additional old notes on April 13, 2004 and provided for a reduction in the borrowing base under the amended and restated credit facilities to $200.0 million. For more information on the amended and restated credit facilities, please see "Description of Certain Indebtedness."

Private Placements. On January 20, 2004, we completed the private placement of $350.0 million aggregate principal amount of 7¹/4% Senior Notes Due 2011 pursuant to Rule 144A and Regulation S under the Securities Act at a price of 100% of the principal amount. The net proceeds of the January 20, 2004 offering were used to acquire North Coast, pay down debt under our credit facilities and North Coast's credit facility, repay our senior term loan in full and pay fees and expenses associated with those Transactions.

On April 13, 2004, we completed a private placement of an additional $100.0 million aggregate principal amount of 7¹/4% Senior Notes Due 2011 pursuant to Rule 144A, having the same terms and governed by the same indenture as the notes issued on January 20, 2004. The notes issued on April 13, 2004 were issued at a price of 103.25% of the principal amount plus interest accrued since January 20, 2004. The net proceeds of the April 13, 2004 offering were used to repay substantially all of our Canadian debt and pay fees and expenses associated therewith.

We refer to all of these privately placed notes as the old notes.

Going Private Transaction. On March 11, 2003, we entered into an Agreement and Plan of Merger providing for the merger of ER Acquisition, Inc., a wholly-owned subsidiary of EXCO Holdings into EXCO. This transaction is referred to in this prospectus as the "going private transaction."

EXCO Holdings was formed by our chairman and chief executive officer, Douglas H. Miller, and his buyout group for the purpose of completing the going private transaction, which closed on July 29, 2003. In the going private transaction, each outstanding share of our common stock, other than shares held by EXCO Holdings and its affiliates, was converted into the right to receive $18.00 in cash per share. The buyout was funded by borrowings under our existing credit facilities and approximately $172.0 million of equity. The equity capital for the going private transaction was provided by investment funds and accounts managed by Cerberus Capital Management, L.P., or Cerberus, our management and institutional and other investors. Cerberus is a New York based investment management firm that, with its affiliates, manages investment funds and accounts in excess of $12.0 billion in equity capital.

The voting capital stock of EXCO Holdings is owned by:

•: members of our management and other of our employees, who own in the aggregate approximately 16% of the voting capital stock of EXCO Holdings;
•: EXCO Investors, LLC, a limited liability company formed prior to the merger for the purpose of holding capital stock of EXCO Holdings, the members of which include business acquaintances of Mr. Miller, which owns approximately 11% of the voting capital stock of EXCO Holdings (the vote of which shares is controlled by Mr. Miller);

•: affiliates of Cerberus, which own in the aggregate approximately 55% of the voting capital stock of EXCO Holdings; and
•: other institutional investors, which own in the aggregate approximately 18% of the voting capital stock of EXCO Holdings.

See "Change of Control Transaction."

Corporate Information

We are a Texas corporation incorporated in October 1955. Our principal executive office is located at 12377 Merit Drive, Suite 1700, Dallas, Texas 75251. Our telephone number is (214) 368-2084.

The Exchange Offer

Background	On January 20, 2004, we completed the private placement of $350,000,000 in aggregate principal amount of our old notes pursuant to Rule 144A and Regulation S under the Securities Act. On April 13, 2004, we completed the private placement of an additional $100,000,000 in aggregate principal amount of our old notes pursuant to Rule 144A under the Securities Act. In connection with those private placements, we entered into registration rights agreements in which we agreed, among other things, to deliver this prospectus to you and to use our commercially reasonable efforts to cause the exchange offer registration statement to become effective under the Securities Act within 180 days after the consummation of the North Coast acquisition.
The Exchange Offer	We are offering to exchange our new notes which have been registered under the Securities Act for a like principal amount of our outstanding, unregistered old notes. Old notes may only be tendered in integral multiples of $1,000 principal amount at maturity. As of the date of this prospectus, $450,000,000 in aggregate principal amount of our old notes is outstanding.
Expiration Date	The exchange offer expires at 5:00 p.m., Eastern Time, on May 28, 2004, unless we extend the offer. We do not currently intend to extend the exchange offer. Pursuant to the terms of the registration rights agreements, the exchange offer must remain open for not less than thirty days (or longer if required by applicable law) after the date that the notice of the exchange offer is mailed to holders of the old notes.
Resale of New Notes	Based on an interpretation by the staff of the Securities and Exchange Commission, or the SEC, set forth in no-action letters issued to third parties, we believe that new notes issued pursuant to the exchange offer in exchange for old notes may be offered for resale, resold and otherwise transferred by you without compliance with the registration and prospectus delivery provisions of the Securities Act, provided that:
	•	you are acquiring the new notes in the ordinary course of your business;
	•	you are not a broker-dealer who acquired the new notes directly from us without compliance with the registration and prospectus delivery provisions of the Securities Act;

	•	you have not engaged in, do not intend to engage in, and have no arrangement or understanding with any person to participate in the distribution of the new notes; and
	•	you are not our affiliate as defined under Rule 405 of the Securities Act.
	Each participating broker-dealer that receives new notes for its own account pursuant to the exchange offer in exchange for old notes that were acquired as a result of market-making or other trading activity must acknowledge that it will deliver a prospectus in connection with any resale of new notes. Prospectus delivery requirements are discussed in greater detail in the section captioned "Plan of Distribution."
	Any holder of old notes who:
	•	is our affiliate;
	•	does not acquire new notes in the ordinary course of its business;
	•	tenders in the exchange offer with the purpose of participating, in a distribution of new notes; or
	•	is a broker-dealer that acquired the old notes directly from us
	must comply with the registration and prospectus delivery requirements of the Securities Act in connection with the resale of new notes.
Consequences For Not Exchanging Old Notes	Old notes that are not tendered in the exchange offer or are not accepted for exchange will continue to bear legends restricting their transfer. You will not be able to offer or sell the old notes unless:
	•	you do so pursuant to an exemption from the requirements of the Securities Act;
	•	the old notes are registered under the Securities Act; or
	•	the transaction requires neither such an exemption nor registration.
	After the exchange offer is closed, we will no longer have an obligation to register the old notes.

Conditions to the Exchange Offer	The exchange offer is subject to customary conditions, which we may, but are not required to, waive. For additional information regarding the conditions to the exchange offer, see "The Exchange Offer—Conditions to the Exchange Offer."
Procedures for Tendering Old Notes	If you are a holder of old notes who wishes to accept the exchange offer, you must:
	•	complete, sign and date the accompanying letter of transmittal, or a facsimile of the letter of transmittal, and mail or otherwise deliver the letter of transmittal, together with all other documents required by the letter of transmittal, including your old notes, to the exchange agent at the address set forth on the cover page of the letter of transmittal; or
	•	arrange for The Depository Trust Company to transmit certain required information, including an agent's message forming part of a book-entry transfer in which you agree to be bound by the terms of the letter of transmittal, to the exchange agent in connection with a book-entry transfer.
	By tendering your old notes in either manner, you will be representing among other things, that:
	•	the new notes you receive pursuant to the exchange offer are being acquired in the ordinary course of your business;
	•	you are not participating, do not intend to participate and have no arrangement or understanding with any person to participate, in the distribution of the new notes issued to you in the exchange offer; and
	•	you are not an "affiliate" of ours, or if you are an affiliate of ours you will comply with the applicable registration and prospectus delivery requirements of the Securities Act.
	If a broker, dealer, commercial bank, trust company or other nominee is the registered holder of your old notes, we urge you to contact that person or entity promptly to tender your old notes in the exchange offer.
	For more information on tendering your old notes, please refer to the sections in this prospectus entitled "The Exchange Offer—Acceptance of Old Notes for Exchange" and "—Procedures for Tendering Old Notes."

Guaranteed Delivery	If you wish to tender your old notes and:
	•	certificates representing your old notes are not lost but are not immediately available,
	•	time will not permit your letter of transmittal and other required documents to reach the exchange agent on or prior to the expiration date of the exchange offer, or
	•	the procedures for book-entry transfer cannot be completed on or prior to the expiration date of the exchange offer,
	you must tender your old notes according to the guaranteed delivery procedures described in this prospectus under the caption "The Exchange Offer—Procedures for Tendering Old Notes—Guaranteed Delivery."
Withdrawal Rights	You may withdraw your tender of old notes at any time prior to the expiration date of the exchange offer. See "The Exchange Offer—Withdrawal of Tenders" for a more complete description of the withdrawal provisions.
Accounting Treatment	We will not recognize any gain or loss for accounting purposes upon the completion of the exchange offer. The expenses of the exchange offer that we pay will increase our deferred financing costs in accordance with generally accepted accounting principles. See "The Exchange Offer—Accounting Treatment."
United States Federal Income Tax Consequences	We believe that the exchange of old notes for new notes will not result in any gain or loss to you for United States federal income tax purposes. See "U.S. Federal Income Tax Considerations" for a more detailed description of the tax consequences of the exchange offer.
Use of Proceeds	We will not receive any proceeds from the exchange or the issuance of the new notes in connection with the exchange offer. We are making this exchange offer solely to satisfy our obligations under our registration rights agreements. See "Use of Proceeds."
Fees and Expenses	We will bear all expenses related to the exchange offer. See "The Exchange Offer—Fees and Expenses."

Exchange Agent

We have appointed Wilmington Trust Company as exchange agent for the exchange offer. You should direct questions, requests for assistance and requests for additional copies of this prospectus (including the letter of transmittal) to the exchange agent at the address set forth under "The Exchange Offer—Exchange Agent."

Summary of Terms of The New Notes

The terms and covenants of the new notes are substantially identical to those of the old notes except that the new notes are registered under the Securities Act and will not have restrictions on transfer or registration rights. The new notes will evidence the same debt as the old notes and will be governed by the same indenture under which the old notes were issued. For purposes of the description of the new notes included in this prospectus, references to "us," "we," "our" and EXCO refer only to EXCO Resources, Inc. and do not include our subsidiaries. The following summary contains basic information about the new notes and is not intended to be complete. It does not contain all of the information that is important to you. For a more complete understanding of the new notes, please refer to the section of this prospectus entitled "Description of the New Notes."

Issuer		EXCO Resources, Inc.
New Notes Offered		$450.0 million aggregate principal amount of 7¹/4% Senior Notes Due 2011.
Maturity Date		January 15, 2011.
Interest Payments		7¹/4% per annum, payable semi-annually in arrears on January 15 and July 15 of each year, commencing July 15, 2004. Interest on the new notes will accrue from the last interest payment date on which interest was paid on the old notes surrendered in exchange therefor, or, if no interest has been paid on such old notes, from January 20, 2004.
Optional Redemption		Prior to January 15, 2007, we may redeem all, but not less than all, of the new notes in cash at a redemption price equal to 100% of the principal amount of the new notes plus the Applicable Premium (as defined in "Description of the New Notes—Optional Redemption"), plus accrued and unpaid interest to the redemption date.
		We may redeem some or all of the new notes beginning on January 15, 2007 at the redemption prices listed under "Description of the New Notes—Optional Redemption."
		Prior to January 15, 2007, we may redeem up to 35% of the aggregate principal amount of the new notes with the net proceeds of certain equity offerings at the redemption price set forth in "Description of the New Notes—Optional Redemption."

Change of Control		If a change of control occurs, subject to certain conditions, we must offer holders of the new notes an opportunity to sell us their new notes at a purchase price of 101% of the principal amount of the new notes, plus accrued and unpaid interest to the date of the purchase. See "Description of the New Notes—Change of Control."
Guaranties		The payment of the principal, premium and interest on the new notes will be guaranteed on a senior basis by all of our current and some of our future domestic subsidiaries (except that the guarantee of Taurus Acquisition, Inc. is subordinated to its guarantee under our amended and restated credit facilities). See "Description of the New Notes—Guaranties."
Share Pledge		Due to tax considerations, the new notes will not be guaranteed by Addison Energy Inc., our Canadian subsidiary. Instead, the new notes will be secured, subject to specified permitted liens and except as described below, by a second-priority security interest in 65% of the capital stock of Addison Energy Inc. and 100% of the capital stock of Taurus Acquisition, Inc. behind the first-priority security interest securing obligations relating to EXCO Resources, Inc.'s obligations under the amended and restated credit facilities or future indebtedness incurred to refinance or replace such amended and restated credit facilities on a first-priority basis. These share pledges will be limited such that, at any time, the aggregate par value, book value as carried by us or market value (whichever is greatest) of such pledged capital stock of either Addison Energy Inc. or Taurus Acquisition, Inc. is not equal to or greater than 20% of the then outstanding aggregate principal amount of the new notes.
		Amendments to or waivers of the pledge agreement governing the first-priority share pledge will, in certain circumstances, automatically apply, without consent of the holders of the new notes, to the pledge agreement governing the share pledge securing the new notes. Also, in the event of a foreclosure, liquidation, bankruptcy or similar proceeding of us or any of our subsidiary guarantors, no assurance can be given that the proceeds from any sale or liquidation of the pledged shares will be sufficient to pay any of our obligations under the new notes, in full or in part, after first satisfying our obligations and those of our guarantors under our amended and restated credit facilities. See "Description of the New Notes—Share Pledge."

		Subject to certain exceptions, the pledge agreement will provide that the first-priority lien holders will control all remedies and other actions related to the pledged shares at all times prior to the payment in full of the obligations secured by the first-priority liens and the termination of the commitments thereunder. As a result, in most circumstances neither the collateral agent, the trustee nor the holders of the new notes will be able to force a sale of the pledged shares or otherwise exercise remedies normally available to secured creditors without the concurrence of lenders under the amended and restated credit facilities and other holders of first-priority liens.
Intercreditor Agreement		Pursuant to an intercreditor agreement, the share pledges securing the new notes will be expressly second in priority to the share pledges securing EXCO Resources, Inc.'s obligations under the amended and restated credit facilities and future indebtedness incurred to replace or refinance the amended and restated credit facilities in accordance with the terms of the indenture. The second-priority share pledges securing the new notes may not be enforced at any time when the obligations secured by first-priority share pledges are outstanding, subject to certain limited exceptions. Any proceeds received by the trustee on behalf of holders of the new notes from the sale of the pledged shares prior to the payment in full of the obligations secured by the first-priority share pledges must be delivered to the holders of those obligations. See "Description of the New Notes—Share Pledge."
Ranking		The new notes and the guarantees will be our and the guarantors' senior obligations (except that the guarantee of Taurus Acquisition, Inc. will be subordinated to its guarantee under our amended and restated credit facilities). They will rank equal in right of payment with our existing and future senior indebtedness and senior in right of payment to any of our existing and future subordinated indebtedness. The new notes will be effectively subordinate to all of our secured debt to the extent of the value of the assets securing such debt and structurally subordinated to all of the existing and future liabilities of our subsidiaries that do not guarantee the new notes. The new notes and the old notes will constitute a single class of securities under the indenture. As of December 31, 2003, after giving effect to the Transactions, we, excluding our subsidiaries, would have had approximately $450.0 million of senior indebtedness, including the $450.0 million of old notes and no guarantees on a senior secured basis of indebtedness of our Canadian subsidiary; excluding guarantees of the indebtedness of EXCO Resources, Inc., our subsidiary guarantors would have had no indebtedness; and our non-guarantor subsidiary would have had no indebtedness.

Restrictive Covenants	The indenture governing the notes contains covenants which limit our ability and certain of our subsidiaries' ability to:
	•	incur or guarantee additional debt and issue certain types of preferred stock;
	•	pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated debt;
	•	make investments;
	•	create liens on our assets;
	•	enter into sale/leaseback transactions;
	•	create restrictions on the ability of our restricted subsidiaries to pay or make other payments to us;
	•	engage in transactions with our affiliates;
	•	transfer or issue shares of stock of subsidiaries;
	•	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 New Notes—Certain Covenants."
Absence of a Public Market for the New Notes	The new notes will be a new issue of debt securities of the same class as the old notes and will generally be freely transferable. Notwithstanding the foregoing, we cannot assure you as to the development of an active market for the new notes or their liquidity. We do not intend to apply for listing of the new notes on any securities exchange or any automated dealer quotation system.

Risk Factors

Investing in the new notes involves substantial risk. You should carefully consider the information under the caption "Risk Factors" and all other information included in this prospectus before investing in the new notes.

Summary Unaudited Pro Forma Financial and Operating Data

The following tables set forth summary unaudited pro forma financial and operating data to give effect to the Transactions and the going private transaction. The unaudited pro forma statement of operations data assume that the Transactions and the going private transaction occurred on January 1, 2003. The unaudited pro forma balance sheet data assume that the Transactions occurred on December 31, 2003. The unaudited pro forma financial and operating data do not purport to be indicative of the results of operations or the financial position that would have occurred had the Transactions or the going private transaction occurred on the dates indicated, nor do they purport to be indicative of future results of operations or financial position. The unaudited pro forma financial and operating data should be read in conjunction with our historical consolidated financial statements and related notes and the historical consolidated financial statements and related notes for North Coast, our unaudited condensed consolidated pro forma financial statements and related notes, "Management's Discussion and Analysis of Financial Condition and Results of Operations" and other financial and operating information contained in this prospectus.

		Year Ended December 31, 2003
		(Dollars in thousands)
Statement of Operations Data:
Revenues and other income:
Oil and natural gas		$	165,964
Commodity price risk management activities			(11,160	)
Well operating, gathering and other			3,244
Other expense			421

	Total revenues and other income		158,469

Costs and expenses:
Oil and natural gas production			43,896
Well operating, gathering and other			2,952
Depreciation, depletion and amortization			42,469
Accretion of asset retirement obligations			1,604
General and administrative			20,870
Interest			34,233

	Total costs and expenses		146,024

Income before income taxes			12,445
Income tax benefit			(523	)

Net income		$	12,968

	At December 31, 2003
	(Dollars in thousands)
Balance Sheet Data:
Cash	$	24,976
Total assets		769,353
Total debt(1)		453,250
Stockholders' equity		182,181

(1): Total debt includes $3.2 million of premium related to the old notes issued on April 13, 2004.

	Year Ended December 31, 2003
	(Dollars in thousands, except average prices and costs)
Other Financial and Operating Data:
Ratio of earnings to fixed charges(1)		1.36
Production:
Oil (Mbbls)		1,317
Natural gas liquids (Mbbls)		392
Natural gas (Mmcf)		26,778
Oil and natural gas (Mmcfe)		37,032
Average Sales Prices (before cash settlements of derivatives):
Oil (Bbls)	$	29.03
Natural gas liquids (Bbls)		24.72
Natural gas (Mcf)		5.13
Oil and natural gas (Mcfe)		5.00
Average Sales Prices (after cash settlements of derivatives):
Oil (Bbls)	$	25.03
Natural gas liquids (Bbls)		24.72
Natural gas (Mcf)		4.37
Oil and natural gas (Mcfe)		4.31
Average Costs (per Mcfe):
Lease operating expense	$	0.95
Production taxes		0.23
General and administrative		0.56
Depletion, depreciation and amortization		1.15

(1): For purposes of computing the ratio of earnings to fixed charges, earnings are defined as pre-tax income plus fixed charges. Fixed charges consist of interest expense, deferred debt issuance costs and an estimate of rent expense, which equals approximately 33% of the total rent expense.

RISK FACTORS

An investment in the new notes involves certain risks. You should consider carefully these risks together with all of the other information included in this prospectus and the documents to which we have referred you before deciding whether this investment is suitable for you.

The risk factors noted in this section and other factors contained in this prospectus describe examples of risks, uncertainties and events that may cause our actual results to differ materially from those contained in any forward-looking statement. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual outcomes may vary materially from those included in this prospectus.

Risks Related to Our Business

Our revenue depends on oil and natural gas prices, which fluctuate.

Our future financial condition, access to capital, cash flow and results of operations depend upon the prices we receive for our oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. The NYMEX spot prices for crude oil and natural gas at the close of business on December 31, 2001 were $19.84 per Bbl and $2.57 per Mmbtu and at December 31, 2003 were $32.52 per Bbl and $6.19 per Mmbtu. In addition, natural gas prices in Canada and the DJ Basin in Colorado, which accounted for an aggregate of approximately 61.1% of our natural gas production during twelve months ended December 31, 2003, have been and may continue to be subject to lower market prices primarily due to higher transportation costs and capacity restraints. On a pro forma basis for the twelve months ended December 31, 2003, natural gas constituted 72.3% of our total production. Factors that affect the prices we receive for our oil and natural gas include:

•: the level of domestic production;
•: the availability of imported oil and natural gas;
•: actions taken by foreign oil and natural gas producing nations;
•: the cost and availability of transportation and pipeline systems with adequate capacity;
•: the cost and availability of other competitive fuels;
•: fluctuating and seasonal demand for oil and natural gas;
•: conservation and the extent of governmental price controls and regulation of production;
•: weather;
•: foreign and domestic government relations; and
•: overall economic conditions.

Our ability to maintain or increase our borrowing capacity, to repay current or future indebtedness and to obtain additional capital on attractive terms depends substantially upon oil and natural gas prices.

Our commodity price risk management program may cause us to forego additional future profits or result in our making cash payments.

To reduce our exposure to changes in the prices of oil and natural gas, we have entered into and may in the future enter into commodity price risk management arrangements for a portion of our oil and natural gas production. The agreements that we have entered into generally have the effect of

providing us with a fixed price for a portion of our expected future oil and natural gas production over a fixed period of time. Commodity price risk management arrangements may expose us to the risk of financial loss in some circumstances, including the following:

•: the counterparty to the commodity price risk management contract may default on its contractual obligations;
•: there is a change in the expected differential between the underlying price in the commodity price risk management agreement and actual prices received; or
•: market prices may exceed the prices at which we are contracted, resulting in our need to make significant cash payments.

Our commodity price risk management activities could have the effect of reducing our revenues. As of December 31, 2003, the net unrealized loss on our commodity price risk management contracts was $15.7 million for EXCO and $3.1 million for North Coast. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Our Liquidity, Capital Resources and Capital Commitments—Derivative Financial Instruments" for more information about our commodity price risk management arrangements.

We may be unable to acquire or develop additional reserves.

As is generally the case in the oil and natural gas industry, our success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are profitable to produce. Factors that may hinder our ability to acquire additional oil and natural gas reserves include competition, access to capital, prevailing oil and natural gas prices and the number of properties for sale. If we are unable to conduct successful development activities or acquire properties containing Proved Reserves, our total Proved Reserves will generally decline as a result of production. Also, our production will generally decline. In addition, if our reserves and production decline then the amount we are able to borrow under our credit agreements will also decline. We may not be able to locate additional reserves, drill economically productive wells or acquire properties containing Proved Reserves.

We may not realize the anticipated benefits from the North Coast acquisition.

Our estimates regarding the expenses and liabilities or the increase in our reserves and production resulting from the North Coast acquisition may prove to be incorrect or we may not be successful in integrating North Coast's properties into our existing business, all of which could significantly reduce our ability to generate cash needed to service our debt and fund our capital program and other working capital requirements.

We have joint and several liability for tax and ERISA liabilities attributable to members of Nuon Energy & Water's tax group.

North Coast and its subsidiaries are part of Nuon Energy & Water's consolidated, combined or unitary group for tax and ERISA purposes for tax years 2003 and 2004, and as a result, North Coast and its subsidiaries are jointly and severally liable for the taxes and ERISA liabilities of all members within that group. There is a risk that a federal, state, local or foreign taxing or other governmental authority may file a claim against North Coast and its subsidiaries for taxes and/or ERISA liabilities attributable to Nuon Energy & Water's consolidated, combined or unitary group for 2003 or 2004. Such taxes and/or ERISA liabilities may be significant and may include taxes associated with the North Coast acquisition. As set forth in the North Coast Acquisition Agreement, if such a claim is asserted, Nuon Energy & Water has agreed to be responsible for, and to indemnify us for, all taxes or ERISA liabilities attributable to Nuon Energy & Water and any of its affiliates other than North Coast and its subsidiaries, for any liability imposed on North Coast and its subsidiaries due to their inclusion in Nuon

Energy & Water's consolidated, combined or unitary group, including any tax liability of North Coast as a result of North Coast making an election under Section 338(h)(10) of the Internal Revenue Code. Nuon Energy & Water's parent, n.v. NUON, a Dutch company with limited liability, has entered into an unconditional, unsecured guaranty agreement with us to guaranty Nuon Energy & Water's performance of its obligations under the North Coast Acquisition Agreement (specifically the tax indemnification provisions), the stock tender agreement and the escrow agreement. Both Nuon Energy & Water's indemnity and n.v. NUON's guaranty are unsecured obligations. There is a risk that neither entity will honor its obligations. Furthermore, neither entity may have any assets in the United States against which we could collect any final judgment we might be awarded.

We may not identify all risks associated with the acquisition of oil and natural gas properties.

Generally, it is not feasible for us to review in detail every individual property involved in an acquisition. Our business strategy focuses on acquisitions of producing oil and natural gas properties. Any future acquisitions will require an assessment of recoverable reserves, future oil and natural gas prices, operating costs, potential environmental hazards and other liabilities and other similar factors. Ordinarily, our review efforts are focused on the higher-valued properties. However, even a detailed review of these properties and records may not reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not inspect every well that we acquire. Potential problems, such as deficiencies in the mechanical integrity of equipment or environmental conditions that may require significant remedial expenditures, are not necessarily observable even when we inspect a well. Even if we were able to identify problems with an acquisition, the seller may be unwilling or unable to provide effective contractual protection or indemnity against all or part of these problems. Even if a seller agrees to provide indemnity, the indemnity may not be fully enforceable. We were not indemnified for these types of risks in the North Coast acquisition.

We may be unable to obtain additional financing to implement our growth strategy.

The growth of our business will require substantial capital on a continuing basis. Because we will pledge substantially all of our assets as collateral under our amended and restated credit facilities, it may be difficult for us in the foreseeable future to obtain financing on an unsecured basis or to obtain additional secured financing other than purchase money indebtedness. If we are unable to obtain additional capital on satisfactory terms and conditions, we may lose opportunities to acquire oil and natural gas properties and businesses.

We may not be successful in managing our growth.

The North Coast acquisition represents a significant increase in our resources and production. The North Coast acquisition constitutes the largest acquisition we have ever completed, increasing the size of our company, measured by Proved Reserves, by over 43%. In addition, in connection with the North Coast acquisition, we added 3,709 gross wells to our portfolio of wells, including approximately 3,535 operated wells, which more than quadrupled the number of wells we operated prior to completion of the North Coast acquisition. Finally, the North Coast acquisition represents our entry into a new geographic production region in which we have not previously operated. All of these factors present significant integration challenges for us. The pursuit of additional acquisitions is a key part of our strategy. Our growth could strain our managerial, financial, technical, operational and administrative resources. Failure to manage our growth successfully could adversely affect our operations and net revenues through increased operating costs and revenues that do not meet our expectations. We may not be able to successfully integrate acquired oil and natural gas properties into our operations or achieve desired profitability.

We may encounter marketing obstacles.

Our ability to market our oil and natural gas production will depend upon the availability and capacity of natural gas gathering systems, pipelines and other transportation facilities. We are primarily dependent upon third parties to transport our products. Transportation space on the gathering systems and pipelines we utilize is occasionally limited or unavailable due to repairs or improvements to facilities or due to space being utilized by other companies that have priority transportation agreements. Our access to transportation options can also be affected by U.S. federal and state regulation and Canadian regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. These factors and the availability of markets are beyond our control. If market factors dramatically change, the financial impact on our revenues could be substantial and could adversely affect our ability to produce and market oil and natural gas.

Our Canadian operations may be adversely affected by currency fluctuations and economic and political developments.

We have significant oil and natural gas operations in Canada, representing approximately 34% of our Proved Reserves at December 31, 2003, on a pro forma basis. Our Canadian operations are subject to the risk of fluctuations in the relative value of the Canadian and U.S. dollars. We have not hedged any currency risk exposure associated with our Canadian operations in prior periods. We are required to recognize foreign currency transaction and translation gains or losses related to our Canadian operations in our consolidated financial statements. Our Canadian operations may be adversely affected by political and economic developments, royalty and tax increases and other laws or policies in Canada, as well as U.S. policies affecting trade, taxation and investment in Canada.

Our Canadian properties and operations are subject to foreign regulations.

The oil and natural gas industry in Canada is subject to extensive legislation and regulation governing its operations. This legislation and regulation, enacted by various levels of government, impacts a number of areas, including royalties, land tenure, exploration, development, production, refining, transportation, marketing, environmental protection, exports, taxes, labor standards and health and safety standards. In addition, extensive legislation and regulation exists with respect to pricing and taxation of oil and natural gas and related products. Canadian governmental legislation and regulation may have a material effect on our operating results and may have a material adverse effect on our results of operations and our financial condition.

We may be unable to overcome risks associated with our drilling activity.

Our drilling involves numerous risks, including the risk that we will not encounter commercially productive oil or natural gas reservoirs. We must incur significant expenditures to identify and acquire properties and to drill and complete wells. The costs of drilling and completing wells is often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents, weather conditions and shortages or delays in the delivery of equipment. While we use advanced technology in our operations, this technology does not allow us to know conclusively prior to drilling a well that oil or natural gas is present or economically producible.

We may not correctly evaluate reserve data or the exploitation potential of properties as we engage in our acquisition, development and exploitation activities.

Our future success will depend on the success of our acquisition, development and exploitation activities. Our decisions to purchase, develop or otherwise exploit properties or prospects will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical

and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations.

We cannot control the development of the properties we own but do not operate.

As of December 31, 2003, we do not operate wells that represent approximately 10% of the present value of estimated future net revenues of our Proved Reserves on a pro forma basis. As a result, the success and timing of our drilling and development activities on those properties depend upon a number of factors outside of our control, including:

•: the timing and amount of capital expenditures;
•: the operators' expertise and financial resources;
•: the approval of other participants in drilling wells; and
•: the selection of suitable technology.

If drilling and development activities are not conducted on these properties, we may not be able to increase our production or offset normal production declines.

Our estimates of oil, natural gas and NGL reserves involve inherent uncertainty.

Numerous uncertainties are inherent in estimating quantities of proved oil, natural gas and NGL reserves, including many factors beyond our control. This prospectus contains estimates of our proved oil, natural gas and NGL reserves and the PV-10 of the proved oil, natural gas and NGL reserves. These estimates are based upon reports of our own engineers and our independent petroleum engineers. These reports rely upon various assumptions, including assumptions required by the SEC, as to constant oil, natural gas and NGL prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. These estimates should not be construed as the current market value of our estimated Proved Reserves. The process of estimating oil, natural gas and NGL reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir. As a result, the estimates are inherently imprecise evaluations of reserve quantities and future net revenue. Our actual future production, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil, natural gas and NGL reserves may vary substantially from those we have assumed in the estimates. Any significant variance in our assumptions could materially affect the quantity and value of reserves described in this prospectus. In addition, our reserves may be revised downward or upward, based upon production history, results of future exploitation and development activities, prevailing oil and natural gas prices and other factors. A material decline in prices paid for our production can adversely impact the estimated volumes of our reserves.

We are exposed to operating hazards and uninsured risks.

Our operations are subject to the risks inherent in the oil and natural gas industry, including the risks of:

•: fire, explosions and blowouts;
•: pipe failure;
•: abnormally pressured formations; and
•: environmental accidents such as oil spills, gas leaks, ruptures or discharges of toxic gases, brine or well fluids into the environment (including groundwater contamination).

These events may result in substantial losses to us from:

•: injury or loss of life;
•: severe damage to or destruction of property, natural resources and equipment;
•: pollution or other environmental damage;
•: environmental clean-up responsibilities;
•: regulatory investigation;
•: penalties and suspension of operations; or
•: attorney's fees and other expenses incurred in the prosecution or defense of litigation.

As is customary in our industry, we maintain insurance against some, but not all, of these risks. Our insurance may not be adequate to cover these losses or liabilities. Further, with the turmoil in the commercial insurance industry as a result of the events of September 11, 2001, insurance coverage may not continue to be available at commercially acceptable premium levels or at all. We do not carry business interruption insurance. Losses and liabilities arising from uninsured or under-insured events could require us to make large unbudgeted cash expenditures that could materially impact our cash flow.

We have renewed well control coverage for our Canadian drilling and workover activities effective as of March 1, 2004. Well control coverage for our U.S. operations was renewed as of March 10, 2004. The new policy covers our U.S. workover operations unlike our previous policy as the premiums have become more economical. North Coast's well control policy is in effect through May 9, 2004. We cannot assure you that we will be able to renew North Coast's well control policy at commercially acceptable premiums or at all. In addition, we cannot assure you that, if we are unable to renew North Coast's well control policy, we will be able to add North Coast and its subsidiaries to our current well control policy on commercially acceptable terms or at all.

We may experience production curtailments.

The producing wells that we own an interest in have, from time to time, experienced reduced or terminated production. These curtailments may result from mechanical failures, contract terms, pipeline and processing plant interruptions, market conditions and weather conditions. These curtailments may last from a few days to many months.

Repercussions from terrorist activities or armed conflict could harm our business.

Terrorist activities, anti-terrorist efforts and other armed conflict involving the United States or its interests abroad may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If events of this nature occur and persist, the attendant political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on prevailing oil and natural gas prices and causing a reduction in our revenues. Oil and natural gas production facilities, transportation systems and storage facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our operations is destroyed or damaged by such an attack. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain if available at all.

Our business exposes us to liability and extensive regulation on environmental matters.

Our operations are subject to numerous U.S. federal, state and local and Canadian laws and regulations relating to the protection of the environment, including those governing the discharge of

materials into the water and air, the generation, management and disposal of hazardous substances and wastes and the cleanup of contaminated sites. We could incur material costs, including cleanup costs, fines and civil and criminal sanctions and third-party claims for property damage and personal injury as a result of violations of, or liabilities under, environmental laws and regulations. Such laws and regulations not only expose us to liability for our own activities, but may also expose us to liability for the conduct of others or for actions by us that were in compliance with all applicable laws at the time those actions were taken. In addition, we could incur substantial expenditures complying with environmental laws and regulations, including future environmental laws and regulations which may be more stringent.

Our business depends on a limited number of key personnel.

We are substantially dependent upon the skills of two key individuals within our management, Mr. Douglas H. Miller and Mr. T. W. Eubank. Both individuals have experience in acquiring, financing and restructuring oil and natural gas companies. We do not have employment agreements with these individuals or maintain key man insurance. The loss of the services of either one of these individuals could hinder our ability to successfully implement our business strategy.

Our principal stockholder is in a position to affect our ongoing operations, corporate transactions and other matters.

EXCO Holdings, as our sole stockholder, has the right to elect our board of directors. For so long as EXCO Acquisition LLC, an affiliate of Cerberus, owns at least 20% of the issued and outstanding shares of EXCO Holdings, it has the right to elect a majority of the board of directors of EXCO Holdings. The interests of EXCO Acquisition LLC and its affiliates may conflict with the interests of the holders of the notes. In particular, EXCO Acquisition LLC may cause a change of control at a time when we do not have sufficient funds to repurchase the notes as described under "Description of the New Notes—Change of Control."

We may have write-downs of our asset values.

Prior to the going private transaction, we recorded pre-tax, non-cash ceiling test write-downs as follows: (a) during 2001, $28.7 million from our United States full cost pool and $20.9 million from our Canadian full cost pool and (b) during the second quarter of 2002, $17.5 million from our Canadian full cost pool. Depending upon oil and natural gas prices in the future, we may be required to write-down the value of our oil and natural gas properties if the present value of the after-tax future cash flows from our oil and natural gas properties falls below the net book value of these properties. Future non-cash ceiling test write-downs would negatively affect our earnings and net worth.

We may experience a financial loss if any of our significant customers fails to pay us for our oil or natural gas.

Our ability to collect the proceeds from the sale of oil and natural gas from our customers depends on the payment ability of our customer base, which includes several significant customers. See "Business—Our Principal Customers" for more information on these customers. If any one or more of these significant customers fails to pay us for any reason, we could experience a material loss. In addition, in recent years, a number of energy marketing and trading companies have discontinued their marketing and trading operations, which has significantly reduced the number of potential purchasers for our oil and natural gas production. This reduction in potential customers has reduced market liquidity and, in some cases, has made it difficult for us to identify creditworthy customers. While we monitor the creditworthiness of our customers and, from time to time, demand adequate assurances of performance if the creditworthiness of our customers is in question, we may experience a material loss as a result of the failure of our customers to pay us for prior purchases of our oil or natural gas.

Competition in our industry is intense, and many of our competitors have greater financial, technological and other resources than we have.

The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring properties, contracting for drilling equipment and securing trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. We are unable to predict when, or if, such shortages may again occur or how they would affect our development and exploitation program. Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases and drilling rights, and, as a result, we may not be able to compete satisfactorily. Many large oil companies have been actively marketing some of their existing producing properties for sale to independent producers. We may not be successful in acquiring any of these properties.

Risks Relating to Our Indebtedness

We have a substantial amount of indebtedness, which may adversely affect our cash flow and our ability to operate our business, remain in compliance with debt covenants and make payments on our debt, including the new notes.

As of December 31, 2003, after giving pro forma effect to the Transactions, we would have had total debt of $453.2 million, including $3.2 million of premium related to the old notes issued on April 13, 2004, and stockholders' equity of $182.1 million. As of April 15, 2004, our actual total debt was $453.2 million, including $3.2 million of premium related to the old notes issued on April 13, 2004.

Our level of debt could have important consequences for you, including the following:

•: it may be more difficult for us to satisfy our obligations with respect to the new notes, and any failure to comply with the obligations of any of our debt agreements, including financial and other restrictive covenants, could result in an event of default under the indenture governing the new notes and the agreements governing such other indebtedness;
•: we may have difficulty borrowing money in the future for acquisitions, capital expenditures or to meet our operating expenses or other general corporate obligations;
•: the amount of our interest expense may increase because certain of our borrowings are at variable rates of interest, which, if interest rates increase, could result in higher interest expense;
•: we will need to use a substantial portion of our cash flows to pay principal and interest on our debt, which will reduce the amount of money we have for operations, working capital, capital expenditures, expansion, acquisitions or general corporate or other business activities;
•: we may have a higher level of debt than some of our competitors, which may put us at a competitive disadvantage;
•: we may be more vulnerable to economic downturns and adverse developments in our industry or the economy in general, especially declines in oil and natural gas prices; and
•: our debt level could limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate.

Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. We will not be

able to control many of these factors, such as economic conditions and governmental regulation. We cannot be certain that our earnings will be sufficient to allow us to pay the principal and interest on our debt, including the new notes, and meet our other obligations. If we do not have enough money to service our debt, we may be required to refinance all or part of our existing debt, including the new notes, sell assets, borrow more money or raise equity. We may not be able to refinance our debt, sell assets, borrow more money or raise equity on terms acceptable to us, if at all. Further, failing to comply with the financial and other restrictive covenants in our indebtedness could result in an event of default under such indebtedness, which could adversely affect our business, financial condition and results of operations.

We may incur substantially more debt, which may intensify the risks described above, including our ability to service our indebtedness.

Together with our subsidiaries, we may be able to incur substantially more debt in the future in connection with our acquisition, development, exploitation and exploration of oil and natural gas producing properties. Although the indenture governing the new notes contains restrictions on our incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions, and under certain circumstances, indebtedness incurred in compliance with these restrictions could be substantial. Also, these restrictions do not prevent us from incurring obligations that do not constitute indebtedness. Assuming the Transactions had occurred on December 31, 2003, we would have had approximately $199.7 million of additional borrowing capacity under the amended and restated credit facilities, subject to specific requirements, including compliance with financial covenants. To the extent new indebtedness is added to our current indebtedness levels, the risks described above could substantially increase.

To service our indebtedness, we will require a significant amount of cash. Our ability to generate cash depends on many factors beyond our control, and any failure to meet our debt obligations could harm our business, financial condition and results of operations.

Our ability to make payments on and to refinance our indebtedness, including the new notes, and to fund planned capital expenditures will depend on our ability to generate cash from operations in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control, including the prices that we receive for oil and natural gas.

Our business may not generate sufficient cash flow from operations and future borrowings may not be available to us under the amended and restated credit facilities in an amount sufficient to enable us to pay our indebtedness, including the new notes, or to fund our other liquidity needs. Our debt service obligations for 2004, following the consummation of the Transactions and assuming no additional incurrence of debt, are $30.8 million including interest payments. If our cash flow and capital resources are insufficient to fund our debt obligations, we may be forced to sell assets, seek additional equity or debt capital or restructure our debt. None of these remedies may, if necessary, be effected on commercially reasonable terms, or at all. In addition, any failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms. Our cash flow and capital resources may be insufficient for payment of interest on and principal of our debt in the future, including payments on the new notes, and any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations and could impair our liquidity.

Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.

The amended and restated credit facilities and the indenture governing the new notes contain a number of significant covenants that, among other things, restrict our ability to:

•: dispose of assets;
•: incur or guarantee additional indebtedness and issue certain types of preferred stock;
•: pay dividends on our capital stock;
•: create liens on our assets;
•: enter into sale or leaseback transactions;
•: enter into specified investments or acquisitions;
•: repurchase, redeem or retire our capital stock or subordinated debt;
•: merge or consolidate, or transfer all or substantially all of our assets and the assets of our subsidiaries;
•: engage in specified transactions with subsidiaries and affiliates; or
•: other corporate activities.

Also, the amended and restated credit facilities require us to maintain compliance with specified financial ratios and satisfy certain financial condition tests. Our ability to comply with these ratios and financial condition tests may be affected by events beyond our control, and, as a result, we may not be able to meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general or otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under the amended and restated credit facilities and the indenture governing the notes impose on us.

A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition tests could result in a default under the amended and restated credit facilities and the notes. A default, if not cured or waived, could result in acceleration of all indebtedness outstanding under the amended and restated credit facilities and the notes. The accelerated debt would become immediately due and payable. If that should occur, we may not be able to pay all such debt or to borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us. See "Description of Certain Indebtedness" and "Description of the New Notes—Defaults."

We conduct a substantial portion of our operations through our subsidiaries and may be limited in our ability to access funds from those subsidiaries to service our debt, including the new notes.

We conduct a substantial portion of our operations through our subsidiaries and depend to a large degree upon dividends and other intercompany transfers of funds from our subsidiaries to meet our debt service and other obligations, including the new notes. Our subsidiaries that do not guarantee the new notes do not have any obligation to pay amounts due on the new notes or to make funds available to us for these payments. In addition, the ability of our subsidiaries to pay dividends and make other payments to us may be restricted by, among other things, applicable corporate and other laws, transfer pricing regulations, potentially adverse tax consequences and agreements of our subsidiaries. Although the indenture governing the new notes limits the ability of our subsidiaries to enter into consensual

restrictions on their ability to pay dividends and make other payments, the limitations are subject to a number of significant qualifications and exceptions. See "Description of the New Notes—Certain Covenants—Limitation on Restrictions on Distributions from Restricted Subsidiaries." If we are unable to access the cash flow of our subsidiaries, we may have difficulty meeting our debt obligations.

Risks Relating to the Exchange Offer and the New Notes

There is no active trading market for the new notes; as a result, the value of the new notes may fluctuate significantly and any market for the new notes may be illiquid.

The new notes will be a new issue of debt securities of the same class as the old notes and will generally be freely transferable. Notwithstanding the foregoing, a liquid market may not develop for the new notes and you may not be able to sell your new notes at a particular time, as we do not intend to apply for the new notes to be listed on any securities exchange or to arrange for quotation on any automated dealer quotation system. In addition, the trading prices of the new notes could be subject to significant fluctuations in response to government regulations, variations in quarterly operating results, demand for oil and natural gas, general economic conditions and various other factors. The liquidity of the trading market in the new notes and the market price quoted for the new notes may also 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 prospects for companies in our industry generally. As a result, an active trading market may not develop for the new notes. If no active trading market develops, you may not be able to resell your new notes at their fair market value or at all.

If you do not exchange your old notes, they may be difficult to resell.

It may be difficult for you to sell the old notes that are not exchanged in the exchange offer since any old notes not exchanged will remain subject to the restrictions on transfer provided for in Rule 144 under the Securities Act. These restrictions on transfer of your old notes exist because we issued the old notes pursuant to an exemption from the registration requirements of the Securities Act and applicable state securities laws. Generally, the old notes that are not exchanged for the new notes pursuant to the exchange offer will remain restricted securities. Accordingly, such old notes may be resold only:

•: to us (upon redemption of the notes or otherwise);
•: pursuant to an effective registration statement under the Securities Act;
•: so long as the old notes are eligible for resale pursuant to Rule 144A under the Securities Act to a qualified institutional buyer within the meaning of Rule 144A in a transaction meeting the requirements of Rule 144A;
•: outside the United States to a foreign person pursuant to the exemption from the registration requirements of the Securities Act provided by Regulation S under the Securities Act;
•: pursuant to an exemption from registration under the Securities Act provided by Rule 144 thereunder (if available); or
•: pursuant to another available exemption from the registration requirements of the Securities Act, in each case in accordance with any applicable securities laws of any state of the United States.

Except as provided in this exchange offer, we do not intend to register the old notes under the Securities Act. To the extent any old notes are tendered and accepted in the exchange offer, the trading market, if any, for the old notes that remain outstanding after the exchange offer would be adversely affected due to a reduction in market liquidity.

The new notes are not secured by our assets, other than certain subsidiary shares pledged on a second-priority basis, or those of our subsidiary guarantors.

The new notes 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 new notes. Our obligations under the amended and restated credit facilities are secured by substantially all of our producing oil and natural gas properties. See "Description of Certain Indebtedness."

If we fail to meet our payment obligations under our amended and restated credit facilities, the lenders under such credit facilities could foreclose on, and acquire control of, substantially all of our assets.

The lenders under our amended and restated credit facilities have a lien on substantially all of our assets. As a result of these liens, if we fail to meet our payment or other obligations under the amended and restated credit facilities, those lenders would be entitled to foreclose on substantially all of our assets and liquidate those assets. Under those circumstances, we may not have sufficient funds to pay principal, premium, if any, and interest on the new notes. As a result, the holders of the new notes may lose a portion of or the entire value of their investment.

The new notes will not be guaranteed by our Canadian subsidiary.

The new notes will not be guaranteed by our Canadian subsidiary. As a result, if we default on our obligations under the new notes, holders of the new notes will not have any claims against our Canadian subsidiary. For the year ended December 31, 2003, revenues of our Canadian operations were $63.0 million. As of December 31, 2003, the total assets of our Canadian operations were $277.1 million and the total liabilities of our Canadian operations were $222.3 million.

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

Federal and state statutes allow courts, under specific circumstances, to void subsidiary guarantees, or require that claims under the subsidiary guarantee be subordinated to all other debts of the subsidiary guarantor, and to require creditors such as the noteholders to return payments received from subsidiary guarantors. Under federal bankruptcy law and comparable provisions of state fraudulent transfer laws, a subsidiary guarantee could be voided or claims in respect of a subsidiary guarantee could be subordinated to all other debts of that subsidiary guarantor if, for example, the subsidiary guarantor, at the time it issued its subsidiary guarantee:

•: intended to hinder, delay or defraud any present or future creditor or received less than reasonably equivalent value or fair compensation for the subsidiary guarantee;
•: was insolvent or rendered insolvent by making the subsidiary guarantee;
•: was engaged in a business or transaction for which the subsidiary guarantor's remaining assets constituted unreasonably small capital; or
•: intended to incur, or believed that it would incur, debts beyond its ability to pay them as they mature.

The measures of insolvency for purposes of these fraudulent transfer laws will vary depending upon the law applied in any proceeding to determine whether a fraudulent transfer has occurred. Generally, a subsidiary guarantor would be considered insolvent if:

•: the sum of its debts, including contingent liabilities, was greater than the fair saleable value of all of 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 become absolute and mature; or
•: it could not pay its debts as they become due.

To the extent a court voids a subsidiary guarantee as a fraudulent transfer or holds the subsidiary guarantee unenforceable for any other reason, holders of new notes would cease to have any direct claim against the subsidiary guarantor. If a court were to take this action, the subsidiary guarantor's assets would be applied first to satisfy the subsidiary guarantor's liabilities, if any, before any portion of its assets could be distributed to us to be applied to the payment of the new notes. A subsidiary guarantor's remaining assets may not be sufficient to satisfy the claims of the holders of new notes related to any voided portions of the subsidiary guarantees.

The holders of the new notes may not be able to realize fully the value of the pledged shares securing the new notes.

The new notes will be secured by second-priority share pledges, subject to specified permitted liens, on 65% of the capital stock of Addison Energy Inc. and 100% of the capital stock of Taurus Acquisition, Inc. All of these shares are also pledged to secure existing and future debt under our amended and restated credit facilities and future debt incurred to refinance or replace the facilities, in each case on a first-priority basis. All rights under the pledged shares are subject to the terms of an intercreditor agreement. The holders of the first-priority pledges or their credit agent will control all decisions and actions with respect to the pledged shares until the debt secured by the first-priority share pledges is paid in full. Accordingly, the holders of the new notes will not have any right to initiate or direct the exercise of remedies against the collateral while the first-priority lien debt is outstanding. As a result, even following an event of default, including a bankruptcy proceeding, the holders of the new notes will not have any right or ability to exercise or cause the exercise of remedies against the pledged shares while the first-priority lien debt is outstanding, other than to file a claim of interest in a bankruptcy proceeding to preserve the second-priority lien against the pledged shares.

If the holders of the first-priority lien debt enter into any amendment, waiver or consent in respect of the pledge agreement securing the first-priority share pledges for the purpose of adding to, or deleting from, or waiving or consenting to any departures from the provisions of such agreement, or changing in any manner the rights of the first-priority lenders, our rights or the rights of the guarantors, then such amendment, waiver or consent shall apply automatically, with certain exceptions, to any comparable provision of the pledge agreement securing the second-priority share pledges.

The holders of these first-priority share pledges will receive all proceeds from the liquidation of the pledged shares securing the new notes until all obligations under such indebtedness are paid in full. The amount to be received from a liquidation of the pledged shares will depend on numerous factors, including market and economic conditions, the availability of buyers, the timing and manner of sale and similar factors. We may not be able to liquidate the pledged shares in a short period of time. No independent appraisals of any of the pledged shares have been prepared by or on behalf of us in connection with this offering. Accordingly, the new notes are secured by the pledged shares only to the extent the first-priority lien debt is oversecured by such pledged shares, and, as a result, the proceeds of any sale of the pledged shares may not be sufficient to satisfy, and may be substantially less than,

amounts due on the new notes after satisfying our obligations secured by the first-priority share pledges.

The capital stock securing the new notes will automatically be released to the extent the pledge of such stock would require the filing of separate financial statements for any of our subsidiaries with the SEC.

The indenture governing the new notes and the pledge agreement provide that to the extent that any rule is adopted, amended or interpreted which would require the filing with the SEC (or any other governmental agency) of separate financial statements of Addison Energy Inc. or Taurus Acquisition, Inc. due to the fact that such subsidiaries' capital stock secures the new notes, then such capital stock will automatically be deemed, for so long as such requirement would be in effect, not to be part of the collateral securing the new notes to the extent necessary to not be subject to such requirement. These share pledges initially provide that they will be limited such that at any time, the aggregate par value, book value as carried by us or market value (whichever is greatest) of such pledged capital stock is not equal to or greater than 20% of the then outstanding aggregate principal amount of the new notes. In such event, the pledge agreement will be amended, without the consent of any holder of the new notes, to the extent necessary to evidence the absence of any liens on such capital stock. The lenders under our amended and restated credit facilities are not subject to a similar requirement. As a result, holders of the new notes could lose their security interest in such portion of the pledged stock if and for so long as any such rule is in effect. In addition, the absence of a lien on a portion of the capital stock of a subsidiary pursuant to this provision in certain circumstances could result in less than a majority of the capital stock of a subsidiary being pledged to secure the new notes, which could impair the ability of the collateral agent, acting on behalf of the holders of the new notes, to sell a controlling interest in such subsidiary or to otherwise realize value on the pledged stock.

Rights of holders of new notes in the pledged stock may be adversely affected by bankruptcy proceedings.

The right of the collateral agent for the new notes to repossess and dispose of the pledged stock securing the new notes upon acceleration is likely to be significantly impaired by federal bankruptcy law if bankruptcy proceedings are commenced by or against us prior to or possibly even after the collateral agent has repossessed and disposed of the collateral. Under the U.S. Bankruptcy Code, a secured creditor, such as the collateral agent, is prohibited from repossessing its security from a debtor in a bankruptcy case, or from disposing of security repossessed from a debtor, without bankruptcy court approval. Moreover, bankruptcy law permits the debtor to continue to retain and to use the collateral, even though the debtor is in default under the applicable debt instruments, provided that the secured creditor is given "adequate protection." The meaning of the term "adequate protection" may vary according to circumstances, but it is intended in general to protect the value of the secured creditor's interest in the collateral and may include cash payments or the granting of additional security, if and at such time the court in its discretion determines, for any diminution in the value of the collateral as a result of the stay of the repossession or disposition or any use of the collateral by the debtor during the pendency of the bankruptcy case. In view of the broad discretionary powers of a bankruptcy court, it is impossible to predict how long payments under the new notes could be delayed following commencement of a bankruptcy case, whether or when the collateral agent would repossess or dispose of the pledged stock, or whether or to what extent holders of the new notes would be compensated for any delay in payment of loss of value of the pledged stock through the requirements of "adequate protection." Furthermore, in the event the bankruptcy court determines that the value of the pledged stock is not sufficient to repay all amounts due on the new notes after first paying first priority lien obligations, the holders of the new notes would have "undersecured claims" as to the difference. Federal bankruptcy laws do not permit the payment or accrual of interest, costs and attorneys' fees for "undersecured claims" during the debtor's bankruptcy case.

A financial failure by us or any subsidiary guarantor may hinder the receipt of payment on the new notes, as well as the enforcement of remedies under the guaranties and the second priority stock pledges.

An investment in the new notes, as in any type of security, involves insolvency and bankruptcy considerations. If we or any of our subsidiary guarantors become a debtor subject to insolvency proceedings under any applicable bankruptcy law, the proceedings are likely to result in delays in the payment of the new notes and in the exercise of enforcement remedies under the new notes, the guaranties or the stock pledges. Provisions under the bankruptcy code or general principles of equity that could result in the impairment of your rights include the automatic stay, avoidance of preferential transfers by a trustee or a debtor-in-possession, substantive consolidation, limitations of collectability of unmatured interest or attorneys' fees and forced restructuring of the new notes.

A financial failure by us or our subsidiaries may result in our assets and the assets of any or all of our subsidiaries becoming subject to the claims of our creditors and the creditors of our subsidiaries.

A financial failure by us or our subsidiaries could affect payment of the new notes if a bankruptcy court were to "substantively consolidate" us and our subsidiaries. If a bankruptcy court substantively consolidated us and our subsidiaries, the assets of each entity would be subject to the claims of creditors of all entities so consolidated. This would expose you not only to the usual impairments arising from the bankruptcy, but also to potential dilution of the amount ultimately recoverable because of the larger creditor base. Furthermore, forced restructuring of the new notes could occur through the "cram-down" provision of the bankruptcy code. Under this provision, the new notes could be restructured over your objections as to their general terms, primarily interest rate and maturity.

We may not be able to repurchase the new notes or repay debt under the amended and restated credit facilities upon a change of control.

Upon the occurrence of a change of control, holders of new notes will have the right to require us to repurchase all or any part of such holder's new notes at a price equal to 101% of the principal amount of the note, plus accrued and unpaid interest, if any, to the date of purchase. We may not have sufficient funds at the time of the change of control to make the required repurchases, or restrictions under the amended and restated credit facilities may not allow such repurchases. In addition, an event constituting a "change of control" (as defined in the indenture governing the notes) could be an event of default under the amended and restated credit facilities that would, if it should occur, permit the lenders to accelerate that debt and that, in turn, would cause an event of default under the indenture governing the new notes, each of which could have material adverse consequences for us and the holders of the new notes.

The source of any funds for any repurchase required as a result of a change of control will be our available cash or cash generated from our business operations or other sources, including borrowings, sales of assets, sales of equity or funds provided by a new controlling entity. Sufficient funds may not be available at the time of any change of control to make any required repurchases of the new notes tendered and to repay debt under the amended and restated credit facilities. Furthermore, using available cash to fund the potential consequences of a change of control may impair our ability to obtain additional financing in the future. Any of our future credit agreements or other agreements relating to our debt will most likely contain similar restrictions and provisions. See "Description of the New Notes—Change of Control."

THE EXCHANGE OFFER

This section of the prospectus describes the proposed exchange offer. While we believe that the description covers the material terms of the exchange offer, this summary may not contain all of the information that is important to you. You should carefully read this entire document and the other documents referred to herein for a more complete understanding of the exchange offer.

Purpose of the Exchange Offer

In connection with each issuance of the old notes, we entered into separate registration rights agreements that provide for the exchange offer. A copy of each registration rights agreement relating to the old notes is filed as an exhibit to the registration statement of which this prospectus is a part. Under each registration rights agreement relating to the old notes we agreed that we would, subject to certain exceptions:

•: within 90 days after the consummation of the North Coast acquisition, file a registration statement with the SEC with respect to a registered offer to exchange the old notes for the new notes having terms substantially identical in all material respects to the old notes except that the new notes are registered under the Securities Act and will not have restrictions on transfer or registration rights;
•: use commercially reasonable efforts to cause the registration statement to be declared effective under the Securities Act within 180 days after the consummation of the North Coast acquisition;
•: following the declaration of the effectiveness of the registration statement, promptly offer the new notes in exchange for surrender of the old notes; and
•: keep the exchange offer open for not less than 30 days (or longer if required by applicable law) after the date notice of the exchange offer is mailed to the holders of the old notes.

For each old note tendered to us pursuant to the exchange offer, we will issue to the holder of such old note a new note having a principal amount equal to that of the surrendered old note. Interest on each new note will accrue from the last interest payment date on which interest was paid on the old note surrendered in exchange therefor, or, if no interest has been paid on such old note, from January 20, 2004.

Under existing SEC interpretations, the new notes will be freely transferable by holders other than our affiliates after the exchange offer without further registration under the Securities Act if the holder of the new notes represents to us in the exchange offer that it is acquiring the new notes in the ordinary course of its business, that it has no arrangement or understanding with any person to participate in the distribution of the new notes and that it is not an affiliate of ours, as such terms are interpreted by the SEC; provided, however, that broker-dealers receiving the new notes in the exchange offer will have a prospectus delivery requirement with respect to resales of such new notes. The SEC has taken the position that such participating broker-dealers may fulfill their prospectus delivery requirements with respect to the new notes (other than a resale of an unsold allotment from the original sale of the old notes) with the prospectus contained in this registration statement. Each broker-dealer that receives the new notes for its own account in exchange for the old notes, where such old notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. See "Plan of Distribution."

Under the registration rights agreements relating to the old notes, we are required to allow participating broker-dealers and other persons, if any, with similar prospectus delivery requirements to use the prospectus contained in this registration statement in connection with the resale of the new notes for 90 days following the consummation of the exchange offer.

A holder of old notes (other than certain specified holders) who wishes to exchange the old notes for the new notes in the exchange offer will be required to represent that any new notes to be received by it will be acquired in the ordinary course of its business and that at the time of the commencement of the exchange offer it has no arrangement or understanding with any person to participate in the distribution (within the meaning of the Securities Act) of the new notes and that it is not an "affiliate" of ours, as defined in Rule 405 of the Securities Act, or if it is an affiliate, that it will comply with the registration and prospectus delivery requirements of the Securities Act to the extent applicable.

In the event that:

(1) any change of law or in applicable interpretations thereof by the staff of the SEC do not permit us to effect an exchange offer; or

(2) for any other reason we do not consummate the exchange offer within 220 days of the consummation of the North Coast acquisition; or

(3) an initial purchaser of the old notes notifies us following consummation of the exchange offer that the old notes held by it are not eligible to be exchanged for the new notes in the exchange offer; or

(4) certain holders of the old notes are not eligible to participate in the exchange offer or may not resell the new notes acquired by them in the exchange offer to the public without delivering a prospectus,

then, we will, subject to certain exceptions,

(1) file a shelf registration statement with the SEC covering resales of the old notes or the new notes, as the case may be, as promptly as practicable, but in no event more than 45 days after so required or requested (which we call the shelf filing date);

(2) use our best efforts to cause the shelf registration statement to be declared effective under the Securities Act; and

(3) use commercially reasonable efforts to keep the shelf registration statement continuously effective until the earliest of (A) two years from the effective date of the shelf registration statement, (B) the date on which all old notes or new notes registered thereunder are sold and (C) the time when the old notes or the new notes covered by the shelf registration statement are no longer restricted securities (as defined in Rule 144 under the Securities Act).

We will, in the event a shelf registration statement is filed, among other things, provide to each holder for whom such shelf registration statement was filed copies of the prospectus which is a part of the shelf registration statement, notify each such holder when the shelf registration statement has become effective and take certain other actions as are required to permit unrestricted resales of the old notes or the new notes, as the case may be. A holder selling such old notes or new notes pursuant to the shelf registration statement generally would be required to be named as a selling security holder in the related prospectus and to deliver a prospectus to purchasers, will be subject to certain of the civil liability provisions under the Securities Act in connection with such sales and will be bound by the provisions of the registration rights agreement that are applicable to such holder (including certain indemnification obligations).

We will pay additional cash interest on the applicable old notes and new notes, subject to certain exceptions:

(1) if we fail to file the registration statement of which this prospectus forms a part with the SEC on or prior to the 90th day after the consummation of the North Coast acquisition;

(2) if the registration statement of which this prospectus forms a part is not declared effective by the SEC on or prior to the 180th day after the consummation of the North Coast acquisition or, if obligated to file a shelf registration statement under section 2(i) of either registration rights agreement, the shelf registration statement is not declared effective on or prior to the 180th day after the consummation of the North Coast acquisition;

(3) if the exchange offer is not consummated on or before the 40th day after the registration statement of which this prospectus forms a part is declared effective;

(4) if obligated to file the shelf registration statement under section 2(ii), (iii) or (iv) of either registration rights agreement, we fail to file the shelf registration statement with the SEC on or prior to the shelf filing date;

(5) if obligated to file a shelf registration statement under section 2(ii), (iii) or (iv) of either registration rights agreement, the shelf registration statement is not declared effective on or prior to the 90th day after the shelf filing date; or

(6) after the registration statement of which this prospectus forms a part or the shelf registration statement, as the case may be, is declared effective, such registration statement thereafter ceases to be effective or usable (subject to certain exceptions);

from and including the date on which any such default shall occur to but excluding the date on which all such defaults have been cured.

The rate of any such additional interest will be 0.50% per annum for the first 90-day period immediately following the occurrence of the default, and such rate shall increase by an additional 0.50% per annum with respect to each subsequent 90-day period until all defaults have been cured, up to a maximum interest rate of 1.5% per annum. We will pay any such additional interest on regular interest payment dates. Such additional interest will be in addition to any other interest payable from time to time with respect to the old notes and the new notes.

All references in the indenture, in any context, to any interest or other amount payable on or with respect to the old notes or the new notes shall be deemed to include any additional interest pursuant to either registration rights agreement relating to the old notes.

If we effect the exchange offer, we will be entitled to close the exchange offer 30 days after the commencement thereof provided that we have accepted all old notes theretofore validly tendered in accordance with the terms of the exchange offer.

Background Of The Exchange Offer

We issued an aggregate of $350.0 million principal amount of our old notes on January 20, 2004 and an additional $100.0 million principal amount of our old notes on April 13, 2004 under the indenture. The maximum principal amount of the new notes that will be issued in this exchange offer for the old notes is $450.0 million. The terms of the new notes and the old notes will be identical in all material respects except that the new notes will be registered under the Securities Act and will not have restrictions on transfer and registration rights. The new notes and the old notes not exchanged in the exchange offer will constitute a single class of debt securities under the indenture.

The new notes will bear interest at a rate of 7¹/4% per year, payable semiannually on January 15 and July 15 of each year, beginning on July 15, 2004. Interest on each new note will accrue from the last interest payment date on which interest was paid on the old note surrendered in exchange therefor, or, if no interest has been paid on such old note, from January 20, 2004.

In order to exchange your old notes for the new notes containing no transfer restrictions in the exchange offer, you will be required to make the following representations:

•: the new notes will be acquired in the ordinary course of your business;
•: you have no arrangements with any person to participate in the distribution of the new notes; and
•: you are not our "affiliate" as defined in Rule 405 of the Securities Act, or if you are an affiliate of EXCO, you will comply with the applicable registration and prospectus delivery requirements of the Securities Act.

Upon the terms and subject to the conditions set forth in this prospectus and in the letter of transmittal, we will accept for exchange any old notes properly tendered and not validly withdrawn in the exchange offer, and the exchange agent will deliver the new notes promptly after the expiration date of the exchange offer. We expressly reserve the right to delay acceptance of any of the tendered old notes or terminate the exchange offer and not accept for exchange any tendered old notes not already accepted if any conditions set forth under "—Conditions to the Exchange Offer" have not been satisfied or waived by us or do not comply, in whole or in part, with any applicable law.

If you tender your old notes, you will not be required to pay brokerage commissions or fees or, subject to the instructions in the letter of transmittal, transfer taxes with respect to the exchange of the old notes. We will pay all charges, expenses and transfer taxes in connection with the exchange offer, other than certain taxes described below under "—Transfer Taxes."

Expiration Date; Extensions; Termination; Amendments

The exchange offer will expire at 5:00 p.m., Eastern Time, on May 28, 2004, unless we extend it. We expressly reserve the right to extend the exchange offer on a daily basis or for such period or periods as we may determine in our sole discretion from time to time by giving oral, confirmed in writing, or written notice to the exchange agent and by making a public announcement by press release to the Dow Jones News Service prior to 9:00 a.m., Eastern Time, on the first business day following the previously scheduled expiration date. During any extension of the exchange offer, all old notes previously tendered, not validly withdrawn and not accepted for exchange will remain subject to the exchange offer and may be accepted for exchange by us.

To the extent we are legally permitted to do so, we expressly reserve the absolute right, in our sole discretion, but are not required, to:

•: waive any condition of the exchange offer; and
•: amend any terms of the exchange offer.

Any waiver or amendment to the exchange offer will apply to all old notes tendered, regardless of when or in what order the old notes were tendered. If we make a material change in the terms of the exchange offer or if we waive a material condition of the exchange offer, we will disseminate additional exchange offer materials, and we will extend the exchange offer to the extent required by law.

We expressly reserve the right, in our sole discretion, to terminate the exchange offer if any of the conditions set forth under "—Conditions to the Exchange Offer" have not been satisfied or waived. Any such termination will be followed promptly by a public announcement. In the event we terminate the exchange offer, we will give immediate notice to the exchange agent, and all old notes previously tendered and not accepted for exchange will be returned promptly to the tendering holders.

In the event that the exchange offer is withdrawn or otherwise not completed, the new notes will not be given to holders of old notes who have validly tendered their old notes. We will return any old notes that have been tendered for exchange but that are not exchanged for any reason to their holder

without cost to the holder, or, in the case of the old notes tendered by book-entry transfer into the exchange agent's account at a book-entry transfer facility under the procedure set forth under "—Procedures for Tendering Old Notes—Book-Entry Transfer," such old notes will be credited to the account maintained at such book-entry transfer facility from which such old notes were delivered, unless otherwise requested by such holder under "Special Delivery Instructions" in the letter of transmittal, promptly following the exchange date or the termination of the exchange offer.

Resale Of The New Notes

Based on interpretations of the SEC set forth in no-action letters issued to third parties, we believe that the new notes issued under the exchange offer in exchange for the old notes may be offered for resale, resold and otherwise transferred by you without compliance with the registration and prospectus delivery provisions of the Securities Act, if:

•: you are not an "affiliate" of ours within the meaning of Rule 405 under the Securities Act;
•: you are acquiring the new notes in the ordinary course of your business; and
•: you do not intend to participate in the distribution of the new notes.

If you tender old notes in the exchange offer with the intention of participating in any manner in a distribution of the new notes:

•: you cannot rely on those interpretations of the SEC; and
•: you must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a secondary resale transaction, and the secondary resale transaction must be covered by an effective registration statement containing the selling security holder information required by Item 507 or 508, as applicable, of Regulation S-K under the Securities Act.

Unless an exemption from registration is otherwise available, any security holder intending to distribute the new notes should be covered by an effective registration statement under the Securities Act containing the selling security holder's information required by Item 507 of Regulation S-K. This prospectus may be used for an offer to resell, a resale or other re-transfer of the new notes only as specifically set forth in the section captioned "Plan of Distribution." Only broker-dealers that acquired the new notes as a result of market-making activities or other trading activities may participate in the exchange offer. Each broker-dealer that receives the new notes for its own account in exchange for old notes, where such old notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of the new notes. Please read the section captioned "Plan of Distribution" for more details regarding the transfer of the new notes.

Acceptance Of Old Notes For Exchange

We will accept for exchange old notes validly tendered pursuant to the exchange offer, or defectively tendered, if such defect has been waived by us, after the later of:

•: the expiration date of the exchange offer; and
•: the satisfaction or waiver of the conditions specified below under "—Conditions to the Exchange Offer."

Except as specified above, we will not accept old notes for exchange subsequent to the expiration date of the exchange offer. Tenders of old notes will be accepted only in principal amounts equal to $1,000 or integral multiples thereof.

We expressly reserve the right, in our sole discretion, to:

•: delay acceptance for exchange of old notes tendered under the exchange offer, subject to Rule 14e-1 under the Exchange Act, which requires that an offeror pay the consideration offered or return the securities deposited by or on behalf of the holders promptly after the termination or withdrawal of a tender offer; or
•: terminate the exchange offer and not accept for exchange any old notes, if any of the conditions set forth below under "—Conditions to the Exchange Offer" have not been satisfied or waived by us or in order to comply in whole or in part with any applicable law.

In all cases, the new notes will be issued only after timely receipt by the exchange agent of certificates representing old notes, or confirmation of book-entry transfer, a properly completed and duly executed letter of transmittal, or a manually signed facsimile thereof, and any other required documents. For purposes of the exchange offer, we will be deemed to have accepted for exchange validly tendered old notes, or defectively tendered old notes with respect to which we have waived such defect, if, as and when we give oral, confirmed in writing, or written notice to the exchange agent. Promptly after the expiration date, we will deposit the new notes with the exchange agent, who will act as agent for the tendering holders for the purpose of receiving the new notes and transmitting them to the holders. The exchange agent will deliver the new notes to holders of old notes accepted for exchange after the exchange agent receives the new notes.

If, for any reason, we delay acceptance for exchange of validly tendered old notes or we are unable to accept for exchange validly tendered old notes, then the exchange agent may, nevertheless, on its behalf, retain tendered old notes, without prejudice to our rights described in this prospectus under the captions "—Expiration Date; Extensions; Termination; Amendments," "—Conditions to the Exchange Offer" and "—Withdrawal of Tenders," subject to Rule 14e-1 under the Securities Exchange Act of 1934, which requires that an offeror pay the consideration offered or return the securities deposited by or on behalf of the holders thereof promptly after the termination or withdrawal of a tender offer.

If any tendered old notes are not accepted for exchange for any reason, or if certificates are submitted evidencing more old notes than those that are tendered, certificates evidencing old notes that are not exchanged will be returned, without expense, to the tendering holder, or, in the case of the old notes tendered by book-entry transfer into the exchange agent's account at a book-entry transfer facility under the procedure set forth under "—Procedures for Tendering Old Notes—Book-Entry Transfer," such old notes will be credited to the account maintained at such book-entry transfer facility from which such old notes were delivered, unless otherwise requested by such holder under "Special Delivery Instructions" in the letter of transmittal, promptly following the exchange date or the termination of the exchange offer.

Tendering holders of old notes exchanged in the exchange offer will not be obligated to pay brokerage commissions or transfer taxes with respect to the exchange of their old notes other than as described under the caption "—Transfer Taxes" or as set forth in the letter of transmittal. We will pay all other charges and expenses in connection with the exchange offer.

Procedures For Tendering Old Notes

Any beneficial owner whose old notes are registered in the name of a broker, dealer, commercial bank, trust company or other nominee or held through a book-entry transfer facility and who wishes to tender old notes should contact such registered holder promptly and instruct such registered holder to tender old notes on such beneficial owner's behalf.

Tender Of Old Notes Held Through The Depository Trust Company

The exchange agent and The Depository Trust Company, or DTC, have confirmed that the exchange offer is eligible for the DTC automated tender offer program. Accordingly, DTC participants may electronically transmit their acceptance of the exchange offer by causing DTC to transfer old notes to the exchange agent in accordance with DTC's automated tender offer program procedures for transfer. DTC will then send an agent's message to the exchange agent.

The term "agent's message" means a message transmitted by DTC and received by the exchange agent that forms part of the book-entry confirmation. The agent's message states that DTC has received an express acknowledgment from the participant in DTC tendering old notes that are the subject of that book-entry confirmation, that the participant has received and agrees to be bound by the terms of the letter of transmittal, and that we may enforce such agreement against such participant. In the case of an agent's message relating to guaranteed delivery, the term means a message transmitted by DTC and received by the exchange agent, which states that DTC has received an express acknowledgment from the participant in DTC tendering old notes that they have received and agree to be bound by the notice of guaranteed delivery.

Tender Of Old Notes Held In Physical Form

For a holder to validly tender old notes held in physical form:

•: the exchange agent must receive at its address set forth in this prospectus a properly completed and validly executed letter of transmittal, or a manually signed facsimile thereof, together with any signature guarantees and any other documents required by the instructions to the letter of transmittal; and
•: the exchange agent must receive certificates for tendered old notes at such address, or such old notes must be transferred pursuant to the procedures for book-entry transfer described above. A confirmation of such book-entry transfer must be received by the exchange agent prior to the expiration date of the exchange offer. A holder who desires to tender old notes and who cannot comply with the procedures set forth herein for tender on a timely basis or whose old notes are not immediately available must comply with the procedures for guaranteed delivery set forth below.

LETTERS OF TRANSMITTAL AND OLD NOTES SHOULD BE SENT ONLY TO THE EXCHANGE AGENT, AND NOT TO US OR TO ANY BOOK-ENTRY TRANSFER FACILITY.

THE METHOD OF DELIVERY OF OLD NOTES, LETTERS OF TRANSMITTAL AND ALL OTHER REQUIRED DOCUMENTS TO THE EXCHANGE AGENT IS AT THE ELECTION AND RISK OF THE HOLDER TENDERING OLD NOTES. DELIVERY OF SUCH DOCUMENTS WILL BE DEEMED MADE ONLY WHEN ACTUALLY RECEIVED BY THE EXCHANGE AGENT. IF SUCH DELIVERY IS BY MAIL, WE SUGGEST THAT THE HOLDER USE PROPERLY INSURED, REGISTERED MAIL WITH RETURN RECEIPT REQUESTED, AND THAT THE MAILING BE MADE SUFFICIENTLY IN ADVANCE OF THE EXPIRATION DATE OF THE EXCHANGE OFFER TO PERMIT DELIVERY TO THE EXCHANGE AGENT PRIOR TO SUCH DATE. NO ALTERNATIVE, CONDITIONAL OR CONTINGENT TENDERS OF OLD NOTES WILL BE ACCEPTED.

Signature Guarantees

A signature on a letter of transmittal or a notice of withdrawal must be guaranteed by an eligible institution. Eligible institutions include banks, brokers, dealers, municipal securities dealers, municipal securities brokers, government securities dealers, government securities brokers, credit unions, national

securities exchanges, registered securities associations, clearing agencies and savings associations. The signature need not be guaranteed by an eligible institution if the old notes are tendered:

•: by a registered holder who has not completed the box entitled "Special Issuance Instructions" or "Special Delivery Instructions" on the letter of transmittal; or
•: for the account of an eligible institution.

If the letter of transmittal is signed by a person other than the registered holder of any old notes, the old notes must be endorsed or accompanied by a properly completed bond power. The bond power must be signed by the registered holder as the registered holder's name appears on the old notes and an eligible institution must guarantee the signature on the bond power.

If the letter of transmittal or any old notes or bond powers are signed by trustees, executors, administrators, guardians, attorneys-in-fact, officers of corporations or others acting in a fiduciary or representative capacity, these persons should so indicate when signing. Unless we waive this requirement, they should also submit evidence satisfactory to us of their authority to deliver the letter of transmittal.

Book-Entry Transfer

The exchange agent will seek to establish a new account or utilize an existing account with respect to the old notes at DTC promptly after the date of this prospectus. Any financial institution that is a participant in the book-entry transfer facility system and whose name appears on a security position listing it as the owner of the old notes may make book-entry delivery of old notes by causing the book-entry transfer facility to transfer such old notes into the exchange agent's account. HOWEVER, ALTHOUGH DELIVERY OF OLD NOTES MAY BE EFFECTED THROUGH BOOK-ENTRY TRANSFER INTO THE EXCHANGE AGENT'S ACCOUNT AT A BOOK-ENTRY TRANSFER FACILITY, A PROPERLY COMPLETED AND VALIDLY EXECUTED LETTER OF TRANSMITTAL, OR A MANUALLY SIGNED FACSIMILE THEREOF, MUST BE RECEIVED BY THE EXCHANGE AGENT AT ITS ADDRESS SET FORTH IN THIS PROSPECTUS ON OR PRIOR TO THE EXPIRATION DATE OF THE EXCHANGE OFFER, OR ELSE THE GUARANTEED DELIVERY PROCEDURES DESCRIBED BELOW MUST BE COMPLIED WITH. The confirmation of a book-entry transfer of old notes into the exchange agent's account at a book-entry transfer facility is referred to in this prospectus as a "book-entry confirmation." Delivery of documents to the book-entry transfer facility in accordance with that book-entry transfer facility's procedures does not constitute delivery to the exchange agent.

Guaranteed Delivery

If you wish to tender your old notes and:

•: certificates representing your old notes are not lost but are not immediately available;
•: time will not permit your letter of transmittal, certificates representing your old notes and all other required documents to reach the exchange agent on or prior to the expiration date of the exchange offer; or
•: the procedures for book-entry transfer cannot be completed on or prior to the expiration date of the exchange offer;

you may tender your old notes if:

•: your tender is made by or through an eligible institution; and
•: on or prior to the expiration date of the exchange offer, the exchange agent has received from the eligible institution a properly completed and validly executed notice of guaranteed delivery,

by manually signed facsimile transmission, mail or hand delivery, in substantially the form provided with this prospectus:

•: setting forth your name and address, the registered number(s) of your old notes and the principal amount of the old notes tendered;
•: stating that the tender is being made by guaranteed delivery;
•: guaranteeing that, within three New York Stock Exchange trading days after the date of the notice of guaranteed delivery, the letter of transmittal or facsimile thereof, properly completed and validly executed, together with certificates representing the old notes, or a book-entry confirmation, and any other documents required by the letter of transmittal and the instructions thereto, will be deposited by the eligible institution with the exchange agent; and
•: the exchange agent receives the properly completed and validly executed letter of transmittal or facsimile thereof with any required signature guarantees, together with certificates for all old notes in proper form for transfer, or a book-entry confirmation, and any other required documents, within three New York Stock Exchange trading days after the date of the notice of guaranteed delivery.

Other Matters

New notes will be issued in exchange for old notes accepted for exchange only after timely receipt by the exchange agent of:

•: certificates for, or a timely book-entry confirmation with respect to, your old notes;
•: a properly completed and duly executed letter of transmittal or facsimile thereof with any required signature guarantees, or, in the case of a book-entry transfer, an agent's message; and
•: any other documents required by the letter of transmittal.

All questions as to the form of all documents and the validity, including time of receipt, and acceptance of all tenders of old notes will be determined by us, in our sole discretion, the determination of which shall be final and binding. ALTERNATIVE, CONDITIONAL OR CONTINGENT TENDERS OF OLD NOTES WILL NOT BE CONSIDERED VALID. We reserve the absolute right to reject any or all tenders of old notes that are not in proper form or the acceptance of which, in our opinion, would be unlawful. We also reserve the right to waive any defects, irregularities or conditions of tender as to any particular old notes. Our interpretation of the terms and conditions of the exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties.

Unless waived by us, any defect or irregularity in connection with tenders of old notes must be cured within the time that we determine. Tenders of old notes will not be deemed to have been made until all defects and irregularities have been waived by us or cured. Neither us, the exchange agent, or any other person will be under any duty to give notice of any defects or irregularities in tenders of old notes, or will incur any liability to holders for failure to give any such notice.

By signing or agreeing to be bound by the letter of transmittal, you will represent to us that, among other things:

•: any new notes that you receive will be acquired in the ordinary course of your business;
•: you have no arrangement or understanding with any person or entity to participate in the distribution of the new notes;

•: if you are not a broker-dealer, that you are not engaged in and do not intend to engage in the distribution of the new notes;
•: if you are a broker-dealer that will receive the new notes for your own account in exchange for old notes that were acquired as a result of market-making activities or other trading activities, that you may not rely on the position of the SEC enunciated in Morgan Stanley & Co. Incorporated (available June 5, 1991) and Exxon Capital Holdings Corporation (available May 13, 1998), as interpreted in the SEC's letter to Shearman & Sterling (available July 2, 1993), and similar no-action letters and you will deliver a prospectus, as required by law, in connection with any resale of the new notes; and
•: you are not an "affiliate" of ours, as defined in Rule 405 of the Securities Act, or, if you are an affiliate, you will comply with any applicable registration and prospectus delivery requirements of the Securities Act.

Withdrawal Of Tenders

Except as otherwise provided in this prospectus, you may withdraw your tender of old notes at any time prior to the expiration date of the exchange offer.

For a withdrawal to be effective:

•: the exchange agent must receive a written notice of withdrawal at the address set forth below under "—Exchange Agent"; or
•: you must comply with the appropriate procedures of DTC's automated tender offer program system.

Any notice of withdrawal must:

•: specify the name of the person who tendered the old notes to be withdrawn; and
•: identify the old notes to be withdrawn, including the principal amount of the old notes to be withdrawn.

If certificates for the old notes have been delivered or otherwise identified to the exchange agent, then, prior to the release of those certificates, the withdrawing holder must also submit:

•: the serial numbers of the particular certificates to be withdrawn; and
•: a signed notice of withdrawal with signatures guaranteed by an eligible institution, unless the withdrawing holder is an eligible institution.

If the old notes have been tendered pursuant to the procedure for book-entry transfer described above, any notice of withdrawal must specify the name and number of the account at DTC to be credited with the withdrawn old notes and otherwise comply with the procedures of DTC.

We will determine all questions as to the validity, form and eligibility, including time of receipt, of notices of withdrawal, and our determination shall be final and binding on all parties. We will deem any old notes so withdrawn not to have been validly tendered for exchange for purposes of the exchange offer.

We will return any old notes that have been tendered for exchange but that are not exchanged for any reason to their holder without cost to the holder. In the case of old notes tendered by book-entry transfer into the exchange agent's account at DTC, according to the procedures described above, those old notes will be credited to an account maintained with DTC for the old notes. This return or crediting will take place as soon as practicable after withdrawal, rejection of tender or termination of the exchange offer. You may re-tender properly withdrawn old notes by following one of the

procedures described under "—Procedures for Tendering Old Notes" at any time on or prior to the expiration date of the exchange offer.

Conditions To The Exchange Offer

Despite any other term of the exchange offer, we will not be required to accept for exchange any old notes and we may terminate or amend the exchange offer as provided in this prospectus before accepting any old notes for exchange if in our reasonable judgment:

•: the new notes to be received will not be tradable by the holder without restriction under the Securities Act and the Exchange Act and without material restrictions under the blue sky or securities laws of substantially all of the states of the United States;
•: the exchange offer, or the making of any exchange by a holder of old notes, would violate applicable law or any applicable interpretation of the staff of the SEC; or
•: any action or proceeding has been instituted or threatened in any court or by or before any governmental agency with respect to the exchange offer that would reasonably be expected to impair our ability to proceed with the exchange offer.

We will not be obligated to accept for exchange the old notes of any holder that has not made to us:

•: the representations described under the captions "—Procedures for Tendering Old Notes" and "Plan of Distribution;" and
•: any other representations that may be reasonably necessary under applicable SEC rules, regulations or interpretations to make available to us an appropriate form for registration of the new notes under the Securities Act.

We expressly reserve the right, at any time or at various times, to extend the period of time during which the exchange offer is open. Consequently, we may delay acceptance of any old notes by giving oral or written notice of an extension to their holders. During an extension, all old notes previously tendered will remain subject to the exchange offer, and we may accept them for exchange. We will return any old notes that we do not accept for exchange for any reason without expense to their tendering holder promptly after the expiration or termination of the exchange offer.

We expressly reserve the right to amend or terminate the exchange offer and to reject for exchange any old notes not previously accepted for exchange, upon the occurrence of any of the conditions of the exchange offer specified above. By public announcement we will give oral or written notice of any extension, amendment, non-acceptance or termination to the holders of the old notes promptly. If we amend the exchange offer in a manner that we consider material, we will disclose the amendment in the manner required by applicable law.

These conditions are solely for our benefit and we may assert them regardless of the circumstances that may give rise to them or waive them in whole or in part at any time or at various times in our sole discretion. If we fail at any time to exercise any of the foregoing rights, this failure will not constitute a waiver of that right. Each of these rights will be deemed an ongoing right that we may assert at any time or at various times. All conditions to the exchange offer, other than those conditions subject to government approvals, will be satisfied or waived prior to the expiration of the exchange offer.

We will not accept for exchange any old notes tendered, and will not issue the new notes in exchange for any old notes, if at any time a stop order is threatened or in effect with respect to the registration statement of which this prospectus constitutes a part or the qualification of the indenture under the Trust Indenture Act of 1939.

Transfer Taxes

We will pay all transfer taxes, if any, applicable to the transfer and exchange of old notes pursuant to the exchange offer. The tendering holder, however, will be required to pay any transfer taxes, whether imposed on the record holder or any other person, if:

•: delivery of the new notes, or certificates for old notes for principal amounts not exchanged, are to be made to any person other than the record holder of the old notes tendered;
•: tendered certificates for old notes are recorded in the name of any person other than the person signing any letter of transmittal; or
•: a transfer tax is imposed for any reason other than the transfer and exchange of old notes under the exchange offer.

Consequences Of Failure To Exchange

If you do not exchange your old notes for the new notes in the exchange offer, you will remain subject to restrictions on transfer of the old notes:

•: as set forth in the legend printed on the old notes as a consequence of the issuance of the old notes pursuant to the exemptions from, or in transactions not subject to, the registration requirements of the Securities Act and applicable state securities laws; and
•: as otherwise set forth in the prospectus distributed in connection with each of the private offerings of the old notes.

In general, you may not offer or sell the old notes unless they are registered under the Securities Act, or if the offer or sale is exempt from registration under the Securities Act and applicable state securities laws. Except as required by the registration rights agreements relating to the old notes, we do not intend to register resales of the old notes under the Securities Act. Based on interpretations of the SEC, you may offer for resale, resell or otherwise transfer the new notes issued in the exchange offer without compliance with the registration and prospectus delivery provisions of the Securities Act, provided that:

•: you are not an "affiliate" within the meaning of Rule 405 under the Securities Act;
•: you acquired the new notes in the ordinary course of your business; and
•: you have no arrangement or understanding with respect to the distribution of the new notes to be acquired in the exchange offer.

If you tender old notes in the exchange offer for the purpose of participating in a distribution of the new notes:

•: you cannot rely on the applicable interpretations of the SEC; and
•: you must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a secondary resale transaction and that such a secondary resale transaction must be covered by an effective registration statement containing the selling security holder information required by Item 507 or 508, as applicable, of Regulation S-K under the Securities Act.

Accounting Treatment

The new notes will be recorded at the same carrying value as the old notes as reflected in our accounting records on the date of the exchange. Accordingly, we will not recognize any gain or loss for accounting purposes upon the completion of the exchange offer. The expenses of the exchange offer

that we pay will increase our deferred financing costs in accordance with generally accepted accounting principles.

Fees and Expenses

We will bear the expenses of soliciting tenders. The principal solicitation is being made by mail; however, we may make additional solicitation by telegraph, telephone or in person by our officers and regular employees and those of our affiliates.

We have not retained any dealer-manager in connection with the exchange offer and will not make any payments to broker-dealers or others soliciting acceptances of the exchange offer. We will, however, pay the exchange agent reasonable and customary fees for its services and reimburse it for its related reasonable out-of-pocket expenses.

We will pay the cash expenses to be incurred in connection with the exchange offer. They include:

•: SEC registration fees;
•: fees and expenses of the exchange agent and trustee;
•: accounting and legal fees and printing costs; and
•: related fees and expenses.

Exchange Agent

Wilmington Trust Company has been appointed as exchange agent for the exchange offer. You should direct questions and requests for assistance, requests for additional copies of this prospectus, the letter of transmittal or any other documents to the exchange agent. You should send certificates for old notes, letters of transmittal and any other required documents to the exchange agent addressed as follows:

Wilmington Trust Company
By Registered or Certified Mail: Wilmington Trust Company DC-1626 Processing Unit PO Box 8861 Wilmington, DE 19899-8861		By Hand or Overnight Delivery: Wilmington Trust Company Corporate Capital Markets 1100 North Market St Wilmington, DE 19890-1626		Facsimile Transmissions: (Eligible Institutions Only) (302) 636-4145 To Confirm by Telephone or for Information Call: (302) 636-6470

Delivery of the letter of transmittal to an address other than as shown above or transmission via facsimile other than as set forth above does not constitute a valid delivery of the letter of transmittal.

Other

Participation in the exchange offer is voluntary, and you should carefully consider whether to exchange the old notes for the new notes. We urge you to consult your financial and tax advisors in making your own decision on what action to take.

We may in the future seek to acquire untendered old notes in open market or privately negotiated transactions, through subsequent exchange offers or otherwise, on terms that may differ from the terms of the exchange offer. We have no present plans to acquire any old notes that are not tendered in the exchange offer or to file a registration statement to permit resales of any untendered old notes.

USE OF PROCEEDS

The exchange offer is intended to satisfy our obligations under the registration rights agreements. We will not receive any proceeds from the exchange or the issuance of the new notes in connection with the exchange offer. In consideration for issuing the new notes as contemplated by this prospectus, we will receive old notes in like principal amount. The form and terms of the new notes are identical in all respects to the form and terms of the old notes, except the new notes are registered under the Securities Act and will not have restrictions on transfer or registration rights. Old notes surrendered in exchange for the new notes will be retired and cancelled and will not be reissued. Accordingly, the issuance of the new notes will not result in any increase in our outstanding indebtedness.

CAPITALIZATION

The following table sets forth the unaudited cash and cash equivalents and the capitalization of EXCO at December 31, 2003 on an actual basis and on an as adjusted basis, assuming the Transactions occurred on that date. This table should be read in conjunction with our historical consolidated financial statements and related notes, the historical consolidated financial statements and related notes of North Coast, our unaudited pro forma consolidated financial statements and related notes, "Management's Discussion and Analysis of Financial Condition and Results of Operations" and other financial information included elsewhere in this prospectus.

		As of December 31, 2003
		Actual		As Adjusted
		(Dollars in thousands)
Cash and cash equivalents		$	7,333	$	24,976	(1)

Total debt:
	Credit facilities(2)	$	157,951	$	—	(3)
	Senior term loan		50,000		—	(3)
	Old notes		—		453,250	(4)

	Total debt		207,951		453,250

Stockholders' equity:
	Common stock		1		1
	Additional paid-in capital		172,045		172,045
	Retained earnings		4,177		2,489	(5)
	Other comprehensive income		7,646		7,646

	Total stockholders' equity		183,869		182,181

	Total capitalization	$	391,820	$	635,431

(1): See our Unaudited Pro Forma Condensed Consolidated Balance Sheet as of December 31, 2003 and note (c) thereto for a description of the changes to cash and cash equivalents.
(2): At April 15, 2004, after consideration of the issuance of old notes on April 13, 2004, our credit facilities have a maximum committed amount of $325.0 million, with a borrowing base of approximately $200.0 million.
(3): The following table describes certain changes to our outstanding indebtedness since December 31, 2003 and as adjusted for the Transactions.

In conjunction with the completion of the North Coast acquisition, we refinanced secured indebtedness of North Coast with our amended and restated credit facilities. The amount outstanding under North Coast's previous credit facility as of December 31, 2003 was $57.0 million.

	Total
	(Dollars in thousands)
Debt outstanding under EXCO credit facilities	$	157,951
Debt outstanding under EXCO senior term loan		50,000

Total debt outstanding as of December 31, 2003		207,951
Refinancing of North Coast indebtedness		57,000
Proceeds from the $350.0 million offering of old notes, net of fees, expenses and use of $167.8 million to fund the North Coast acquisition		(171,327	)
Proceeds from the $100.0 million offering of old notes, net of fees and expenses		(93,624	)

Adjusted debt outstanding under credit facilities	$	—

(4): Old notes as adjusted includes $3.2 million of premium related to the old notes issued on April 13, 2004.
(5): The reduction in retained earnings reflects the expensing of costs incurred to obtain a commitment for bridge loan financing that was not utilized as a result of the issuance on January 20, 2004 of the old notes, and the write-off of deferred financing costs related to the senior term loan that was retired as discussed in Note (3) above.

UNAUDITED PRO FORMA FINANCIAL DATA

The following unaudited pro forma condensed consolidated balance sheet as of December 31, 2003 is based on EXCO's (successor basis) and North Coast's audited historical consolidated balance sheets as of December 31, 2003 and gives effect to the Transactions as if each had occurred on December 31, 2003.

The unaudited pro forma condensed consolidated statement of operations for the year ended December 31, 2003 has been derived from our audited consolidated statement of operations for the 209 day period ended July 28, 2003 (predecessor basis), our audited consolidated financial statements for the 156 day period ended December 31, 2003 (successor basis) and North Coast's audited consolidated financial statements for the year ended December 31, 2003. The pro forma statement of operations gives effect to the following events as if each occurred on January 1, 2003:

•: Our going private transaction, which occurred on July 29, 2003, and pursuant to which a change in control of EXCO was effected through the purchase of each outstanding common share, other than common shares held by EXCO Holdings and its affiliates. As a result of the going private transaction, we became a wholly-owned subsidiary of EXCO Holdings, our parent. As a result of the change in control, Generally Accepted Accounting Principles (GAAP) requires the acquisition by EXCO Holdings to be accounted for as a purchase transaction in accordance with Statement of Financial Accounting Standards No. 141, "Business Combinations." GAAP requires the application of "push down accounting" in situations where the ownership of an entity has changed, meaning that the post-transaction financial statements of the acquired entity reflect a new basis of accounting in accordance with Staff Accounting Bulletin No. 54. The aggregate purchase price has been allocated to the underlying assets and liabilities based upon their respective estimated fair market values at the date of acquisition. For tax reporting purposes, we received carry over tax basis. See Note 1 to the December 31, 2003 consolidated financial statements.
•: Our acquisition of North Coast for a purchase price of approximately $225.4 million. The North Coast acquisition will be accounted for using the purchase method of accounting in accordance with Statement of Financial Accounting Standards No. 141, "Business Combinations." Accordingly, the pro forma financial statements reflect the allocation of the purchase price to the underlying assets and liabilities based upon their estimated fair values. For tax purposes we will also receive a step up in tax basis equal to the purchase price.
•: Adjustments to conform North Coast's historical accounting policies related to oil and natural gas properties from successful efforts to full cost accounting.
•: The issuance of the old notes.
•: The assumption of North Coast's debt and repayment of our and North Coast's credit facilities.
•: The payment of our related fees and expenses.

The unaudited pro forma financial statements should be read in conjunction with the accompanying notes to unaudited pro forma financial statements, our historical consolidated financial statements and related notes and the historical consolidated financial statements and related notes of North Coast, "Management's Discussion and Analysis of Financial Condition and Results of Operations" and other financial information contained in this prospectus. The pro forma information presented herein does not purport to be indicative of the financial position or results of operations that would have actually occurred had the Transactions and the going private transaction occurred on the dates indicated or which may occur in the future.

After we have completed the valuation studies necessary to finalize the required North Coast purchase price allocations, the unaudited pro forma financial information will be subject to adjustment.

Such adjustments will likely result in changes to the unaudited pro forma condensed consolidated balance sheet and the unaudited pro forma condensed consolidated statements of operations to reflect, among other things, the final allocation of the purchase price. There can be no assurance that such changes will not be material.

Unaudited Pro Forma Condensed Consolidated
Balance Sheet as of December 31, 2003

		EXCO Historical		North Coast Historical(a)		Adjustments for the Transactions(b)			Pro Forma
		(Dollars in thousands)
Assets:
Current Assets
	Cash and cash equivalents	$	7,333	$	20,248	$	(2,605	)(c)	$	24,976
	Other current assets		24,236		11,145		—			35,381

	Total current assets		31,569		31,393		(2,605	)		60,357
Oil and natural gas properties and other equipment, net			415,044		141,654		84,070	(d)		640,768
Goodwill			53,346		—		—			53,346
Deferred financing costs			1,565		—		9,789	(e)(h)		11,354
Other assets			3,506		415		(393	)(d)		3,528

	Total assets	$	505,030	$	173,462	$	90,861		$	769,353

Liabilities and Stockholders' Equity:
Current Liabilities
	Liabilities from commodity price and interest rate risk management activities	$	12,804	$	3,759	$	—		$	16,563
	Other current liabilities		32,384		12,705		—			45,089

	Total current liabilities		45,188		16,464		—			61,652
Total long-term debt			207,951		57,000		178,673 9,626	(f) (i)		453,250
Deferred income taxes			45,899		17,241		(18,632	)(d)		44,508
Liabilities from commodity price risk management activities			3,780		—		—			3,780
Asset retirement obligations and other long-term liabilities			18,343		963		4,676	(d)		23,982

	Total liabilities		321,161		91,668		174,343			587,172

Commitments and contingencies			—		—		—			—
Stockholders' equity			183,869		81,794		(81,794 (1,688	)(g) )(h)		182,181

	Total liabilities and stockholders' equity	$	505,030	$	173,462	$	90,861		$	769,353

Notes to Unaudited Pro Forma Condensed
Consolidated Balance Sheet

(a): Represents historical information for North Coast as of December 31, 2003, as reported in or derived from its audited consolidated financial statements at December 31, 2003.
(b): Assumes the acquisition of North Coast had been consummated on December 31, 2003 for a purchase price of $225.4 million. The acquisition of North Coast will be accounted for as a purchase. The total estimated purchase price was calculated and allocated as follows (dollars in thousands):

Purchase Price Calculations:
	Payments for tendered shares including options and warrants	$	167,781
	Assumption of debt including interest expense		57,149
	Merger related costs		477

	Total North Coast acquisition costs	$	225,407

Allocation of purchase price:
	Oil and natural gas properties—proved	$	196,873
	Oil and natural gas properties—unproved		7,258
	Gas gathering assets and other equipment		21,593
	Other assets		22
	Deferred income tax asset		1,391
	Other current assets		20,373
	Accounts payable and accrued expenses		(12,705	)
	Asset retirement obligations		(5,639	)
	Liabilities from commodity price risk management activities		(3,759	)

	Total allocation	$	225,407

The purchase price allocation above is subject to completion of valuation studies and changes resulting from net cash flows between December 31, 2003 and the closing date of the North Coast acquisition.

(c): Assumes the estimated $11.0 million of transaction costs incurred by North Coast in January 2004 and not reflected in its December 31, 2003 balance sheet are funded from cash on hand at North Coast. These costs primarily include investment banking fees ($1.7 million), bonus pool and severance costs ($9.2 million) and other fees ($100,000) and are not capitalizable as part of the acquisition. Also, assumes net offering proceeds of $103.2 million, which includes a $3.2 million premium on the $100.0 million of old notes issued on April 13, 2004 less repayment of $93.6 million of the Canadian credit facility and less $1.2 million of financing costs related to that offering were added to cash. The remaining proceeds of $8.4 million would have been available for working capital. At April 15, 2004, no indebtedness was outstanding under the U.S. or Canadian credit facilities.
(d): Represents pro forma adjustments to allocate the purchase price to the estimated fair value of assets acquired and liabilities assumed based upon (b) above. The estimate of North Coast's asset retirement obligation is based upon EXCO's estimate of future abandonment costs and the report on proved reserves as prepared by Lee Keeling and Associates, Inc. as of December 31, 2003. North Coast's deferred income tax liability has been eliminated since EXCO received a step up in basis for book and tax purposes equal to the purchase price; however, a deferred income tax asset of approximately $1.4 million will be recognized based upon certain book to tax differences associated with current liabilities.

(e): Represents $1.7 million of capitalized financing costs related to the amended and restated credit facilities and $9.7 million of capitalized financing costs related to the issuances of the old notes. In addition, approximately $0.8 million of deferred financing costs had been paid and recognized on our December 31, 2003 consolidated balance sheet.
(f): Represents the $350.0 million of the old notes issued on January 20, 2004 less the repayment portion of the EXCO and North Coast credit facilities and senior term loan ($171.3 million). The change in debt is net of the repayment of the North Coast loan upon completion of the North Coast acquisition. For purposes of the pro forma condensed consolidated balance sheet, $167.8 million of the remaining proceeds of those old notes were used to pay for the North Coast tendered shares, including options and warrants, and $10.9 million of the remaining proceeds were used for debt issuance and transaction costs.
(g): Represents the elimination of North Coast's historical stockholders' equity in connection with purchase accounting.
(h): Represents the reduction in stockholders' equity for the $938,000 write-off of costs incurred in January 2004 to secure the bridge loan financing, which was not utilized upon issuance of the old notes on January 20, 2004 and deferred financing costs of approximately $750,000 related to the senior term loan, which was retired with the proceeds of the old notes issued on January 20, 2004.
(i): Represents the $100.0 million of old notes issued on April 13, 2004 plus $3.2 million of premium on those old notes less repayment of the Canadian credit facility ($93.6 million). At April 15, 2004, no indebtedness was outstanding under the U.S. or Canadian credit facilities.

Unaudited Pro Forma Condensed Consolidated Statement
of Operations for the Year Ended December 31, 2003

		EXCO
		Historical						Pro Forma
		209 Day Period from January 1 to July 28, 2003(a)			156 Day Period from July 29 to December 31, 2003(a)			Adjustments for the Going Private Transaction			Year Ended December 31, 2003			North Coast Historical(b)		Adjustments for the Transactions			Pro Forma
		(Dollars in thousands)
Revenues and other income:
Oil and natural gas		$	61,416		$	46,133		$	—		$	107,549		$	58,415	$	—		$	165,964
Commodity price risk management activities(c)			—			(11,160	)		—			(11,160	)		—		—			(11,160	)
Well operating, gathering and other			—			—			—			—			6,881		(3,637)	(d)		3,244
Other income (expense)			(1,033	)		239			—			(794	)		478		737	(d)		421

	Total revenues and other income		60,383			35,212			—			95,595			65,774		(2,900	)		158,469

Costs and expenses:
Oil and natural gas production			19,793			14,524			—			34,317			10,220		(641	)(d)		43,896
Well operating, gathering and other			—			—			—			—			5,211		(2,259	)(d)		2,952
Exploration expense			—			—			—			—			3,271		(3,271)	(e)		—
Depreciation, depletion and amortization			12,022			12,012			4,331	(f)		28,365			9,215		4,889	(g)		42,469
Accretion of asset retirement obligations			737			528			—			1,265			—		339	(h)		1,604
General and administrative			19,272			5,847			(10,050)	(i)		15,069			7,302		(1,501)	(j)		20,870
Interest			2,981			3,971			1,215	(k)		8,167			2,757		23,309	(l)		34,233

	Total costs and expenses		54,805			36,882			(4,504	)		87,183			37,976		20,865			146,024

Income (loss) before income taxes			5,578			(1,670	)		4,504			8,412			27,798		(23,765	)		12,445
Income tax expense (benefit)			4,801			(5,847	)		(711	)(m)		(1,757	)		9,791		(8,557)	(m)		(523	)

Net income (loss)		$	777		$	4,177		$	5,215		$	10,169		$	18,007	$	(15,208	)	$	12,968

Notes to Unaudited Pro Forma Condensed
Consolidated Statement of Operations

(a): A change in control of EXCO occurred on July 29, 2003 as a result of the going private transaction. Subsequent to this change in control, the financial statements reflect a new basis of accounting. See "Note 1—The Merger" of the notes to EXCO's December 31, 2003 consolidated financial statements included elsewhere in this prospectus.
(b): Represents historical information for North Coast as of December 31, 2003, as reported in or derived from its audited consolidated financial statements at December 31, 2003.
(c): Following the going private transaction, EXCO (successor basis) adopted the same accounting policies as EXCO (predecessor basis). Effective July 29, 2003, we no longer account for derivative financial instruments using hedge accounting. Instead, any change in fair value is recognized directly through the statement of operations. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies—Accounting for Derivatives." The pro forma statements of operations reflect the historical accounting treatment in effect for all periods presented.
(d): Represents reclassifications to conform to EXCO's presentation.
(e): Represents the adjustment to capitalize exploration expense as required under the full-cost method of accounting employed by EXCO.
(f): Represents increased depreciation, depletion and amortization primarily relating to the step up in basis of oil and natural gas properties associated with the purchase price allocation for the going private transaction as if it occurred on January 1, 2003.
(g): Represents increased depreciation, depletion and amortization primarily relating to the step up in basis of oil and natural gas properties associated with the purchase price allocation for the North Coast transaction as if it occurred on January 1, 2003 and utilizing the report on Proved Reserves prepared by Lee Keeling and Associates, Inc. as of December 31, 2003.
(h): Represents additional accretion charges resulting from the revaluation of fair value based upon EXCO management's assessment of certain factors as they relate to North Coast's asset retirement obligation.
(i): General and administrative pro forma expense adjustments include the following:

	Year Ended December 31, 2003
	(Dollars in thousands)
Accelerated stock compensation(1)	$	(8,157	)
Management retention bonuses(2)		1,080
Going private costs(3)		(2,973	)

Total G&A pro forma adjustment	$	(10,050	)

(1): Represents stock compensation expense attributable to the acceleration of stock option vesting in connection with the going private transaction.
(2): Represents additional contractual management compensation resulting from the going private transaction.
(3): Represents third party costs incurred by EXCO directly related to the going private transaction.

(j): Represents transaction costs incurred by North Coast and expensed during the year ended December 31, 2003 primarily related to employee retention payments and investment banking fees in connection with the acquisition of North Coast by EXCO.
(k): EXCO borrowed an additional $53.6 million under its former credit facilities to fund a portion of the going private transaction. This adjustment reflects the additional interest expense resulting from this borrowing in prior periods as if the borrowing was outstanding at January 1, 2003:

	Year Ended December 31, 2003
	(Dollars in thousands)
Interest expense from the $53.6 million increase in former credit facilities borrowings in the going private transaction at 3.85% at July 29, 2003	$	1,215

(l): Represents the adjustment to historical interest expense on debt to be retired and interest expense on debt assumed and issued in connection with the North Coast acquisition, at rates assumed to be in effect at the time of the Transactions, as presented in the following table. Total pro forma interest expense includes the additional interest expense resulting from the going private acquisition discussed in (i) above.

	Year Ended December 31, 2003
	(Dollars in thousands)
Historical interest expense	$	9,709
Interest expense resulting from the old notes issued on January 20, 2004		25,375
Interest expense resulting from the old notes issued on April 13, 2004		7,250
Increase in interest expense from the $53.6 million increase in credit facility borrowings in the going private transaction.		1,215
Reduction in interest expense from the $265.0 million pay down of our and North Coast's credit facilities.		(10,924	)
Amortization of $3.2 million premium related to the old notes issued on April 13, 2004		(378	)
Amortization of $9.7 million deferred financing costs related to the old notes—7 years		1,388
Amortization of additional deferred financing costs of $1.7 million to amend and restate our existing credit facilities—3 years		598

Total pro forma interest expense	$	34,233

At December 31, 2003, on a pro forma basis, no indebtedness was outstanding under the U.S. or Canadian credit facilities. Interest on the credit facility is variable at Libor plus 1.25%-2.00% under our U.S. credit agreement and the Banker's Acceptance rate plus 1.25%-2.00% under our Canadian credit agreement.

(m): Represents the income tax effect of the pro forma adjustments, the elimination of EXCO's tax valuation increases or decreases recognized during the 209 day period from January 1, 2003 to July 28, 2003 (as EXCO is now in a net deferred tax liability position) and adjustment of North Coast's historical rate to approximate EXCO's U.S. tax rate.

Supplemental Pro Forma Data Related to Oil and Natural Gas Activities

Proved Reserves and PV-10 were calculated using NYMEX spot prices at the close of business on December 31, 2003 of $32.52 per Bbl for oil and $6.19 per Mmbtu for natural gas adjusted for historical differentials between NYMEX and local prices. The standardized measures of discounted future net cash flows do not include the effects of commodity price risk management or other derivative contracts. The Proved Reserves and PV-10 of the Proved Reserves for EXCO and North Coast as of December 31, 2003 were prepared by Lee Keeling and Associates, Inc., an independent petroleum engineering firm in Tulsa, Oklahoma. The estimated amount of future abandonment costs and the PV-10 value of those costs for EXCO and North Coast were determined by EXCO.

The following table presents the standardized measure of discounted future net cash flows as of December 31, 2003 for EXCO, North Coast and pro forma for the North Coast acquisition.

	EXCO		North Coast		Pro Forma
	(Dollars in thousands)
Future cash flows	$	2,167,968	$	1,281,999	$	3,449,967
Future production costs		652,837		328,561		981,398
Future development costs		84,191		20,493		104,684
Future abandonment costs		41,245		17,842		59,087

Future net cash flows before tax		1,389,695		915,103		2,304,798
Future income taxes		419,788		267,832		687,620

Future net cash flows after tax		969,907		647,271		1,617,178
Annual discount at 10%		516,803		382,098		898,901

Standardized measure of discounted future net cash flows	$	453,104	$	265,173	$	718,277

SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA

The following table presents our selected historical financial and operating data. You should read this financial data in conjunction with our historical consolidated financial statements and related notes, "Management's Discussion and Analysis of Financial Condition and Results of Operations" and other financial information included elsewhere in this prospectus. The following information does not reflect any financial information with respect to the North Coast acquisition.

														209 Day Period from January 1 to July 28, 2003(1)
																	156 Day Period from July 29 to December 31, 2003(1)
		Year Ended December 31,
		1999			2000			2001			2002
		(Dollars in thousands)
Statement of Operations Data:(2)
Revenues and other income:
	Oil and natural gas	$	5,294		$	28,869		$	61,237		$	66,446		$	61,416		$	46,133
	Commodity price risk management activities		—			—			—			—			—			(11,160	)
	Other		2,173			1,252			5,567			6,654			(1,033	)		239
	Gain on disposition of properties, equipment and other assets		5,102			538			136			3			—			—

	Total revenues and other income		12,569			30,659			66,940			73,103			60,383			35,212

Costs and expenses:
	Oil and natural gas production		2,375			9,484			23,914			29,223			19,793			14,524
	Depreciation, depletion and amortization		1,446			4,949			14,244			18,558			12,022			12,012
	Accretion of discount on asset retirement obligations(3)		—			—			—			—			737			528
	General and administrative		1,934			2,003			4,806			10,968			19,272			5,847
	Interest expense		17			1,369			3,133			3,408			2,981			3,971
	Impairment of oil and natural gas properties		—			—			49,575			17,459			—			—
	Impairment of marketable securities		—			—			—			1,136			—			—
	Uncollectible value of Enron hedges		—			—			10,669			—			—			—

	Total costs and expenses		5,772			17,805			106,341			80,752			54,805			36,882

Income (loss) before income taxes and minority interest			6,797			12,854			(39,401	)		(7,649	)		5,578			(1,670	)
Minority interest in limited partnership			(7	)		—			—			—			—			—

Income (loss) before income taxes			6,804			12,854			(39,401	)		(7,649	)		5,578			(1,670	)
Income tax expense (benefit)			2,139			4,400			(54	)		(6,682	)		4,801			(5,847	)

Income (loss) before extraordinary items and accounting change			4,665			8,454			(39,347	)		(967	)		777			4,177
Cumulative effect of change in accounting principle, net of income tax(3)			—			—			—			—			255			—

Net income (loss)			4,665			8,454			(39,347	)		(967	)		1,032		$	4,177

Dividends on preferred stock			—			—			2,653			5,256			2,620

Earnings (loss) on common stock		$	4,665		$	8,454		$	(42,000	)	$	(6,223	)	$	(1,588	)

Basic earnings (loss) per share		$	0.69		$	1.23		$	(5.96	)	$	(0.88	)	$	(0.20	)

Diluted income (loss) per share		$	0.69		$	1.18		$	(5.96	)	$	(0.88	)	$	(0.20	)

Weighted average common and common equivalent shares outstanding:
	Basic		6,698			6,835			7,046			7,061			8,084

	Diluted		6,714			7,122			7,046			7,061			8,084

Statement of Cash Flow Data:
Net cash provided by (used in):
	Operating activities	$	(8,620	)	$	27,297		$	24,923		$	31,660		$	20,418		$	21,720
	Investing activities		(2,862	)		(66,519	)		(132,778	)		(76,937	)		(23,520	)		(38,528	)
	Financing activities		(39	)		37,450			102,130			45,928			9,982			14,964

	December 31,
	1999		2000		2001		2002		2003(1)
	(Dollars in thousands)
Balance Sheet Data:(2)
Current assets	$	31,599	$	20,262	$	21,121	$	26,198	$	31,569
Total assets		50,932		102,372		191,056		241,174		505,030
Current liabilities		10,017		8,655		13,322		33,193		45,188
Long-term debt, less current maturities		—		42,488		44,994		97,943		207,951
Stockholders' equity		40,880		49,791		120,379		99,884		183,869
Total liabilities and stockholders' equity		50,932		102,372		191,056		241,174		505,030

(1): The going private transaction was accounted for as a change in control resulting from the acquisition of us by EXCO Holdings, our parent. See "Change of Control Transaction." GAAP requires the application of "push down accounting" in situations where the ownership of an entity has changed, meaning that the post-transaction financial statements of the acquired entity reflect a new basis of accounting in accordance with Staff Accounting Bulletin No. 54 ("SAB 54"). Accordingly, EXCO Holdings applied purchase accounting in recording the buyout of shares to effect the going private transaction and its basis has been "pushed down" to us. In accordance with GAAP, we have allocated the purchase price to the assets acquired and liabilities assumed based upon estimated fair values at the date of acquisition. Consequently, our financial position and operating results subsequent to July 29, 2003 reflect a new basis of accounting (successor basis) and are not comparable to prior periods (predecessor basis).

In connection with the going private transaction, we no longer account for derivative financial instruments using hedge accounting. Instead, any change in fair value is recognized directly through the statement of operations. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies—Accounting for Derivatives" for a description of this accounting method.
(2): We have completed numerous acquisitions since January 1, 1999 that materially impact the comparability of this data between periods.
(3): We adopted SFAS 143, "Accounting for Asset Retirement Obligations" on January 1, 2003. See "Note 2—Summary of Significant Accounting Policies—Deferred Abandonment and Asset Retirement Obligations" of the notes to our December 31, 2003 consolidated financial statements included elsewhere in this prospectus.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS

The following information should be read in conjunction with our historical consolidated financial statements and related notes, our unaudited pro forma condensed consolidated financial statements and related notes and other financial information included elsewhere in this prospectus.

Overview

We are an independent energy company engaged in the acquisition, exploration, development and exploitation of oil and natural gas properties in the United States and Canada. For the three year period ended December 31, 2003, we have spent in excess of $200.0 million in property and corporate acquisitions. Further, on July 29, 2003, we completed a "going private" transaction that resulted in all of our outstanding common stock being acquired by EXCO Holdings Inc., a holding company owned by certain members of our management and several institutional and other investors. This transaction resulted in a change in the valuation of our assets. On January 27, 2004, we acquired all of the outstanding common stock of North Coast Energy, Inc. for a purchase price of approximately $225.4 million, including the assumption of $57.0 million in outstanding bank debt. Our strategy is to continue to grow primarily through the acquisition of proved oil and natural gas reserves and, to the extent possible, through the exploitation and development of these properties. We funded the acquisition of North Coast through the issuance on January 20, 2004 of $350.0 million in 7¹/4% senior unsecured notes. We expect to continue to use debt, primarily under our bank credit agreements, to make future acquisitions. We also expect to enter into new derivative financial instruments to reduce our exposure to changes in the prices of oil and natural gas. We used approximately $98.8 million of the proceeds from the April 13, 2004 issuance of the additional $100.0 million in 7¹/4% senior unsecured notes to repay substantially all of the indebtedness outstanding under our Canadian credit facility.

Critical Accounting Policies

In response to the SEC's Release No. 33-8040, "Cautionary Advice Regarding Disclosure About Critical Accounting Policies," we have identified the most critical accounting principles used in the preparation of our consolidated financial statements. We determined the critical principles by considering accounting policies that involve the most complex or subjective decisions or assessments. We identified our most critical accounting policies to be those related to our Proved Reserves, derivatives accounting, functional currency assessment, deferred tax asset valuations and our choice of accounting method for oil and natural gas properties.

We prepared our consolidated financial statements for inclusion in this report in accordance with accounting principles that are generally accepted in the United States, or GAAP. GAAP represents a comprehensive set of accounting and disclosure rules and requirements, and applying these rules and requirements requires management judgments and estimates including, in certain circumstances, choices between acceptable GAAP alternatives. Effective July 29, 2003, in connection with the going private transaction, we discontinued hedge accounting for derivative financial instruments. See "—Accounting for Derivatives" for a discussion of this change. The following is a discussion of our most critical accounting policies, judgments and uncertainties that are inherent in our application of GAAP.

Estimates of Proved Reserves

The Proved Reserves data included in this prospectus is prepared in accordance with SEC guidelines. The accuracy of a reserve estimate is a function of:

•: the quality and quantity of available data;

•: the interpretation of that data;
•: the accuracy of various mandated economic assumptions; and
•: the judgment of the persons preparing the estimate.

Our Proved Reserves information included in this report is based on estimates prepared internally by our engineers and audited by our independent petroleum engineers.

Because these estimates depend on many assumptions, all of which may substantially differ from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.

You should not assume that the present value of future net cash flows is the current market value of our estimated Proved Reserves. In accordance with SEC requirements, we based the estimated discounted future net cash flows from Proved Reserves on prices and costs on 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. Further, a discount rate of 10% may not be an accurate assumption of future interest rates.

Proved Reserves materially impact depletion expense. If the Proved Reserves decline, then the rate at which we record depletion expense increases, reducing net income. A decline in the estimate of Proved Reserves may result from lower market prices, and a decline may make it uneconomical to drill or produce from higher cost fields. In addition, the decline in Proved Reserves may impact the outcome of our assessment of our oil and natural gas properties for impairment.

Accounting for Derivatives

We engage in commodity price risk management activities to protect against commodity price fluctuations and in connection with the incurrence of debt related to our acquisition activities. In connection with the incurrence of debt related to our acquisition activities, our objective in entering into these commodity price risk management transactions is to manage price fluctuations and achieve a more predictable cash flow to fund our development and acquisition activities. These derivatives are not held for trading purposes.

Prior to July 29, 2003, when entering into hedging transactions, we formally documented all relationships between hedging instruments and hedged items, as well as our risk-management objective and strategy for undertaking various hedge transactions. The process included linking all derivatives that are designated as cash flow hedges to forecasted transactions. We also formally assessed, both at the hedge's inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. When it was determined that a derivative was not highly effective as a hedge or that it ceased to be a highly effective hedge, we discontinued hedge accounting prospectively. Under hedge accounting, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings and the ineffective portion of any change in fair value of a derivative designated as a hedge is immediately recognized in earnings.

Effective July 29, 2003, in connection with the going private transaction, we discontinued hedge accounting for all existing derivatives. Currently, we do not designate derivative transactions as hedges for accounting purposes; accordingly, changes in the fair value of derivative financial instruments will be recognized currently in our statement of operations.

Effective as of November 30, 2001, we ceased hedge accounting for our hedge transactions then in place with Enron North America, the counterparty to our swap agreements, due to its bankruptcy filing.

Assessments of Functional Currencies

We determine the functional currencies of our subsidiaries by assessing the currency of the economic environment in which a subsidiary primarily realizes and expends its operating revenues, costs and expenses. We have determined that the Canadian dollar is the functional currency of our international operations in Canada. Our assessment of functional currencies can have a significant impact on our periodic results of operations and on our financial position.

Deferred Tax Asset Valuations

We periodically assess the probability of recovering recorded deferred tax assets based on our assessment of future earnings outlooks by tax jurisdiction. These estimates are inherently imprecise because we make many assumptions in the assessment process. For the years ended December 31, 2001 and 2002 (predecessor basis), our net deferred tax asset in the U.S. of $7.6 million and $3.5 million, respectively, were fully reserved due to the uncertainty of the realization of such benefits. We are in a net deferred tax liability position in Canada, and, accordingly, the only valuation allowance has been provided in the amount of $2.6 million related to net operating loss carryforwards that are expected to expire without utilization. Effective with the going private transaction, as of July 29, 2003, EXCO (successor basis) is now in a deferred tax liability position in the U.S. due to the step-up in basis for book purposes related to purchase accounting and the carryover of tax basis. Accordingly, no valuation allowance relating to the deferred tax asset was recognized in the purchase price allocation at the acquisition date or at December 31, 2003.

Accounting for Oil and Natural Gas Properties

The accounting for and disclosure of oil and natural gas producing activities requires that we choose between GAAP alternatives and that we make judgments regarding estimates of future uncertainties.

We use the full cost method of accounting, which involves capitalizing all acquisitions, exploration, exploitation and development costs. Once we incur costs, they are recorded in the full cost pool or in unevaluated properties. Unevaluated property costs are not subject to depletion. We review our unevaluated costs on an ongoing basis, and we expect these costs to be evaluated in one to three years and transferred to the full cost pool during that time. The full cost pool is comprised of lease and well equipment and exploration and development costs incurred plus intangible acquired proved leaseholds.

We calculate depletion using the unit-of-production method. Under this method, the sum of the full cost pool and all estimated future development costs are divided by the total amount of Proved Reserves. This rate is applied to our total production for the period, and the appropriate expense is recorded. We capitalize the portion of general and administrative costs that are attributable to our acquisition, exploration, exploitation and development activities.

To the extent that total capitalized oil and natural gas property costs (net of related deferred income taxes and accumulated depreciation, depletion and amortization) exceed the estimated future net revenues from proved properties using current period-end prices discounted at 10%, adjusted for related income tax effects, plus the lower of cost or fair value of unproved properties, excess costs are charged to operations. Once incurred, a write-down of oil and natural gas properties is not reversible at a later date even if oil or natural gas prices increase. We could be required to write down our oil and natural gas properties if there is a decline in oil or natural gas prices, or downward adjustments are made to our Proved Reserves. During 2001 and 2002, we recognized impairment charges of $20.9 million and $17.5 million, respectively, with respect to our properties located in Canada, and in 2001, we recognized an impairment charge of $28.7 million, with respect to our properties located in the United States. These charges were the result of low prices for oil and natural gas at September 30, 2001, December 31, 2001 and June 30, 2002.

Goodwill

As a result of a change in control, the going private transaction has been accounted for using the purchase method of accounting pursuant to SFAS No. 141, "Accounting for Business Combinations." As a result, EXCO Holdings' cost of acquiring EXCO has been allocated to the assets and liabilities acquired based upon estimated fair values. Under applicable generally accepted accounting principles, the new basis of accounting for EXCO Holdings is "pushed down" to the subsidiary company, EXCO. Therefore, EXCO's financial position and operating results subsequent to July 28, 2003 reflect a new basis of accounting and are not comparable to prior periods. In addition, tax basis carried over from the formerly public company as a result of the merger. The going private purchase price has been allocated to the assets acquired and liabilities assumed according to the estimated fair values. The purchase price allocation has resulted in $51.1 million of goodwill being recorded, $24.2 million in the United States geographic operating segment and $26.9 million in the Canadian geographic operating segment. Changes in the balance of goodwill from the date of acquisition to December 31, 2003 are the result of foreign currency translation adjustments for associated Canadian goodwill. None of the goodwill is currently deductible for income tax purposes. Furthermore, in accordance with SFAS No. 142, "Goodwill and Intangible Assets," goodwill is not amortized, but is tested for impairment on an annual basis, or more frequently as impairment indicators arise. Impairment tests, which involve the use of estimates related to the fair market value of the business operations with which goodwill is associated, are performed at the end of our fourth quarter. Losses, if any, resulting from impairment tests will be reflected in operating income in the statement of operations.

Asset Retirement Obligations

Prior to 2003, we provided for future site restoration costs on our Canadian oil and natural gas properties based upon management's estimates. The costs were being recognized over the remaining life of Proved Reserves by a charge to depreciation, depletion and amortization in the statement of operations with a related increase in the non-current deferred abandonment liability. Actual expenditures for site restoration were charged to the deferred abandonment liability when incurred. We did not provide for site restoration costs on our U.S. properties as we estimated that salvage values would exceed the asset retirement costs.

In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, "Accounting for Asset Retirement Obligations." The statement requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. We adopted the new rules on asset retirement obligations on January 1, 2003, for both our U.S. and Canadian operations. Application of the new rules resulted in an increase in net proved developed and undeveloped oil and natural gas properties of approximately $11.4 million, recognition of an asset retirement obligation liability of approximately $10.4 million, an increase in deferred income tax liability of approximately $690,000 and a cumulative effect of adoption that increased net income and stockholder's equity by approximately $255,000.

Accounting for Income Taxes

Income taxes are provided based upon the liability method of accounting. Deferred taxes are recorded to reflect the tax benefit and consequences of future years differences between the tax bases of assets and liabilities and their financial reporting basis. We record a valuation allowance to reduce deferred tax assets if it is more likely than not that some portion or all of the deferred tax assets will not be realized. We generally consider the earnings of Addison, our Canadian subsidiary, to be permanently reinvested for use in those operations and, consequently, deferred federal income taxes,

net of applicable foreign tax credits, are not provided on the undistributed earnings of Addison that are to be so reinvested.

Recently Issued Accounting Standards

SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Intangible Assets," were issued in June 2001 and became effective for us on July 1, 2001 and January 1, 2002, respectively. SFAS No. 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. Additionally, SFAS No. 141 requires companies to disaggregate and report goodwill separately from other intangible assets. SFAS No. 142 established new guidelines for accounting for goodwill and other intangible assets. Under SFAS No. 142, goodwill and other intangible assets are not amortized but rather are reviewed annually for impairment.

One interpretation relating to these standards is that oil and natural gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves for both undeveloped and developed leaseholds should be classified separately from oil and natural gas properties, as intangible assets on the balance sheet, and the disclosures required by SFAS No. 141 and No. 142 relating to intangibles would be included in the notes to financial statements. In connection with our going private transaction, we have adopted a policy of including these costs as part of oil and natural gas properties on our consolidated balance sheet as of December 31, 2003. The financial statements of our predecessor company at December 31, 2002 originally reflected this interpretation; however, since there are various interpretations relative to this standard, we have reclassified the December 31, 2002 amounts to reflect the presentation at December 31, 2003.

Since we have adopted full cost accounting for oil and natural gas activities, we understand that the interpretation of SFAS No. 141 and No. 142 as described above would only affect our balance sheet classification of proved oil and natural gas leaseholds acquired after June 30, 2001 and our unproved oil and natural gas leaseholds. Our results of operations and cash flows would not be affected, since these oil and natural gas mineral rights held under lease and other contractual arrangements representing the rights to extract such reserves would continue to be amortized in accordance with full cost rules.

As of December 31, 2003, we had undeveloped leaseholds of approximately $9.2 million that would be classified on our balance sheet as "intangible undeveloped leasehold" and developed leaseholds of an estimated $333.4 million that would be classified as "intangible developed leasehold" if we applied the interpretation currently being considered. We will continue to classify our oil and natural gas mineral rights held under lease and other contractual rights representing the right to extract such reserves within oil and natural gas properties until further guidance is provided.

In April 2003, the FASB issued SFAS No. 149, which amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133. SFAS No. 149 clarifies the discussion around initial net investment and when a derivative contains a financing component, and amends the definition of the term underlying to conform it to language used in FIN 45. In addition, SFAS No. 149 also incorporates certain Derivative Implementation Group Implementation Issues. The provisions of SFAS No. 149 are effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. The guidance should be applied to hedging relationships on a prospective basis. We do not believe that SFAS No. 149 will have a material impact on our consolidated results of operations, cash flows and financial position.

Our Results of Operations

The following is a discussion of our financial condition and results of operations for the years ended December 31, 2001, 2002 and 2003. The information presented below for the year ended

December 31, 2003 represents the total of our activity for the 209 day period from January 1, 2003 to July 28, 2003 and the 156 day period from July 29, 2003 to December 31, 2003.

The comparability of our results of operations from year to year is impacted by:

•: the acquisition of our Canadian operations in April 2001;
•: property acquisitions and, to a lesser degree, property dispositions that have occurred during the three years presented;
•: significant fluctuations in the prices received for oil and natural gas sales; and
•: the "going private" transaction that occurred on July 29, 2003.

General

The availability of a ready market for oil, natural gas and NGLs and the prices of oil, natural gas and NGLs are dependent upon a number of factors that are beyond our control. These factors include, among other things:

•: the level of domestic production and economic activity generally;
•: the availability of imported oil and natural gas;
•: actions taken by foreign oil producing nations;
•: the cost and availability of natural gas pipelines with adequate capacity and other transportation facilities;
•: the cost and availability of other competitive fuels, fluctuating and seasonal demand for oil, natural gas and refined products; and
•: the extent of governmental regulation and taxation (under both present and future legislation) of the production, refining, transportation, pricing, use and allocation of oil, natural gas, refined products and substitute fuels.

Accordingly, in light of the many uncertainties affecting the supply and demand for oil, natural gas and refined petroleum products, we cannot accurately predict the prices or marketability of the oil, natural gas or NGLs from any producing well in which we have or may acquire an interest.

United States

We produce oil, natural gas and NGLs. We do not refine or process the oil we produce. With the exception of our Black Lake Field in Louisiana, we do not process a significant portion of the natural gas or NGLs we produce. At the Black Lake Field we operate a natural gas processing plant that is 100% dedicated to production from the field.

We sell the majority of the oil we produce under short-term contracts using market sensitive pricing. The majority of our contracts are based on NYMEX pricing, which is typically calculated as the average of the daily closing prices of oil to be delivered one month in the future. We also sell a portion of our oil at F.O.B. field prices posted by the principal purchaser of oil where our producing properties are located. Our sales contracts are of a type common within the industry, and we usually negotiate a separate contract for each property. Generally, we sell our oil to purchasers and refiners near the areas of our producing properties.

We sell the majority of our natural gas under short-term contracts using market sensitive pricing. Our sales contracts are of a type common within the industry, and we frequently negotiate a separate contract for each property. We sell our natural gas to transmission and utility companies that have pipelines in the vicinity of our producing properties, to companies that will construct pipelines to our properties or to third party natural gas marketing companies.

We sell our NGLs under both short-term and long-term contracts. We sell the NGLs to refiners and processors in the vicinity of our producing properties. Our sales contracts are of a type common within the industry, and we usually negotiate a separate contract for each property. Typically, the prices we receive for NGLs are based on the Oil Price Information Service (OPIS) index, less transportation and fractionating fees.

We cannot assure you that we will be able to market all the oil, natural gas or NGLs we produce. If our oil, natural gas or NGLs can be marketed, we cannot assure you that we can negotiate favorable price and contractual terms. Changes in oil or natural gas prices may significantly affect our revenues, cash flows, the value of our oil and natural gas properties and the estimates of recoverable oil, natural gas and NGLs contained in our properties. Further, significant declines in the prices of oil or natural gas may have a material adverse effect on our business and on our financial condition.

We engage in oil and natural gas production activities in geographic regions where, from time to time, the supply of oil or natural gas available for delivery exceeds the demand. In this situation, companies purchasing oil or natural gas in these areas reduce the amount of oil or natural gas that they purchase from us. If we cannot locate other buyers for our production or for any of our newly discovered oil or natural gas reserves, we may shut-in our oil or natural gas wells for periods of time. If this occurs, we may incur additional payment obligations under our oil and natural gas leases and, under certain circumstances, the oil and natural gas leases might be terminated.

Canada

The majority of our Canadian oil is ultimately sold to Plains Marketing Canada, L.P. at market sensitive prices less applicable tariffs, trucking and quality adjustments.

At December 31, 2003, we were selling approximately 20,300 Mmbtus of our Canadian natural gas per day to two different purchasers at market sensitive prices. The remainder of our Canadian natural gas is sold to various purchasers at market sensitive prices.

Our NGLs are sold primarily to two different buyers under contracts which provide for index pricing less transportation and fractionation fees.

We acquired Addison, our Canadian subsidiary, in April 2001.

Revenues

The following tables present our oil and natural gas revenues (before commodity price risk management activities), production and average unit sales price for the three years ended December 31, 2001, 2002 and 2003. Results for the predecessor and successor periods in 2003 are combined as the going private transaction had no impact on 2003 revenues before commodity price risk management activities and production. The table also shows the changes in these amounts between years.

			Year ended December 31,						Year to year change
			2001		2002		2003		2001-2002			2002-2003
			(In thousands)
Oil and natural gas revenues before commodity price risk management activities:
	Oil revenues:
	U.S.		$	20,871	$	20,648	$	22,351	$	(223	)	$	1,703
	Canada			1,739		9,661		12,802		7,922			3,141

		Total	$	22,610	$	30,309	$	35,153	$	7,699		$	4,844

	Natural gas revenues:
	U.S.		$	24,049	$	20,083	$	34,051	$	(3,966	)	$	13,968
	Canada			5,394		18,077		42,228		12,683			24,151

		Total	$	29,443	$	38,160	$	76,279	$	8,717		$	38,119

	Natural gas liquids revenues:
	U.S.		$	1,826	$	1,227	$	1,342	$	(599	)	$	115
	Canada			1,087		4,454		8,348		3,367			3,894

		Total	$	2,913	$	5,681	$	9,690	$	2,768		$	4,009

	Total oil and natural gas revenues:
	U.S.		$	46,746	$	41,958	$	57,744	$	(4,788	)	$	15,786
	Canada			8,220		32,192		63,378		23,972			31,186

		Total	$	54,966	$	74,150	$	121,122	$	19,184		$	46,972

			Year ended December 31,			Year to year change
			2001	2002	2003	2001-2002		2002-2003
Production:
	Oil (Mbbls):
	U.S.		887	869	755	(18	)	(114	)
	Canada		80	399	448	319		49

		Total	967	1,268	1,203	301		(65	)

	Natural gas (Mmcf):
	U.S.		6,243	6,878	7,551	635		673
	Canada		2,086	6,565	8,360	4,479		1,795

		Total	8,329	13,443	15,911	5,114		2,468

	Natural gas liquids (Mbbls):
	U.S.		96	74	59	(22	)	(15	)
	Canada		68	242	332	174		90

		Total	164	316	391	152		75

	Total production (Mmcfe):
	U.S.		12,141	12,536	12,440	395		(96	)
	Canada		2,974	10,411	13,042	7,437		2,631

		Total	15,115	22,947	25,482	7,832		2,535

			Year ended December 31,						Year to year change
			2001		2002		2003		2001-2002			2002-2003
Average sales price (before cash settlements of derivative financial instruments):
	Oil (per Bbl):
	U.S.		$	23.54	$	23.75	$	29.59	$	0.21		$	5.84
	Canada			21.71		24.23		28.58		2.52			4.35
		Total		23.39		23.90		29.22		0.51			5.32
	Natural gas (per Mcf):
	U.S.		$	3.85	$	2.92	$	4.51	$	(0.93	)	$	1.59
	Canada			2.59		2.75		5.05		0.16			2.30
		Total		3.53		2.84		4.79		(0.69	)		1.95
	Natural gas liquids (per Bbl):
	U.S.		$	18.97	$	16.66	$	22.58	$	(2.31	)	$	5.92
	Canada			15.90		18.38		25.11		2.48			6.73
		Total		17.70		17.98		24.73		0.28			6.75
	Total production (per Mcfe):
	U.S.		$	3.85	$	3.35	$	4.64	$	(0.50	)	$	1.29
	Canada			2.76		3.09		4.86		0.33			1.77
		Total		3.64		3.23		4.75		(0.41	)		1.52

Our revenues from the sale of oil, natural gas and NGLs, before cash settlements of derivative financial instruments, for the year ended December 31, 2003 increased by $47.0 million, or 63%, over the year ended December 31, 2002 primarily due to higher prices received for oil, natural gas and NGLs. The increase in revenue resulting from higher average oil, natural gas and NGL prices was approximately $34.8 million. Our average oil and natural gas price, before cash settlements of derivative financial instruments, received during the year ended December 31, 2003, were 22% and 69%, respectively, greater than received during the prior year.

The increase in revenue was also due to an increase in production volumes. Our increased production of natural gas and NGLs for the year ended December 31, 2003 compared to the year ended December 31, 2002 increased revenues by $13.7 million. This increase is primarily attributable to our acquisition of the DJ Basin properties in November 2002, the additional interests in the Vinegarone properties in October 2003 and several property acquisitions in Canada during 2002 and 2003. The increase in production from these acquisitions for the year ended December 31, 2003 over the year ended 2002 was 2.3 Bcf of natural gas and 53,000 Bbls of NGLs. The remaining increase in natural gas and NGLs volumes is attributable to other smaller acquisitions and the results of our development and exploitation capital spending, primarily in Canada. Oil volumes overall decreased 65,000 Bbls during these same periods, which decreased revenue by $1.5 million. Oil volumes decreased primarily due to a general decline in production from our oil producing properties.

Our revenues from the sale of oil, natural gas and NGLs, before cash settlements of derivative financial instruments, for the year ended December 31, 2002 increased by $19.2 million, or nearly 33%, over the year ended December 31, 2001 primarily due to increased production resulting from acquisitions made during the years ended 2001 and 2002. Our production of oil, natural gas and NGLs increased by 301,000 Bbls, 5.1 Bcf and 152,000 Bbls, respectively, for the year ended December 31, 2002, compared to the year ended December 31, 2001. These increases are primarily attributable to our acquisitions of Addison, completed in late April 2001, the PrimeWest properties, completed in December 2001, the Medicine River properties, completed in April 2002 and the DJ Basin properties completed in November 2002. Production from these acquisitions during 2002 was 295,000 Bbls of oil, 3.5 Bcf of natural gas and 139,000 Bbls of NGLs.

The increase in revenue resulting from increased production was partially offset by lower prices received for natural gas. Our average natural gas price received during the year ended December 31, 2002 was $2.84 per Mcf as compared to $3.53 per Mcf for 2001, which decreased revenue by $5.8 million. This decrease was partially offset by higher oil and NGL prices. Our average oil price received during the year ended December 31, 2002 was $23.90 per Bbl as compared to $23.39 per Bbl for 2001, which increased revenue by $493,000. Our average NGL price received during the year ended December 31, 2002 was $17.98 per Bbl as compared to $17.70 per Bbl for 2001, which increased revenue by less than $100,000.

During 2002 we had one well control event that directly impacted revenues. During November and December 2002, we sold 254,000 Mcf of natural gas from Miami Corp. #35 well while it was experiencing an uncontrolled flow from the wellbore. These sales increased revenue by $1.0 million. Oil and natural gas production costs and production and ad valorem taxes for the Miami Corp. #35 during this period were less than $100,000. There was no production from this well during 2003 as the well was temporarily abandoned. In December 2003, we commenced sidetrack drilling operations on this well and, in January 2004, the well was completed and placed on production as a producing natural gas well.

			Year ended December 31,								Year to year change
			2001		2002			2003			2001-2002			2002-2003
			(In thousands)
Commodity price risk management activities:
	Settlements on derivative financial instruments		$	6,271	$	(7,704	)	$	(19,915	)	$	(13,975	)	$	(12,211	)
	Non-cash changes in fair value of derivative financial instruments			—		—			(5,785	)		—			(5,785	)

		Total commodity price risk management activities	$	6,271	$	(7,704	)	$	(25,700	)	$	(13,975	)	$	(17,996	)

			Year ended December 31,								Year to year change
			2001		2002			2003			2001-2002			2002-2003
			(In thousands)
Other income (expense):
	Income from terminated hedges		$	1,346	$	6,976		$	1,763		$	5,630		$	(5,213	)
	Income (expense) from hedge ineffectiveness			3,517		(886	)		(2,544	)		(4,403	)		(1,658	)
	Gain (loss) on foreign currency transactions			—		(208	)		(1,405	)		(208	)		(1,197	)
	Other, net			704		772			1,392			68			620

		Total other income (expense)	$	5,567	$	6,654		$	(794	)	$	1,087		$	(7,448	)

Our cash settlements of derivative financial instruments reduced revenue by $19.9 million and $7.7 million during the years ended December 31, 2003 and 2002, respectively. The NYMEX oil and natural gas prices that are used to settle our hedges increased significantly over the oil and natural gas prices of our contracts. The increases in prices resulted in us making significant payments to our counterparties to settle our derivative financial instruments during the year and decreased our revenues as a result. For the year ended December 31, 2001, the oil and natural gas prices of our derivative financial instruments were significantly higher than the NYMEX oil and natural gas price and, as a result, we received significant payments from Enron North America, our counterparty at that time.

Prior to the completion of the going private transaction, we accounted for our derivative financial instruments as cash flow hedges. During the 209 day period from January 1 to July 28, 2003, we reduced our revenues by $2.5 million for the ineffective portion of the change in the fair value of our hedges. The ineffectiveness was primarily due to a significant increase in March 2003 in the difference

between the NYMEX price for oil and natural gas, which is the price we use to settle our hedges, and the actual price that we receive in the field for the physical delivery of our oil and natural gas production. For the 156 day period from July 29 to December 31, 2003, we have recognized as a reduction of revenue $5.8 million from the change in the fair value of our derivative financial instruments. Previously, the effective portion of this change was reflected in other comprehensive income while the ineffective portion was recognized in current period earnings. We expect that our revenues will continue to be significantly impacted in future periods by the change in the fair value of our derivative financial instruments as a result of the volatility in oil and natural gas prices and the volume of future oil and natural gas sales covered under our commodity price risk management program.

During the 209 day period from January 1, 2003 to July 28, 2003, we recorded $1.8 million in non-cash income from terminated hedges as other income. For the year ended December 31, 2002, we recorded $6.9 million as non-cash income from terminated hedges. As a result of the going private transaction, we ceased recording such income during the 156 day period from July 29, 2003 to December 31, 2003. The increase in the foreign currency transaction losses is a result of the strengthening of the Canadian dollar versus the U.S. dollar during 2003. The exchange rate at December 31, 2003 of the Canadian dollar to the U.S. dollar was 21% higher than the exchange rate at December 31, 2002.

The increase in other income for 2002 compared to 2001 was primarily attributable to $6.1 million in non-cash income from derivative ineffectiveness and terminated hedges during the year ended December 31, 2002, compared to $4.9 million in non-cash income from derivative ineffectiveness and terminated hedges for 2001.

Costs and Expenses

The following tables present our oil and natural gas production costs and average oil and natural gas production cost per Mcfe for the three years ended December 31, 2001, 2002 and 2003. Results for the predecessor and successor periods in 2003 are combined as the going private transaction had no impact on 2003 production costs. The table also shows the changes in these amounts between years.

			Year ended December 31,						Year to year change
			2001		2002		2003		2001-2002			2002-2003
			(In thousands)
Oil and natural gas production costs:
	Oil and natural gas operating costs:
	U.S.		$	17,372	$	15,034	$	13,688	$	(2,338	)	$	(1,346	)
	Canada			2,402		9,776		14,826		7,374			5,050

		Total	$	19,774	$	24,810	$	28,514	$	5,036		$	3,704

	Production and ad valorem taxes:
	U.S.		$	4,024	$	3,986	$	5,023	$	(38	)	$	1,037
	Canada			116		427		780		311			353

		Total	$	4,140	$	4,413	$	5,803	$	273		$	1,390

	Total oil and natural gas production costs:
	U.S.		$	21,396	$	19,020	$	18,711	$	(2,376	)	$	(309	)
	Canada			2,518		10,203		15,606		7,685			5,403

		Total	$	23,914	$	29,223	$	34,317	$	5,309		$	5,094

			Year ended December 31,						Year to year change
			2001		2002		2003		2001-2002			2002-2003
Oil and natural gas production costs per Mcfe:
	Oil and natural gas operating costs:
	U.S.		$	1.43	$	1.20	$	1.10	$	(0.23	)	$	(0.10	)
	Canada			0.81		0.94		1.14		0.13			0.20
		Total		1.32		1.08		1.12		(0.24	)		0.04
	Production and ad valorem taxes:
	U.S.		$	0.33	$	0.32	$	0.40	$	(0.01	)	$	0.08
	Canada			0.04		0.04		0.06		—			0.02
		Total		0.27		0.19		0.23		(0.08	)		0.04
	Total oil and natural gas production costs:
	U.S.		$	1.76	$	1.52	$	1.50	$	(0.24	)	$	(0.02	)
	Canada			0.85		0.98		1.20		0.13			0.22
		Total		1.59		1.27		1.35		(0.32	)		0.08

Our oil and natural gas operating costs for the year ended December 31, 2003 increased $3.7 million, or 13%, from the same period in 2002. Our acquisitions of the DJ Basin and the additional interests in the Vinegarone properties in the United States and the acquisition of several properties in Canada during 2002 and 2003 increased oil and natural gas operating costs by $2.8 million. The remaining increase in oil and natural gas operating costs is primarily the result of other, smaller acquisitions and new wells added through our development and exploitation capital program, mainly in Canada. These increases were partially offset by the oil and natural gas operating costs incurred on oil and natural gas properties in the United States that were sold in late 2002 and in 2003. Oil and natural gas production costs on a unit of production basis increased $0.04 per Mcfe to $1.12 per Mcfe for the year ended December 31, 2003. This increase is primarily due to higher per unit

operating costs on non-operated properties acquired by Addison. Production and ad valorem taxes for the year ended December 31, 2003 increased by $1.4 million, or 31%, over 2002. This increase is primarily attributable to higher production taxes in the United States as a result of the significantly increased prices received for production and $399,000 in production taxes on the DJ Basin and additional interest in the Vinegarone properties. Further, ad valorem taxes in Texas and other states are based partially on the value of oil and natural gas reserves, which have increased as a result of the higher oil and natural gas prices. Additionally, ad valorem taxes in Canada have increased by $351,000 as a result of property acquisitions. These increases were partially offset by lower production taxes incurred on oil and natural gas properties in the United States that were sold in late 2002 and in 2003. These taxes are generally based upon the price received for production. No production taxes are paid in Canada.

Our oil and natural gas operating costs for the year ended December 31, 2002 increased $5.0 million, or 25%, over the same period in 2001 primarily as a result of property acquisitions. Oil and natural gas operating costs from the PrimeWest (acquired in December 2001), Medicine River (acquired in April 2002) and the DJ Basin (acquired in November 2002) properties increased oil and natural gas production costs by $4.8 million. Oil and natural gas production costs on a unit of production basis decreased $0.24 per Mcfe primarily a result of the lower costs, on a unit of production basis, from our Canadian properties. Production and ad valorem taxes for the year ended December 31, 2002 increased by $274,000. The increase in production and ad valorem taxes is primarily attributable to higher ad valorem taxes paid in Canada. No production taxes are paid in Canada.

Our depreciation, depletion and amortization costs for the year ended December 31, 2003 increased by $5.5 million, or 29%, to $24.0 million from $18.6 million for the same period in 2002. The primary reasons for this increase are:

•: the increase in proved oil and natural gas property value due to the going private transaction;
•: our acquisitions of the Medicine River, DJ Basin, and other smaller properties as well as the additional interests in the Vinegarone properties during 2002 and 2003;
•: the adoption of SFAS 143, "Accounting for Asset Retirement Obligations"; and
•: the higher sales volumes for the year ended December 31, 2003 when compared to the year ended December 31, 2002.

Our depreciation, depletion and amortization costs for the year ended December 31, 2002 increased by $4.4 million, or 30%, to $18.6 million from $14.2 million for the same period in 2001, as a result of our acquisitions of Addison and the PrimeWest, Medicine River and DJ Basin properties. Depletion expense on production from these properties was approximately $5.2 million. This increase was partially offset by lower depletion rates due to non-cash ceiling test write-downs taken in the third and fourth quarters in 2001 and in the second quarter in 2002.

Accretion of discount on asset retirement obligations is the result of the adoption, as of January 1, 2003, of SFAS 143, "Accounting for Asset Retirement Obligations." This non-cash expense measures the changes in the liability for an asset retirement obligation due to the passage of time by applying an interest method of allocation to the amount of the liability at the beginning of the period. See

"Note 5—Asset Retirement Obligations" of the notes to our December 31, 2003 consolidated financial statements for additional information regarding our adoption of SFAS 143.

			Year ended December 31,									Year to year change
			2001			2002			2003			2001-2002			2002-2003
			(In thousands, except per unit and employee count)
General and administrative expenses:
	Gross G&A expense		$	8,837		$	15,258		$	29,175		$	6,421		$	13,917
	Operator overhead reimbursements			(2,912	)		(2,891	)		(2,489	)		21			402
	Capitalized exploitation and development charges			(1,119	)		(1,399	)		(1,567	)		(280	)		(168	)

		Net G&A expense	$	4,806		$	10,968		$	25,119		$	6,162		$	14,151

	General and administrative expense per Mcfe		$	0.32		$	0.48		$	0.99		$	0.16		$	0.51
	Number of employees at December 31			93			119			132			26			13

Our general and administrative costs for the year ended December 31, 2003 increased by $14.2 million, or 130%, over the same period in 2002 and was primarily attributable to:

•: approximately $3.0 million in legal, financial advisory, printing and other costs that we incurred in connection with the going private transaction and to prepare and make the required regulatory filings during the year ended December 31, 2003 compared to $336,000 during the year ended December 31, 2002;
•: approximately $4.2 million in increased salaries, benefits and office space that resulted primarily from increased staffing needs to manage properties acquired since December 2001 as well as higher salary and bonuses for our employees; and
•: approximately $9.1 million in stock option compensation expense for the year ended December 31, 2003 related to the stock option plan of Addison, our wholly-owned Canadian subsidiary, and the buyout of employee stock options as part of the going private transaction compared to $1.4 million during 2002.

Our general and administrative costs for the year ended December 31, 2002 increased by $6.2 million, or 128%, over the same period in 2001 and was primarily due to:

•: approximately $2.6 million in increased salaries, benefits and office space that resulted primarily from increased staffing needs as a result of our acquisitions of Addison and the STB Energy, PrimeWest and Medicine River properties;
•: approximately $1.4 million in stock option compensation expense related to the Addison stock option plan;
•: approximately $474,000 in legal costs incurred in pursuing our bankruptcy claim against Enron North America Corp.; and,
•: approximately $336,000 in costs incurred for financial and legal advisors we retained to evaluate the going private transaction.

We expect that our general administrative expenses will increase during 2004 as a result of the acquisition of North Coast. The Appalachian Basin, where North Coast operates, represents a new core area for us and, as a result, we have decided at this time to not make significant changes in the operations or staffing of North Coast.

Our interest expense for the year ended December 31, 2003 increased $3.5 million, or 104%, to $6.9 million from $3.4 million for the same period in 2002. This increase was primarily due to greater amounts of outstanding borrowings resulting from the going private transaction, our acquisitions of the

Medicine River and DJ Basin properties, the acquisition of the additional interests in the Vinegarone properties, other smaller property acquisitions and borrowings for working capital needs. Our long-term debt balance at December 31, 2003 was $207.9 million compared to $97.9 million at December 31, 2002. See "Our Liquidity, Capital Resources and Capital Commitments" for a description of changes in our long-term debt that occurred in January 2004. As a result of the issuance of the old notes, we expect our interest expense to increase significantly in 2004.

Our interest expense for the year ended December 31, 2002 increased to $3.4 million from $3.1 million for 2001. This increase was primarily caused by higher average outstanding borrowings during the year ended December 31, 2002, when compared to 2001.

Under full cost accounting rules, we must compare the amount in our full cost pools (separate pools exist for the United States and Canada) to a ceiling test limit. In calculating future net revenues for the ceiling test limit, current prices and costs are generally held constant indefinitely. As a result of lower prices for Canadian natural gas at the end of the second quarter of 2002, we had a pre-tax, non-cash write-down of our oil and natural gas properties of $17.5 million ($9.7 million after-tax) from our Canadian full cost pool. As a result of low oil and natural gas prices at September 30, 2001 and December 31, 2001, we had pre-tax, non-cash ceiling test write-downs of our oil and natural gas properties during the year ended December 31, 2001 of $49.6 million, of which $28.7 million was from our United States full cost pool and $20.9 million was from our Canadian full cost pool. We did not have any write-downs of our full cost pools during the year ended December 31, 2003. Due to the volatility of oil and natural gas prices, it is possible that we will incur additional non-cash ceiling test write-downs in the future.

Periodically, we invest in the marketable securities of other companies prior to initiating discussions of potential business combinations with those companies. We consider these investments to be "available for sale", which means that unrealized gains and losses are excluded from earnings and included in other comprehensive income unless the decline in the fair value of the investment is "other than temporary." During the year ended December 31, 2002, we determined that, due to the significant decline in market value of two of our investments, the decline in the fair value of those two investments was "other than temporary" and, as a result, we have recognized a non-cash pre-tax impairment expense of $1.1 million. We did not have similar impairment charges during 2003.

Prior to the completion of the going private transaction, we did not record any income tax benefit in the U.S. associated with losses generated in the U.S., as it was uncertain whether we would be able to utilize our net deferred tax asset. Accordingly, the tax effects of our U.S. generated losses were offset by an increase in our valuation allowance. This resulted in an overall higher effective tax rate. Effective July 29, 2003 and in conjunction with our going private transaction, the deferred tax asset valuation allowance reduced in the purchase price allocation as EXCO (successor basis) is now in a deferred tax liability position. There is a valuation allowance of approximately $2.6 million for net operating loss carryforwards that are subject to limitations and are expected to expire before being utilized. During the 156 day period ended December 31, 2003, EXCO (successor basis) recognized a tax benefit in the U.S. of $2.8 million relating to U.S. generated loss during this period. During this same time period, we recognized a Canadian tax benefit of $3.0 million on pre-tax income of $6.2 million. This consists of a current tax expense of $1.3 million and a deferred income tax benefit of approximately $4.3 million for the 156 day period from July 29 to December 31, 2003. Of the Canadian deferred income tax benefit, approximately $4.9 million is the result of legislation which became effective on November 7, 2003 that will phase-in reduced income tax rates and allow for the deductibility of crown royalties, which has been accounted for in the deferred tax benefit amount for 2003. However, the Province of Alberta has indicated that it is not going to follow the federal government phase-in deduction of crown royalties and it intends to enact legislation during 2004 that will provide for the full deduction of crown royalties beginning in 2007 with no phase-in period. The Province of Alberta has also indicated an intention to lower its income tax rate by 1% for 2004;

however, no legislation has been introduced or enacted. As a result, we have not recognized the benefit of a lower Alberta tax rate at December 31, 2003.

We recorded a current income tax benefit of $2.7 million in the United States for the year ended December 31, 2002, to reflect a refund of taxes expensed and paid during 2001 and the refund of income taxes carried back to prior years for 2001 and 2002 taxable losses, after deducting intangible drilling costs. For the year ended December 31, 2002, we did not record any deferred income tax benefits or expense in the U.S., as it was uncertain whether we would be able to utilize our net deferred tax asset. Accordingly, the tax effect of our U.S. generated income was offset by a reduction in our valuation allowance. Effective with the going private transaction, as of July 29, 2003, we are now in a deferred tax liability position in the U.S. due to the step-up in basis for book purposes related to purchase accounting and the carryover of tax basis. Accordingly, the valuation allowance was reversed in the purchase price allocation at the acquisition date, except for the $2.6 million allowance for net operating loss carryforwards as discussed above. In Canada we recorded a deferred tax benefit of $4.0 million in 2002. The deferred tax benefit is primarily the result of the non-cash ceiling test write-down on our Canadian full cost pool. We did not have any current income tax expense or benefit in Canada during 2002.

The cumulative effect of change in accounting principle, net of income tax, is the result of the adoption of SFAS 143 on January 1, 2003. In accordance with the provisions of SFAS 143, we recognized a $255,000 benefit from the cumulative effect of change in accounting principle, net of $690,000 of associated deferred income taxes.

Our Liquidity, Capital Resources and Capital Commitments

General

Most of our growth has resulted from recent acquisitions and our development and exploitation program. Consistent with our strategy of acquiring and developing reserves, we have an objective of maintaining financing flexibility. In the past, we have utilized a variety of sources of capital to fund our acquisition, development and exploitation programs and to fund our operations. Our general financial strategy is to use a combination of cash flow from operations, bank financing and the sale or issuance of debt securities to fund our operations, conduct development and exploitation activities and to fund acquisitions. We do not have a set budget for acquisitions as these tend to be opportunity driven. Historically, we have used the proceeds from the issuance of equity securities and borrowings under our credit agreements to raise cash to fund acquisitions. We cannot assure you that funds will be available to us in the future to meet our budgeted capital spending or to fund acquisitions. Furthermore, our ability to borrow from sources other than our credit agreements is subject to restrictions imposed by our lenders. In addition, the indenture governing our notes contains restrictions on incurring indebtedness and the pledging of our assets. If we cannot secure additional funds for our planned development and exploitation activities or for future acquisitions, then we will be required to delay or substantially reduce these activities.

During the year ended December 31, 2003, we increased our long-term debt by 112% to approximately $208 million at December 31, 2003. This increase was primarily the result of $53.6 million in additional borrowings incurred for our going private transaction as well as $56.4 million in borrowings for acquisitions and working capital requirements during the year. We generated cash flow of approximately $42.1 million after changes in working capital, which helped fund our acquisition, development and exploitation activities. At December 31, 2003, our cash and cash equivalents balances was $7.3 million, an increase of $5.4 million from December 31, 2002. Our working capital deficit at December 31, 2003 increased to $13.6 million from $7.0 million at December 31, 2002. This occurred primarily due to changes in the quantity and in the value of our outstanding derivative financial instruments. During December 2003, we entered into several derivative contracts in anticipation of the

completion of the North Coast acquisition. This increase in the volume of oil and natural gas under contract along with the fact that product prices at December 31, 2003 were higher than at December 31, 2002, resulted in an increase in the fair value of our derivative financial instruments.

Acquisitions and Capital Expenditures

In November 2003, we entered into the North Coast Acquisition Agreement to acquire all of the issued and outstanding stock of North Coast. On January 27, 2004, we completed the North Coast acquisition. We funded the North Coast acquisition from the net proceeds from the offering of the old notes on January 20, 2004.

			Year ended December 31,
			2001		2002		2003
			(In thousands)
Capital expenditures:
	Property acquisitions		$	69,183	$	55,832	$	31,448
	Acquisition of Addison Energy Inc.			44,864		—		—
	Development capital expenditures			23,835		26,022		41,139
	Other			—		—		1,402

		Total capital expenditures	$	137,882	$	81,854	$	73,989

During 2004, we have budgeted approximately $75.6 million for our development, exploitation and exploration activities, including $23.5 million for North Coast which was acquired in January 2004. For the year ended December 31, 2003, we spent $8.9 million in the United States and $32.2 million in Canada on our development and exploitation activities. As of December 31, 2003, we were contractually obligated to spend $3.0 million for our development and exploitation activities. Further, we had signed agreements totaling $2.9 million for two property acquisitions in Canada.

We expect to continue to utilize cash from operations and available funds under our credit agreements to fund our acquisitions, capital expenditures and working capital. We believe that our capital resources from existing cash balances, cash flow from operating activities and borrowing capacity under our amended and restated credit facilities are adequate to meet the cash requirements of our business. However, future cash flows are subject to a number of variables including production volumes and oil and natural gas prices. If cash flows decline we would be required to reduce our capital expenditure budget which in turn may affect our production in future periods. We cannot assure you that operations and other capital resources will provide cash in sufficient amounts to maintain or initiate planned levels of capital expenditures.

Credit Agreements

U.S. Credit Agreement. At December 31, 2003, our former restated U.S. credit agreement provided for borrowings of up to $124.0 million under a revolving credit facility with a borrowing base of $95.0 million. On January 27, 2004, our U.S. credit agreement was amended and restated to provide for borrowings up to $250.0 million with a borrowing base of $120.0 million. Our borrowing base is determined based on a number of factors including commodity prices. We use derivative financial instruments to lessen the impact of volatility in commodity prices. The borrowing base will be redetermined as of May 1, 2004, and each November 1 and May 1 thereafter. At December 31, 2003, we had approximately $49.5 million of outstanding indebtedness, letter of credit commitments of $275,000 and approximately $45.3 million available for borrowing under our former U.S. credit agreement. At April 15, 2004, we had $1,000 of outstanding indebtedness, letter of credit commitments of $275,000 and approximately $94.7 million available for borrowing. Borrowings under our amended and restated credit agreement are secured by a first lien mortgage providing a security interest in 90%

of our U.S. oil and natural gas properties including North Coast. At our election, interest on borrowings may be (i) the greater of the administrative agent's prime rate or the federal funds effective rate plus 0.50% plus an applicable margin or (ii) LIBOR (London InterBank Offered Rate) plus an applicable margin. At December 31, 2003, the six month LIBOR rate was 1.22%, which would result in an interest rate of approximately 2.72% on any new indebtedness we may incur under the U.S. credit agreement. At April 15, 2004, we had $1,000 of outstanding U.S. indebtedness with a weighted average cost of 4.25%.

Canadian Credit Agreement. At December 31, 2003, our former Canadian credit agreement provided for borrowings of up to U.S. $186.5 million under a revolving credit facility with a borrowing base of approximately $108.5 million (CDN $140.7 million) using the exchange rate on December 31, 2003. On January 27, 2004, our Canadian credit agreement was amended and restated to provide for borrowings up to $189.4 million with a borrowing base of approximately $105.0 million (CDN $138.6 million) using the exchange rate on January 26, 2004. Our borrowing base is determined based on a number of factors including commodity prices. We use derivative financial instruments to lessen the impact of volatility in commodity prices. The borrowing base will be redetermined as of May 1, 2004, and each November 1 and May 1 thereafter. At December 31, 2003, we had approximately U.S. $108.5 million of outstanding indebtedness and were fully borrowed under our Canadian credit agreement. At April 15, 2004, we had approximately $745 of outstanding indebtedness and approximately $102.8 million available for borrowing using the exchange rate on April 15, 2004. We applied approximately $98.8 million of the net proceeds of the April 13, 2004 issuance of old notes to repay substantially all of the indebtedness outstanding under our Canadian credit agreement. Borrowings under the credit agreement are secured by a first lien mortgage providing a security interest in 90% of our Canadian oil and natural gas properties. At our election, interest on borrowings may be (i) the Canadian prime rate plus an applicable margin or (ii) the Banker's Acceptance rate plus an applicable margin. At December 31, 2003, the six month Banker's Acceptance rate was 2.66%, which would result in an interest rate of approximately 4.66% on any new indebtedness we incur under the Canadian credit agreement. At April 15, 2004, we had $745 of outstanding Canadian indebtedness at a weighted average cost of 4.00%.

Financial Covenants and Ratios. At December 31, 2003 our former U. S. and Canadian credit agreements contained certain financial covenants and other restrictions which require that we:

•: maintain a ratio of our consolidated current assets to consolidated current liabilities (as defined under our credit agreements) of at least 1.0 to 1.0 at the end of any fiscal quarter;
•: not permit our ratio of consolidated funded debt (other than the U.S. senior term loan) to consolidated EBITDA (as defined under our credit agreements) to be greater than 3.75 to 1.0 at the end of each fiscal quarter; and
•: not permit our ratio of consolidated EBITDA (as defined under our credit agreements) to consolidated interest expense to be less than 2.5 to 1.0 at the end of each fiscal quarter.

Additionally, our former credit agreements contained a number of other covenants regarding our liquidity and capital resources, included restrictions on our ability to incur additional indebtedness, restrictions on our abilitiy to pledge assets, and prohibit the payment of dividends on our common stock.

As of December 31, 2003, we were in compliance with the covenants contained in our former U.S. and Canadian credit agreements.

Our current assets to current liabilities ratio as defined under our former credit agreements was 2.3 to 1.0 at December 31, 2003.

Our consolidated funded debt (other than the U.S. senior term loan) to consolidated EBITDA at December 31, 2003 as defined under our former credit agreements was 2.9 to 1.0.

At December 31, 2003, as defined under our former credit agreements, our consolidated EBITDA to consolidated interest expense was 7.3 to 1.0.

U.S. Senior Term Loan. On October 17, 2003, we entered into a $50.0 million senior term credit agreement. We borrowed all $50.0 million under the senior term agreement and we used the proceeds to repay a portion of our indebtedness under our U.S. credit agreement. Borrowings under the term loan were collateralized by a second lien pledge of 65% of the stock of Addison and 100% of the stock of Taurus Acquisition, Inc. Interest on borrowings were at LIBOR plus an applicable margin which was fixed for periods not to exceed six months each during the life of the term loan. At December 31, 2003, the LIBOR rate plus applicable margin on the term loan was 6.12%. The U.S. senior term loan was paid in full on January 27, 2004 from the proceeds of the $350.0 million issuance of old notes. See "Capitalization."

Debt Service Requirements. Our debt service requirements, following the consummation of the Transactions, on our amended and restated U.S. credit agreement, our amended and restated Canadian credit agreement and our senior notes are shown in the following table.

		Payments Due by Period
		2004		2005		2006		2007		2008 and thereafter		Total
		(In millions)
U.S. Credit Agreement
	Interest	$	—	$	—	$	—	$	—	$	—	$	—
	Principal		—		—		—		—		—		—

			—		—		—		—		—		—
Canadian Credit Agreement
	Interest		—		—		—		—		—		—
	Principal		—		—		—		—		—		—

			—		—		—		—		—		—
7¹/4% Senior Notes
	Interest		30.8		32.6		32.6		32.6		99.2		227.8
	Principal		—		—		—		—		450.0		450.0

			30.8		32.6		32.6		32.6		549.2		677.8
Total
	Interest		30.8		32.6		32.6		32.6		99.2		227.8
	Principal		—		—		—		—		450.0		450.0

		$	30.8	$	32.6	$	32.6	$	32.6	$	549.2	$	677.8

Equity Transactions

On March 11, 2003, we entered into an Agreement and Plan of Merger providing for the merger of ER Acquisition, Inc., a wholly-owned subsidiary of EXCO Holdings into EXCO. EXCO Holdings was formed by our chairman and chief executive officer, Douglas H. Miller, and his buyout group for the purpose of completing the going private transaction, which closed on July 29, 2003. In the going private transaction, each outstanding share of our common stock, other than shares held by EXCO Holdings and its affiliates, was converted into the right to receive $18.00 in cash per share. The buyout was funded by borrowing under our former credit facilities and approximately $172.0 million in equity.

The equity capital for the going private transaction was provided by investment funds and accounts managed by Cerberus, our management and institutional and other investors.

The capital stock of EXCO Holdings is owned by:

•: members of our management and other of our employees, who own in the aggregate approximately 16% of the voting capital stock of EXCO Holdings;
•: EXCO Investors, LLC, a limited liability company formed prior to the going private transaction for the purpose of holding capital stock of EXCO Holdings, the members of which include business acquaintances of Mr. Miller, which owns approximately 11% of the voting capital stock of EXCO Holdings (the vote of which shares is controlled by Mr. Miller);
•: affiliates of Cerberus, who own in the aggregate approximately 55% of the voting capital stock of EXCO Holdings; and
•: other institutional investors, who own in the aggregate approximately 18% of the voting capital stock of EXCO Holdings.

EXCO Holdings' stepped up basis was pushed down to us in accordance with Staff Accounting Bulletin No. 54. See Note 1 to our December 31, 2003 condensed consolidated financial statements. Accordingly, EXCO Holdings' investment in us is reflected as additional paid in capital in the December 31, 2003 condensed consolidated balance sheet.

Derivative Financial Instruments

We may use derivative instruments to manage exposure to commodity prices, foreign currency and interest rate risks. Our objectives for holding derivatives are to minimize risks using the most effective methods to eliminate or reduce the impacts of these exposures.

Commodity Price Risk Management Activities

Our production is generally sold at prevailing market prices. However, we periodically enter commodity price risk management contracts for a portion of our production when market conditions are deemed favorable and oil and natural gas prices exceed our minimum internal price targets.

Our objective in entering into commodity price risk management contracts is to manage price fluctuations and achieve a more predictable cash flow associated with our acquisition activities and borrowings under our credit agreements. These transactions limit exposure to declines in prices, but also limit the benefits we would realize if prices increase. As of April 15, 2004, we had the following open positions in place:

	Swaps						Floors			Ceilings
	Gas- Mmmbtu	Average contract- $/Mmbtu		Oil- Mbbls	Average contract- $/Bbl		Gas- Mmmbtu	Average contract- $/Mmbtu		Gas- Mmmbtu	Average contract- $/Mmbtu
2004	13,054	$	4.76	764	$	24.52	9,921	$	4.05	6,700	$	6.01
2005	15,622		4.93	329		25.65	1,059		4.25	—		—
2006	10,403		4.82	—		—	—		—	—		—
2007	6,388		4.60	—		—	—		—	—		—
2008	2,745		4.55	—		—	—		—	—		—
2009	1,825		4.51	—		—	—		—	—		—
2010	1,825		4.51	—		—	—		—	—		—
2011	1,825		4.51	—		—	—		—	—		—
2012	1,830		4.51	—		—	—		—	—		—
2013	1,825		4.51	—		—	—		—	—		—

We occasionally enter into fixed-price physical delivery contracts as well as commodity price swap derivatives to manage price risk with regard to a portion of our oil and natural gas production.

Interest Rate Risk Management Activities

As a result of the North Coast acquisition, we assumed the following interest rate swaps:

Term		Notional Amount			LIBOR Rate Fixed
February 1, 2004 to December 31, 2004		$	20,000,000		3.2	%
February 1, 2004 to December 31, 2004		$	20,000,000		3.0	%

Gains and losses are determined using a 360 day year and based on the 3-month LIBOR rate set quarterly.

Contractual Obligations and Commercial Commitments

The following table presents a summary of our contractual obligations at December 31, 2003, with set and determinable payments prior to the Transactions.

	Payments Due by Period
Contractual Obligations	2004-2005		2006-2007		2008 and thereafter		Total
	(Dollars in thousands)
Long-term debt	$	—	$	207,951	$	—	$	207,951
Operating leases		2,347		1,966		1,332		5,645
Drilling/work commitments		3,018		—		—		3,018
Pending property acquisition agreements		2,888		—		—		2,888

Total contractual cash obligations	$	8,253	$	209,917	$	1,332	$	219,502

We also have a $275,000 letter of credit that has been issued to a service provider which will expire in 2004.

Pro forma for the Transactions, the following table presents a summary of our contractual obligations at December 31, 2003, with set and determinable payments.

	Payments Due by Period
Contractual Obligations	2004-2005		2006-2007		2008 and thereafter		Total
	(Dollars in thousands)
Long-term debt(1)	$	—	$	—	$	450,000	$	450,000
Operating leases		3,078		2,623	��	1,332		7,033
Drilling/work commitments		3,018		—		—		3,018
Pending property acquisition agreements		2,888		—		—		2,888

Total contractual cash obligations	$	8,984	$	2,623	$	451,332	$	462,939

(1): The notes are due on January 15, 2011. The annual interest obligation on the notes is $32.6 million.

BUSINESS

General

The following table sets forth a summary of our pro forma Proved Reserves, the PV-10 of such Proved Reserves and Standardized Measure of such Proved Reserves as of December 31, 2003.

		Proved Reserves(1)				PV-10(1)(2)		Standardized Measure(1)(2)
		Natural Gas (Bcf)	Crude Oil (Mmbbl)	NGLs (Mmbbl)	Total (Bcfe)(3)	Amount (in millions)		Amount (in millions)
Area
United States:
EXCO		156.1	10.5	0.8	223.9	$	343.7	$	234.1
North Coast		179.9	1.4	—	188.3		369.5		265.2

	Total U.S. Proved(4)	336.0	11.9	0.8	412.2		713.2		499.3

Canada:
Alberta		126.4	6.8	7.0	209.2		299.6		219.0

	Total U.S. and Canada Proved(4)	462.4	18.7	7.8	621.4	$	1,012.8	$	718.3

Proved Developed(4)		403.5	15.6	7.1	539.7	$	902.0		N/A

(1): The Proved Reserves and the PV-10 of the Proved Reserves for EXCO and North Coast as of December 31, 2003 as used in this table were prepared by Lee Keeling and Associates, Inc., an independent petroleum engineering firm in Tulsa, Oklahoma. The amount of estimated future abandonment costs and the PV-10 of those costs for EXCO and North Coast used in this table were determined by EXCO.
(2): The PV-10 data is based on December 31, 2003 NYMEX spot prices of $6.19 per Mmbtu for natural gas and $32.52 per Bbl for oil adjusted for historical differentials between NYMEX and local prices.
(3): Mmbbl converted to Bcfe on a one Bbl to six Mcf conversion ratio.
(4): On a pro forma basis as though we had completed the North Coast acquisition as of December 31, 2003.

Our present value of estimated future net revenues, or PV-10, is an estimate of future net revenues from a property at the date indicated, after deducting production and ad valorem taxes, future capital costs and operating expenses, but before deducting federal income taxes. The future net revenues have been discounted at an annual rate of 10% to determine their "present value." The present value is shown to indicate the effect of time on the value of the net revenue stream and should not be construed as being the fair market value of the properties. Estimates have been made using constant oil, natural gas and NGL prices and operating costs at the date indicated. The prices used do not reflect any adjustments for derivatives. We believe that the present value of estimated future net revenues before income taxes, while not in accordance with GAAP, is an important financial measure used by investors and independent oil and natural gas producers for evaluating the relative significance of oil and natural gas properties and acquisitions.

The Standardized Measure represents the PV-10, after giving effect to income taxes, and as calculated in accordance with FAS 69.

North Coast Acquisition

On November 26, 2003, we entered into the North Coast Acquisition Agreement, as amended and restated on December 4, 2003, to acquire all of the issued and outstanding stock of North Coast pursuant to a tender offer and merger. We acquired all of the outstanding common stock, options and warrants of North Coast on January 27, 2004 for a purchase price of $167.8 million and we assumed $57.0 million of North Coast's outstanding indebtedness. As a result of the tender offer and merger, North Coast became one of our wholly-owned subsidiaries and continues to be an energy company focused on the exploration, development and production of natural gas reserves in the Appalachian Basin. The North Coast acquisition establishes a new core operating area for us in the Appalachian Basin, which positions us to benefit from the attractive qualities of the basin and to capitalize on consolidation opportunities in the area. North Coast's operations have several attractive attributes including:

•: long-life oil and natural gas reserves with a Reserve Life at December 31, 2003 of approximately 16.3 years;
•: significantly developed reserves with approximately 91% classified as Proved Developed Reserves at December 31, 2003;
•: proximity to Midwestern and East coast natural gas markets; and
•: positive average price differential to NYMEX.

Our Competitive Strengths and Strategy

•: established histories of production;
•: long reserve lives;
•: low finding and development expenditures;
•: high drilling success rates; and
•: a high concentration of natural gas.

We seek to improve the overall quality of our asset base by exploiting our properties that have potential for value enhancement and growth, while disposing of marginal or non-strategic properties.

Appalachian Basin that were acquired in the North Coast acquisition. In addition, our extensive knowledge of our operating areas and our acquisition expertise position us to capitalize on and integrate strategic acquisition opportunities in our core areas. Due to industry trends of consolidation and asset rationalization, we believe we will continue to have opportunities to acquire oil and natural gas properties at attractive rates of return.

Cost-focused operations. At December 31, 2003, on a pro forma basis, we operate properties that contain approximately 90% of our Proved Reserves. Having operating rights with respect to our properties permits us to manage our operating costs, capital expenditures and the timing of development and exploitation of our properties. For the year ended December 31, 2003, our pro forma lease operating expense, not including production and ad valorem taxes, per Mcfe was $0.95. Using our estimate of Proved Reserves at the time of the acquisitions, we acquired 576.1 Bcfe of Proved Reserves in 111 acquisitions between December 1997 and December 31, 2003, and pro forma for our acquisition of North Coast, at an average cost of approximately $0.87 per Mcfe. Between January 1, 2000 and December 31, 2003, we invested approximately $356.6 million in acquisition, development, and exploitation activities, adding 489.6 Bcfe to our Proved Reserves and replacing approximately 693% of our net production at an average "all-in" cost, including revisions, of $0.73 per Mcfe. During the same period we drilled 136 developmental wells, achieved a drilling success rate of 89% and did not participate in any exploratory wells. We expect further improvement of our corporate efficiencies through the development and operation of a larger asset base from acquisitions.

Experienced, incentivized management team. With an average industry work experience of 23 years, our management team has considerable experience in acquiring and operating oil and natural gas properties. Since our management team first purchased a significant ownership interest in us in December 1997 and assumed its current position as our senior management, we have achieved substantial growth in our reserves, production and cash flow through a strategy of acquiring producing properties with development and exploitation potential. From December 31, 1997 to December 31, 2003, and pro forma for our acquisition of North Coast, we increased our Proved Reserves from 4.7 Bcfe to 621.4 Bcfe. In addition, members of our management team and key employees own approximately 16% of the voting capital stock of EXCO Holdings.

Comprehensive commodity price risk management program. We employ a comprehensive commodity price risk management program which better enables us to execute our business plan over the entire commodity price cycle. In connection with the incurrence of debt related to our acquisition activities, our objective in entering into these commodity price risk management transactions is to manage price fluctuations and achieve more predictable cash flows. In connection with the additional reserves that were acquired in the North Coast acquisition and the recent increase in quoted future commodity pricing, we have entered into additional commodity price risk management contracts.

Our Oil, Natural Gas and NGL Reserves

The following table summarizes Proved Reserves for EXCO and North Coast at the dates shown, and was prepared according to the rules and regulations of the SEC:

		At December 31,
		2001						2002						2003
		EXCO						EXCO						EXCO
		United States		Canada		Total		United States		Canada		Total		United States		Canada		Total		North Coast		Pro Forma Total
Oil (Mbbls)
	Developed		7,555		3,414		10,969		9,067		5,425		14,492		7,750		6,529		14,279		1,343		15,622
	Undeveloped		3,498		386		3,884		3,214		329		3,543		2,740		257		2,997		85		3,082

	Total		11,053		3,800		14,853		12,281		5,754		18,035		10,490		6,786		17,276		1,428		18,704

Natural Gas (Mmcf)
	Developed		87,868		65,230		153,098		115,222		92,512		207,734		123,897		117,030		240,927		162,587		403,514
	Undeveloped		22,388		8,174		30,562		26,376		15,183		41,559		32,165		9,362		41,527		17,307		58,834

	Total		110,256		73,404		183,660		141,598		107,695		249,293		156,062		126,392		282,454		179,894		462,348

Natural Gas Liquids (Mbbls)
	Developed		774		2,470		3,244		985		3,432		4,417		724		6,377		7,101		—		7,101
	Undeveloped		13		359		372		112		562		674		103		597		700		—		700

	Total		787		2,829		3,616		1,097		3,994		5,091		827		6,974		7,801		—		7,801

Total (Mmcfe)(1)			181,296		113,178		294,474		221,866		166,183		388,049		223,964		208,952		432,916		188,462		621,378

Pre-tax Present Value, discounted at 10% (PV-10) (in thousands)
	Developed	$	92,150	$	76,127	$	168,277	$	219,399	$	218,013	$	437,412	$	274,244	$	282,590	$	556,834	$	345,174	$	902,008
	Undeveloped		13,540		7,338		20,878		64,433		28,178		92,611		69,473		17,056		86,529		24,346		110,875

	Total	$	105,690	$	83,465	$	189,155	$	283,832	$	246,191	$	530,023	$	343,717	$	299,646	$	643,363	$	369,520	$	1,012,883

Standardized Measure (in thousands)(2)		$	83,085	$	60,444	$	143,529	$	152,923	$	157,417	$	310,340	$	234,085	$	219,019	$	453,104	$	265,173	$	718,277

(1): Mbbl converted to Mmcfe on a one Bbl to six Mcf conversion ratio. The PV-10 data is based on December 31, 2003 NYMEX spot prices of $6.19 per Mmbtu for natural gas and $32.52 per Bbl for oil adjusted for historical differentials between NYMEX and local prices.
(2): The Standardized Measure represents the PV-10, after giving effect to income taxes, and as calculated in accordance with FAS 69.

The reserve estimates presented as of December 31, 2001, 2002 and 2003 for EXCO and the reserve estimates as of December 31, 2003 for North Coast have been prepared by Lee Keeling and Associates, Inc., an independent petroleum engineering firm in Tulsa, Oklahoma. The estimate of EXCO's and North Coast's PV-10 and Standardized Measure is based upon EXCO's estimate of future abandonment costs and the report on Proved Reserves as prepared by Lee Keeling and Associates, Inc. as of December 31, 2003. Estimates of oil, natural gas and NGL reserves are projections based on engineering data and are forward-looking in nature. These reports rely upon various assumptions, including assumptions required by the SEC, such as constant oil, natural gas and NGL prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. These reports should not be construed as the current market value of our Proved Reserves. The process of estimating oil and natural gas reserves is also dependent on geological, engineering and economic data for each reservoir. Because of the uncertainties inherent in the interpretation of this data, we cannot ensure that the reserves will ultimately be realized. Our actual results could differ materially. See also Note 16 of the notes to our 2003 consolidated financial statements included in this prospectus for additional information regarding our oil, natural gas and NGL reserves, including the present value of future net revenues and the Standardized Measure.

Our Production, Prices and Expenses

The following table summarizes for the periods indicated, revenues (including cash settlements of derivative financial instruments), net production of oil, natural gas and NGLs sold, the average sales

price per unit of oil, natural gas and NGLs and costs and expenses associated with the production of oil, natural gas and NGLs for EXCO and North Coast:

		At December 31,
		2001						2002						2003
		EXCO						EXCO						EXCO
		United States		Canada		Total		United States		Canada		Total		United States		Canada		Total		North Coast
		(In thousands, except production and per unit amounts)
Sales:
	Oil:
	Revenue	$	21,633	$	1,739	$	23,372	$	16,330	$	9,661	$	25,991	$	17,083	$	12,802	$	29,885	$	3,085
	Production sold (Mbbl)		887		80		967		869		399		1,268		755		448		1,203		114
	Average sales price per Bbl(1)	$	24.40	$	21.71	$	24.17	$	18.78	$	24.23	$	20.50	$	22.63	$	28.58	$	24.84	$	27.13
	Natural Gas:
	Revenue	$	29,558	$	5,394	$	34,952	$	16,697	$	18,077	$	34,774	$	19,404	$	42,228	$	61,632	$	55,330
	Production sold (Mmcf)		6,243		2,086		8,329		6,878		6,565		13,443		7,551		8,360		15,911		10,867
	Average sales price per Mcf(1)	$	4.73	$	2.59	$	4.20	$	2.43	$	2.75	$	2.59	$	2.57	$	5.05	$	3.87	$	5.09
	Natural Gas Liquids:
	Revenue	$	1,826	$	1,087	$	2,913	$	1,227	$	4,454	$	5,681	$	1,342	$	8,348	$	9,690		—
	Production sold (Mbbl)		96		68		164		74		242		316		59		332		391		—
	Average sales price per Bbl	$	18.97	$	15.90	$	17.70	$	16.66	$	18.38	$	17.98	$	22.58	$	25.11	$	24.73		—
Costs and Expenses:
	Average production cost per Mcfe	$	1.76	$	0.85	$	1.59	$	1.52	$	0.98	$	1.27	$	1.50	$	1.20	$	1.35	$	0.88
	General and administrative expense per Mcfe	$	0.34	$	0.23	$	0.32	$	0.54	$	0.40	$	0.48	$	1.22	$	0.76	$	0.99	$	0.63
	Depreciation, depletion and amortization per Mcfe	$	0.80	$	1.50	$	0.94	$	0.76	$	0.87	$	0.81	$	0.88	$	1.00	$	0.94	$	0.80

(1): Including the effects of derivative cash settlements.

Our Interest in Productive Wells

The following table quantifies on a pro forma basis as of December 31, 2003 our productive wells (wells that are currently producing oil or natural gas or are capable of production), including temporarily shut-in wells. The number of total gross oil and natural gas wells excludes any multiple completions. Gross wells refers to the total number of physical wells that we hold any working interest in, regardless of our percentage interest. A net well is not a physical well, but is a concept that reflects

the actual total working interests we hold in all wells. We compute the number of net wells we own by totaling the percentage interests we hold in all our gross wells.

		Gross Wells(1)			Net Wells
		Oil	Gas	Total	Oil	Gas	Total
United States:
EXCO:
	Colorado	13	115	128	8	106	114
	Kansas	115	45	160	46	22	68
	Louisiana	17	19	36	13	13	26
	Mississippi	27	—	27	24	—	24
	Nebraska	44	4	48	20	2	22
	New Mexico	9	84	93	1	32	33
	Oklahoma	92	28	120	40	6	46
	Texas	470	171	641	141	89	230
	Wyoming	73	9	82	16	7	23
North Coast:
	Kentucky	—	136	136	—	131	131
	Ohio	—	1,242	1,242	—	976	976
	Pennsylvania	39	423	462	35	342	377
	Virginia	—	1	1	—	1	1
	West Virginia	368	1,500	1,868	365	1,367	1,732

Total United States		1,267	3,777	5,044	709	3,094	3,803

Canada:
	Alberta	190	328	518	83	225	308

	Total U.S. and Canada	1,457	4,105	5,562	792	3,319	4,111

(1): As of December 31, 2003, we owned interests in 17 gross wells with multiple completions.

As of December 31, 2003, on a pro forma basis, we were the operator of 4,299 gross (3,761 net) wells, which represented approximately 90% of the present value of estimated future net revenues (as of December 31, 2003) of our Proved Reserves.

Our Drilling Activities

We intend to concentrate our drilling activity on lower risk, development-type properties. The number and types of wells we drill will vary depending on the amount of funds we have available for drilling, the cost of each well, the size of the fractional working interests we acquire in each well and the estimated recoverable reserves attributable to each well.

During the two year period ended December 31, 2003, we did not participate in the drilling of any exploratory wells.

The following table summarizes our approximate gross and net interests in the development wells we drilled during the periods indicated and refers to the number of wells completed at any time during the period, regardless of when drilling was initiated:

		EXCO Development Wells
		Gross			Net
		Productive	Dry	Total	Productive	Dry	Total
Year ended December 31, 2001
	United States	32	4	36	17.0	1.0	18.0
	Canada	9	1	10	8.6	1.0	9.6

	Total	41	5	46	25.6	2.0	27.6

Year ended December 31, 2002
	United States	9	1	10	5.4	.3	5.7
	Canada	12	1	13	7.5	1.0	8.5

	Total	21	2	23	12.9	1.3	14.2

Year ended December 31, 2003
	United States	12	3	15	8.9	1.3	10.2
	Canada	36	5	41	20.7	4.3	25.0

	Total	48	8	56	29.6	5.6	35.2

The drilling activities in the United States referenced in the above table were primarily conducted in Texas, Oklahoma, New Mexico, Louisiana and Kansas. The drilling activities in Canada referenced in the above table were conducted in Alberta. As of December 31, 2003, we owned a 100% working interest in one well being drilled in Louisiana and a 56.5% working interest in one well being drilled in Texas and a 100% working interest in one well being drilled in Alberta, Canada. As of February 29, 2004, we owned an 18% working interest in one well being drilled in New Mexico.

The following table summarizes North Coast's approximate gross and net interests in the exploratory wells drilled during the periods indicated and refers to the number of wells completed at any time during the period, regardless of when drilling was initiated:

	North Coast Exploratory Wells
	Gross			Net
	Productive	Dry	Total	Productive	Dry	Total
Year ended December 31, 2001	7	—	7	6.5	—	6.5
Year ended December 31, 2002	8	—	8	6.1	—	6.1
Year ended December 31, 2003	9	4	13	7.7	1.8	9.5

The following table summarizes North Coast's approximate gross and net interests in the development wells it drilled during the periods indicated and refers to the number of wells completed at any time during the period, regardless of when drilling was initiated:

	North Coast Development Wells
	Gross			Net
	Productive	Dry	Total	Productive	Dry	Total
Year ended December 31, 2001	77	—	77	51.3	—	51.3
Year ended December 31, 2002	107	—	107	94.7	—	94.7
Year ended December 31, 2003	75	1	76	73.8	1.0	74.8

As of December 31, 2003, North Coast owned a 100% working interest in one well being drilled in Pennsylvania and a 100% working interest in one well being drilled in Kentucky. As of February 29, 2004, North Coast owned a 100% working interest in one well being drilled in Ohio.

Summary of Our Development and Exploitation Projects

We are currently pursuing an active development and exploitation strategy. Pro forma for the year 2004, we have budgeted up to $75.6 million for development drilling, exploration, recompletions, production facilities and other exploitation related projects to implement this strategy, of which $300,000 is for exploration activities associated with the North Coast properties.

Set forth below are highlights of our planned activities for 2004.

EXCO Fields/Areas

Vinegarone Field

The Vinegarone Field is a natural gas field located in Val Verde County, Texas. We hold working interests ranging from less than 2% to 100% in 24 producing wells, of which we operate 21 wells. The wells produce from the Strawn and Swanson formations at depths from 10,000 to 10,500 feet. We currently plan to drill three wells during 2004.

Black Lake Field

The Black Lake Field is a natural gas field located in Natchitoches Parish, Louisiana. We hold an 84% working interest and operate all 23 producing wells in this 16,936 acre unitized field. The wells produce from the Pettit Lime formation at a depth of approximately 8,000 feet. We plan to drill two horizontal wells and perform artificial lift projects on four wells in this field during 2004.

Wattenberg Field

The Wattenberg Field is a natural gas field located in Weld County, Colorado. We acquired these properties during 2002. We hold working interests ranging from less than 3% to 100% in 111 producing wells, of which we operate 108 wells. The wells produce primarily from the Codell formation at a depth of approximately 7,000 feet. We currently plan to drill seven wells and perform workover operations on five wells during 2004.

Pecan Lake, South

The Pecan Lake, South Field is located in Cameron Parish, Louisiana. We hold an average working interest of 90% in six producing wells. Pecan Lake, South produces from the Miocene section at depths ranging from 7,000 to 16,000 feet. We completed the sidetrack of the Miami Corp 35 well, in which we have a working interest of 100%, during the first quarter of 2004. The well is currently producing more than 6.0 Mmcf per day.

Garrington Area

The Garrington Area is located in Alberta, Canada and produces oil and natural gas from Cretaceous and Mississippian formations at depths from 5,000 to 9,000 feet. We have an average working interest of 87% in 218 producing wells, 206 of which we operate. We plan to complete 83 exploitation projects in the Garrington Area during 2004, which include recompletions, lift optimizations and facility expansions. We plan to drill 16 wells in this area during 2004.

Pine Creek Area

The Pine Creek Area is located in Alberta, Canada and produces oil and natural gas from the Cretaceous formation at depths from 6,000 to 9,000 feet. We have an average working interest of 75% in 88 producing wells, 75 of which we operate. We plan to complete 24 exploitation projects in the Pine Creek Area during 2004, which include recompletions, lift optimizations and facility expansions. We plan to drill three wells in this area during 2004.

North Coast Areas

Ravenswood Area

The Ravenswood Area is located in West Virginia. North Coast operates 639 wells, which represent 94% of the reserves North Coast has at Ravenswood. Production in the Ravenswood area is primarily from Mississippian and Devonian formations at depths of 2,500 to 4,400 feet. We have identified 11 drilling locations for 2004.

Maben Area

The Maben Area is located in Southwest West Virginia. North Coast operates 301 wells, which represent 95% of the reserves North Coast owns in the Maben Area. Maben produces from Mississippian and Devonian formations at depths ranging from 1,500 to 5,500 feet. We have identified 13 drilling locations for 2004.

Cambridge Area

The Cambridge Area is located in Southern Ohio. North Coast operates 735 wells, which represent 95% of the reserves we own in the Cambridge Area. Cambridge produces from the Clinton Reservoir and the Knox series at depths from 3,000 feet to 6,200 feet. We have identified three proved drilling locations and eight non-proved drilling locations in the Knox series for 2004.

Northwest Pennsylvania Area

The Northwest Pennsylvania Area of the Appalachia Basin includes the Jamestown, Corry and Allegheny National Forest fields. North Coast operates 457 wells, which represent 99% of the reserves North Coast has in the area. Production is from the Medina and Devonian formations at depths from 1,600 feet to 4,900 feet. For 2004, we plan to drill more than 50 development wells.

Our Developed and Undeveloped Acreage

Developed acreage are those acres spaced or assignable to producing wells. Undeveloped acreage are those acres that do not currently have completed wells capable of producing commercial quantities

of oil or natural gas, regardless of whether the acreage contains Proved Reserves. The following table sets forth the developed and undeveloped acreage for us and North Coast at December 31, 2003:

		Developed Acreage		Undeveloped Acreage
		Gross	Net	Gross	Net
United States:
EXCO:
	Colorado	12,212	11,183	3,307	2,691
	Kansas	21,484	10,455	4,400	194
	Louisiana	26,903	14,678	10,527	7,546
	Mississippi	5,576	743	4,226	3,281
	Montana	7,894	339	—	—
	Nebraska	21,491	6,762	8,918	2,429
	New Mexico	23,753	7,156	8,835	4,752
	Oklahoma	10,476	2,011	1,373	723
	Texas	68,086	23,293	30,330	16,046
	Wyoming	7,551	1,963	5,781	2,740
North Coast:
	Kentucky	13,780	13,780	17,200	17,200
	Ohio	112,738	112,738	45,489	36,046
	Pennsylvania	43,762	43,762	43,074	43,017
	Tennessee	—	—	3,017	3,017
	Virginia	107	107	—	—
	West Virginia	88,930	86,888	143,730	139,235

Total United States		464,743	335,858	330,207	278,917
Canada:
	Alberta	176,616	117,669	130,034	93,009

	Total	641,359	453,527	460,241	371,926

The primary terms of our oil and natural gas leases expire at various dates, generally ranging from one to five years. Almost all of our undeveloped acreage is "held by production," which means that these leases are active as long as we produce oil or natural gas from the acreage. Upon ceasing production, these leases will expire.

We evaluate our portfolio of properties on an ongoing basis to determine the economic viability of the properties and whether these properties enhance our objectives. During the course of normal business, we may dispose of producing properties and undeveloped acreage if we believe that it is in our best interest. Since January 1, 2004, we have divested $7.3 million of non-core properties, including properties sold for $6.6 million on March 31, 2004.

Our Principal Customers

During the year ended December 31, 2003, sales of oil to Plains All American, Inc. and affiliates and sales of natural gas to Nexen Marketing U.S.A., Inc. and to Coral Canada U.S. Inc. accounted for 16.6%, 12.9% and 11.4%, respectively, of our total pro forma oil and natural gas revenues. Sales of oil and natural gas to our top six purchasers during the year ended December 31, 2003, accounted for 54.7% of our total pro forma oil and natural gas revenues. If we were to lose any one of our oil and natural gas purchasers, the loss could temporarily cease or delay production and sale of our oil and natural gas in that particular purchaser's service area. If we were to lose a purchaser, we believe we could identify a substitute purchaser. During 2002, several large wholesale purchasers of natural gas

experienced significant downgrades in their credit ratings. As a result, many of these companies have either significantly reduced their level of natural gas purchases or have discontinued their purchases of natural gas. Although we do not believe that we have yet been significantly impacted by these changes, the loss of these large natural gas purchasers could have a detrimental effect on the natural gas market in general and on our ability to find purchasers for our natural gas. In appropriate circumstances, we require letters of credit or other forms of credit enhancement from our purchasers.

Competition

We are also affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. We are unable to predict when, or if, such shortages may again occur or how they would affect our development and exploitation program.

Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases and drilling rights, and we cannot assure you that we will be able to compete satisfactorily. Many large oil companies have been actively marketing some of their existing producing properties for sale to independent producers. We cannot assure you that we will be successful in acquiring any of these properties.

Applicable Laws and Regulations

U.S. Regulations

The availability of a ready market for oil and natural gas production depends upon numerous factors beyond our control. These factors include state and federal regulation of oil and natural gas production and transportation, as well as regulations governing environmental quality and pollution control, state limits on allowable rates of production by a well or proration unit, the amount of oil and natural gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. For example, a productive natural gas well may be "shut-in" because of an over-supply of natural gas or lack of an available natural gas pipeline in the areas in which we may conduct operations. State and federal regulations generally are intended to prevent waste of oil and natural gas, protect rights to produce oil and natural gas between owners in a common reservoir, control the amount of oil and natural gas produced by assigning allowable rates of production and control contamination of the environment. Pipelines and gas plants also are subject to the jurisdiction of various federal, state and local agencies.

Our sales of natural gas are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of gas by pipelines are regulated by the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act, as well as under Section 311 of the Natural Gas Policy Act. Since 1985, the FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to gas buyers and sellers on an open-access, non-discriminatory basis.

Our sales of oil are also affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of oil by pipelines are regulated by the

FERC under the Interstate Commerce Act. FERC has implemented a simplified and generally applicable rate-making methodology for interstate oil pipelines to fulfill the requirements of Title VII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil pipeline rates. Within the last three years, the FERC has announced several important transportation-related policy statements and rule changes, including a statement of policy and final rule issued February 25, 2000, concerning alternatives to its traditional cost-of-service rate-making methodology to establish the rates interstate natural gas pipelines may charge for their services. The final rule revises FERC's pricing policy and current regulatory framework to improve the efficiency of the market and further enhance competition in natural gas markets.

With respect to transportation of oil and natural gas on or across the Outer Continental Shelf (OCS), the Outer Continental Shelf Lands Act (OCSLA) requires that all oil and natural gas pipelines, including gathering facilities, provide open and non-discriminatory access to both owner and non-owner shippers. FERC has authority under OCSLA to exempt gathering facilities from the open access transmission requirements. A recent decision by the U.S. Court of Appeals, District of Columbia Circuit (The Williams Companies v. FERC, No. 02-5056, decided October 10, 2003) appears to narrow FERC's jurisdiction, and broaden that of the Department of Interior, to enforce open access requirements under OCSLA. The decision did not address FERC's authority to enforce open access requirements for the Outer Continental Shelf under its Natural Gas Act jurisdiction over gas and its Interstate Commerce Act jurisdiction over oil. The decision is subject to appeal within 90 days of issuance. The decision relies upon a lower court's decision that FERC lacked authority under OCSLA to require natural gas companies to file information concerning their pricing and service structures.

In the event we conduct operations on federal, state or Indian oil and gas leases, such operations must comply with numerous regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and certain of such operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Bureau of Land Management (BLM) or Minerals Management Service (MMS) or other appropriate federal or state agencies.

Our OCS leases in federal waters are administered by the MMS and require compliance with detailed MMS regulations and orders. The MMS has promulgated regulations implementing restrictions on various production-related activities, including restricting the flaring or venting of natural gas. Under certain circumstances, the MMS may require any operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect our financial condition and operations. On March 15, 2000, the MMS issued a final rule effective June 1, 2000, that amended its regulations governing the calculation of royalties and the valuation of crude oil produced from federal leases. Among other matters, this rule amended the valuation procedure for the sale of federal royalty oil by eliminating posted prices as a measure of value and relying instead on arm's length sales prices and spot market prices as market value indicators. Because we generally sell our production to third parties and therefore pay royalties on production from federal leases, we do not anticipate that this final rule will have any substantial impact on us.

The Mineral Leasing Act of 1920 (the Mineral Act) prohibits direct or indirect ownership of any interest in federal onshore oil and natural gas leases by a foreign citizen of a country that denies "similar or like privileges" to citizens of the United States. Such restrictions on citizens of a "non-reciprocal" country include ownership or holding or controlling stock in a corporation that holds a federal onshore oil and gas lease. If this restriction is violated, the corporation's lease can be canceled in a proceeding instituted by the United States Attorney General. Although the regulations of the BLM (which administers the Mineral Act) provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. We own interests in federal onshore oil and natural gas leases. It is possible that some of our shareholders may be citizens of foreign countries, and at some time in the future might be determined to be non-reciprocal under the Mineral Act.

The pipelines we use to gather and transport our oil and natural gas may be subject to regulation by the Department of Transportation (DOT) under the Hazardous Liquids Pipeline Safety Act of 1979, as amended (HLPSA). The HLPSA governs the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Where applicable, the HLPSA requires us and other pipeline operators to comply with regulations issued pursuant to HLPSA that are designed to permit access to and allow copying of records and to make certain reports available and provide information as required by the Secretary of Transportation.

The Pipeline Safety Act of 1992 (the Pipeline Safety Act) amends the HLPSA in several important respects. The Pipeline Safety Act requires the Research and Special Programs Administration (RSPA) of DOT to consider environmental impacts, as well as its traditional public safety mandate, when developing pipeline safety regulations. In addition, the Pipeline Safety Act mandates the establishment by DOT of pipeline operator qualification rules requiring minimum training requirements for operators and requires that pipeline operators provide maps and records to RSPA. It also authorizes RSPA to require certain pipeline modifications as well as operational and maintenance changes. We believe our pipelines are in substantial compliance with the HLPSA and the Pipeline Safety Act and their regulations and comparable state laws and regulations where such laws and regulations are applicable. However, we could incur significant expenses if new or additional safety measures are required.

U.S. Federal Taxation

The federal government may propose tax initiatives that affect us. We are unable to determine what effect, if any, future proposals would have on product demand or our results of operations.

U.S. Environmental Regulation

The exploration, development and production of oil and natural gas, including the operation of saltwater injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, installing and operating oil and natural gas wells. Our domestic activities are subject to federal environmental laws and regulations, including, but not limited to:

•: the Oil Pollution Act of 1990 (OPA);
•: the Clean Water Act (CWA);
•: the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA);
•: the Resource Conservation and Recovery Act (RCRA);
•: the Clean Air Act (CAA); and
•: the Safe Drinking Water Act (SDWA).

Our domestic activities are also controlled by state regulations promulgated under comparable state statutes. We also are subject to regulations governing the handling, transportation, storage and disposal of naturally occurring radioactive materials that are found in our oil and natural gas operations. Civil and criminal fines and penalties may be imposed for non-compliance with environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking certain of our activities, limit or prohibit other activities because of protected areas or species, can impose certain substantial liabilities for the cleanup of pollution, impose certain reporting requirements, regulate remedial plugging operations to prevent future contamination and can require substantial expenditures for compliance.

Under OPA and CWA, our release of oil and hazardous substances into or upon waters of the United States, adjoining shorelines and wetlands and offshore areas could result in our being held

responsible for: (1) the costs of remediating a release, (2) administrative, civil or criminal fines or penalties or (3) OPA specified damages, such as loss of use, and natural resource damages. The extent of our liability could be extensive depending upon the circumstances of the release. Liability can be joint and several and without regard to fault. The CWA also may impose permitting requirements for certain discharges of pollutants and requirements to develop Spill Prevention Control and Countermeasure Plans and Facility Response Plans to address potential discharges of oil into or upon waters of the United States and adjoining shorelines.

CERCLA and comparable state statutes, also known as Superfund laws, can impose joint, several and retroactive liability, without regard to fault or the legality of the original conduct, on specified classes of persons for the release of a "hazardous substance" into the environment. In practice, cleanup costs are usually allocated among various responsible parties. Liability can arise from conditions on properties where operations are conducted and/or from conditions at third party disposal facilities where wastes from operations were sent. Although CERCLA, as amended, currently exempts petroleum (including oil, natural gas and NGLs) from the definition of hazardous substance, some similar state statutes do not provide such an exemption. We cannot assure you that the exemption will be preserved in any future amendments of the act. Such amendments could have a significant impact on our costs or operations. Additionally, our operations may involve the use or handling of other materials that may be classified as hazardous substances under CERCLA and similar state statutes at a future date.

RCRA and comparable state and local programs impose requirements on the management, treatment, storage and disposal of both hazardous and nonhazardous solid wastes. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hydrocarbons or other solid wastes may have been disposed or released on or under the properties we own or lease or the locations where such wastes have been taken for disposal. In addition, many of these properties have been owned or operated by third parties. We have not had control over such parties' treatment of hydrocarbons or other solid wastes and the manner in which such substances may have been disposed or released. We also generate hazardous and nonhazardous solid waste in our routine operations. From time to time, proposals have been made that would reclassify certain oil and natural gas wastes, including wastes generated during pipeline, drilling and production operations, as "hazardous wastes" under RCRA, which would make these solid wastes subject to much more stringent handling, transportation, storage, disposal and clean-up requirements. Adoption of these proposals could have a significant impact on our operating costs. While state laws vary on this issue, state initiatives to further regulate oil and natural gas wastes could have a similar impact on our operations.

Oil and natural gas exploration and production, and possibly other activities, have been conducted at the majority of our properties by previous owners and operators. Materials from these operations remain on some of the properties and in some instances may require remediation. In some instances, we have agreed to indemnify the sellers of producing properties from whom we have acquired reserves against certain liabilities for environmental claims associated with the properties. We do not believe the costs to be incurred by us for compliance and remediating previously or currently owned or operated properties will be material, but we cannot guarantee that result.

If in the course of our routine oil and natural gas operations surface spills and leaks occur, including casing leaks of oil or other materials, we may incur penalties and costs for waste handling, remediation and third party actions for damages. Moreover, we are only able to directly control the operations of the wells that we operate. Notwithstanding our lack of control over wells owned by us but operated by others, the failure of the operator to comply with applicable environmental regulations may be attributable to us and may create legal liabilities for us.

In 2003, DOT through RSPA adopted new requirements for certain shippers of hazardous materials. These have both training and security planning requirements that may apply to our

operations. We do not believe that the costs that will be incurred by us for compliance will be significant, but cannot guarantee that result or predict the ultimate cost to us.

We do not anticipate that we will be required in the near future to expend amounts that are material in relation to our total capital expenditures program complying with environmental laws and regulations, but inasmuch as these laws and regulations are frequently changed and are subject to interpretation, we are unable to predict the ultimate cost of compliance or the extent of liability risks. We are also unable to assure you that more stringent laws and regulations protecting the environment will not be adopted and that we will not incur material expenses in complying with environmental laws and regulations in the future. If substantial liabilities to third parties or governmental entities are incurred, the payment of such claims may reduce or eliminate the funds available for project investment or result in loss of our properties. Although we maintain insurance coverage we consider to be customary in the industry, we are not fully insured against all of these risks, either because insurance is not available or because of high premiums. Accordingly, we may be subject to liability or may lose substantial portions of properties due to hazards that cannot be insured against or have not been insured against due to prohibitive premiums or for other reasons. The imposition of any of these liabilities or compliance obligations on us may have a material adverse effect on our financial condition and results of operations.

OSHA and Other Regulation

We are subject to the requirements of the federal Occupational Safety and Health Act (OSHA) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

Canadian Laws and Regulations

General

The oil and natural gas industry is subject to extensive controls and regulations imposed by various levels of government. The provincial government of Alberta has legislation and regulations which govern land tenure, royalties, production rates, environmental protection, the prevention of waste and other matters. Although it is not expected that these controls and regulations will affect our operations in a manner materially different than they would affect other oil and natural gas companies of similar size, the controls and regulations should be considered carefully by investors in the oil and natural gas industry. Outlined below are some of the principal aspects of legislation and regulations governing the oil and natural gas industry. All current legislation is a matter of public record and we are unable to predict what additional legislation or amendments may be enacted.

Pricing and Marketing—Oil

In Canada, producers of oil negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. The prices we receive depend, in part, on oil type and quality, prices of competing fuels, distance to market, the value of refined products and the supply/demand balance and other contractual terms. Oil exports from Canada may be made pursuant to export contracts with terms not exceeding one year, in the case of light crude, and not exceeding two years, in the case of heavy crude, provided that an order approving any such export has been obtained from the National Energy Board (NEB). Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export license from the NEB, which requires governmental approval.

Pricing and Marketing—Natural Gas

In Canada, the price of natural gas sold in intraprovincial, interprovincial and international trade is determined by negotiations between buyers and sellers. The price we receive depends, in part, on natural gas quality, prices of competing natural gas and other fuels, distance to market, access to downstream transportation, length of contract term, weather conditions, the supply/demand balance and other contractual terms. Natural gas exported from Canada is subject to regulation by the NEB and the government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet certain criteria prescribed by the NEB and the government of Canada. Natural gas exports for a term of less than two years or for a term of two to 20 years (in quantities of not more than 30,000 cubic meters per day) must be made pursuant to an NEB order. Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or a larger quantity requires an exporter to obtain an export license from the NEB, which requires governmental approval.

The provincial government of Alberta also regulates the volume of natural gas that may be removed from Alberta for consumption elsewhere, based on such factors as reserve availability, transportation arrangements and market considerations.

Pipeline Capacity

Although pipeline expansions are ongoing, the lack of firm natural gas pipeline capacity continues to affect the ability to produce and market natural gas production. The prorating of capacity on the interprovincial pipeline systems may also affect the ability to export oil.

The North American Free Trade Agreements

On January 1, 1994, the North American Free Trade Agreement, NAFTA, among the governments of Canada, the U.S. and Mexico became effective. NAFTA carries forward most of the material energy terms contained in the Canada-U.S. Free Trade Agreement. In the context of energy resources, Canada continues to remain free to determine whether exports to the U.S. or Mexico will be allowed, provided that any export restrictions do not:

•: reduce the proportion of energy resource exported relative to domestic use (based upon the proportion prevailing in the most recent 36 month period);
•: impose an export price higher than the domestic price; or
•: disrupt normal channels of supply. All three countries are prohibited from imposing minimum export or import price requirements.

Land Tenure

Oil and natural gas located in the western provinces is owned predominately by the respective provincial governments. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licenses and permits for varying terms and conditions set forth in provincial legislation which may include requirements to perform specific work or make payments. Oil and natural gas located in such provinces can also be privately owned and rights to explore for and produce such oil and natural gas are generally granted by lease on such terms and conditions as may be negotiated.

Royalties and Incentives

In addition to federal regulation, each province in Canada has legislation and regulations that govern land tenure, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of oil and natural gas production. Royalties payable on

production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee, although production from such lands is also subject to certain provincial taxes and royalties. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production. The rate of royalties payable depends in part on prescribed reference prices, the type of product being produced, well productivity, geographical location and field discovery date.

From time to time the federal and provincial governments in Canada have established incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays and tax credits and are generally introduced when commodity prices are low. The programs are designed to encourage exploration and development activity by improving earnings and cash flow within the industry. The trend in recent years has been for provincial governments to allow such programs to expire without renewal, and consequently few such programs are currently operative.

On October 13, 1992, the provincial government of Alberta implemented major changes in its royalty structure and created incentives for exploring and developing oil and natural gas reserves. The incentives created include: (1) a one year royalty holiday on new oil discovered on or after October 1, 1992; (2) incentives by way of royalty holidays and reduced royalties on reactivated, low productivity, vertical re-entry and horizontal wells; (3) introduction of separate par pricing for light/medium and heavy oil; and (4) a modification of the royalty formula structure through the implementation of the Third Tier Royalty with a base rate of 2% and a rate cap of 25% for oil pools discovered after September 30, 1992. The new oil royalty reserved to the Crown has a base rate of 10% and a rate cap of 30%. The old oil royalty reserved to the Crown has a base rate of 10% and a rate cap of 35%.

In Alberta, the royalty reserved to the Crown in respect of natural gas production, subject to various incentives, is between 15% and 30%, in the case of new gas, and between 15% and 35%, in the case of old gas, depending upon a prescribed or corporate average reference price.

In Alberta, certain producers of oil or natural gas are also entitled to a credit against the royalties payable to the Alberta Crown by virtue of the Alberta royalty tax credit program (ARTC). The ARTC program is based on a price-sensitive formula, and the ARTC rate varies between 75%, at prices for oil below CDN $100 per cubic meter, and 25%, at prices above CDN $210 per cubic meter. The ARTC rate is applied to a maximum of CDN $2,000,000 of Alberta Crown royalties payable for each producer or associated group of producers. Crown royalties on production from producing properties acquired from companies claiming maximum entitlement to ARTC will generally not be eligible for ARTC. The ARTC rate is established quarterly based on the average "par price," as determined by the Alberta Resource Development Department for the previous quarterly period.

Oil and natural gas royalty holidays for specific wells and royalty reduction reduce the amount of Crown royalties paid by us to the provincial governments. The ARTC provides a rebate on Alberta Crown royalties paid in respect of eligible producing properties.

Canadian Environmental Regulation

Our operations include the exploration, production and development of oil and natural gas and are subject to environmental regulation, including 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 natural gas industry operations. In addition, legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. In addition, applicable environmental laws may impose remediation obligations with respect to property designated as a contaminated site upon certain responsible persons, which include persons responsible for the substance causing the contamination, persons who caused the release of the substance and any past or present owner, tenant or other person in possession of the site. Compliance with such legislation can require significant expenditures. We could incur material

fines and penalties, the revocation of necessary licenses and authorizations and liability for pollution damage and cleanup costs as a result of violations of, or liabilities under, environmental laws and regulations.

In Alberta, environmental compliance is governed by the Alberta Environmental Protection and Enhancement Act ("AEPEA"). In addition to replacing a variety of older statutes which related to environmental matters, the AEPEA imposes certain new environmental responsibilities on oil and natural gas operators in Alberta and in certain instances also imposes greater penalties for violations.

On December 17, 2002, Canada ratified the Kyoto Protocol, thereby committing to a 6% reduction in greenhouse gas emissions below 1990 levels within the 2008-2012 commitment period. To inform the ratification decision, the Climate Change Plan for Canada was released in November 2002, outlining the approach the Government of Canada intends to take to implement its emissions reduction commitment. Natural Resources Canada, an arm of the federal government, established the Large Final Emitters Group to serve as the focal point for government discussions with industry sectors in the implementation of the Climate Change Plan for Canada. In addition to other targeted measures set out in the Plan, it established a three-pronged approach to address emissions from large industrial emitters: targets for reductions established through covenant with a regulatory or financial backstop (55 megatonne (Mt) reduction); access to a domestic emissions trading system, domestic offsets and international permits to provide flexibility; and complementary measures (an additional 11 Mt reduction). The Large Final Emitters Group will negotiate agreements with large industrial emitters to reduce greenhouse gas emissions through 2012, using the mechanisms described above. As a result of Canada's ratification of the Kyoto Protocol, reductions in greenhouse gases from our operations may be required, which could result in increased capital expenditures and/or reductions in production of oil and gas.

We will be taking such steps as required to ensure compliance with the AEPEA and similar legislation in other jurisdictions in which we operate. We believe that we are in material compliance with applicable environmental laws and regulations. We also believe that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards.

Title to Our Properties

When we acquire developed properties, we conduct a title investigation. However, when we acquire undeveloped properties, as is common industry practice, we usually conduct little or no investigation of title other than a preliminary review of local mineral records. We do conduct title investigations and, in most cases, obtain a title opinion of local counsel before we begin drilling operations. We believe that the methods we utilize for investigating title prior to acquiring any property are consistent with practices customary in the oil and natural gas industry and that our practices are adequately designed to enable us to acquire good title to properties. However, some title risks cannot be avoided, despite the use of customary industry practices.

Our properties are generally burdened by:

•: customary royalty and overriding royalty interests;
•: liens incident to operating agreements; and
•: liens for current taxes and other burdens and minor encumbrances, easements and restrictions.

We believe that none of these burdens either materially detract from the value of our properties or materially interfere with property used in the operation of our business. Substantially all of our properties are pledged as collateral under our U.S. and Canadian credit facilities (and will be pledged as collateral under these facilities as amended in connection with the Transactions). These properties and the properties acquired in the North Coast acquisition have been pledged as collateral under the amended and restated credit facilities.

Legal Proceedings

We are from time to time involved in litigation incidental to the conduct of our business. We believe that no litigation currently pending against us, if adversely determined, would have a material adverse effect on our consolidated financial position or results of operations.

NORTH COAST ACQUISITION

On November 26, 2003, we entered into the North Coast Acquisition Agreement, as subsequently amended and restated, to acquire all of the issued and outstanding shares of North Coast common stock pursuant to a tender offer and a merger. On December 5, 2003, we commenced the tender offer for the North Coast shares at a purchase price of $10.75 per share or an aggregate of $167.8 million on a fully-diluted basis. The offer expired at 12:00 midnight, New York City time, on January 23, 2004.

Our obligation to accept for payment the shares of North Coast tendered pursuant to the tender offer was subject to the satisfactory tender of shares aggregating at least 90% of the total outstanding shares on a fully-diluted basis. Approximately 96.8% of the total number of outstanding shares of North Coast were ultimately tendered. As a result, on January 27, 2004, NCE Acquisition, Inc., our wholly-owned subsidiary, merged with and into North Coast pursuant to a short form merger under Delaware law and North Coast continued as the surviving corporation.

The parties made customary representations and warranties to each other. Except with respect to certain tax matters, the representations, obligations and pre-closing agreements made by the parties in the North Coast Acquisition Agreement did not survive the closing of the merger and we will not be indemnified for any breaches of the agreement.

We have agreed with Nuon Energy & Water that we will make a joint election to have the transactions contemplated by the North Coast Acquisition Agreement, including the tender offer and merger, taxed pursuant to an election under Section 338(h)(10) of the Code and any analogous provisions of applicable state, local and foreign tax law. By making the election, the transaction would be treated as an asset sale by North Coast (rather than a stock sale) which would allow us to step-up the tax basis in the North Coast assets we acquire in the transaction. Nuon Energy & Water has agreed to pay any federal, state and local taxes attributable to making such an election and will indemnify us for such tax liability. Nuon Energy & Water has entered into an escrow agreement to fund the payment of the full amount of the estimated tax liability attributable to such an election. The parties have agreed to cooperate with each other to determine the amount of the estimated tax liability attributable to the election and to ensure that the appropriate tax returns are filed.

We are responsible for, and have agreed to indemnify Nuon Energy & Water for, all taxes attributable to North Coast and its subsidiaries, NCE Acquisition, Inc. and EXCO Resources, Inc. The parties have agreed to cooperate with each other to determine the amount of the estimated tax liability of North Coast and its subsidiaries and to ensure that the appropriate tax returns are filed.

Nuon Energy & Water is responsible for, and has agreed to indemnify us for, all taxes attributable to Nuon Energy & Water and any of its affiliates other than North Coast and its subsidiaries, including, but not limited to, any liability imposed on North Coast and its subsidiaries due to their inclusion in Nuon Energy & Water's consolidated, combined or unitary tax group in 2003 and 2004. The parties have agreed to cooperate with each other to determine the amount of the estimated tax liability of Nuon Energy & Water and any of its affiliates other than North Coast and its subsidiaries and to ensure that the appropriate tax returns are filed.

Nuon Energy & Water's parent, n.v. NUON, a Dutch company with limited liability, has entered into an unconditional, unsecured guaranty agreement with us to guaranty Nuon Energy & Water's performance of its obligations under the North Coast Acquisition Agreement (specifically the tax indemnification provisions), the stock tender agreement and the escrow agreement.

MANAGEMENT

Cerberus Capital Management, L.P., a Delaware limited partnership, or Cerberus, is a New York investment management firm, which together with its affiliates, has in excess of $12.0 billion of equity capital under management. Entities controlled by Cerberus hold 100% of the issued and outstanding equity of EXCO Acquisition L.L.C., which in turn owns approximately 60% of the Class A equity of EXCO Holdings, which in turn holds 100% of the issued and outstanding equity of EXCO.

The principal executive offices of Cerberus are located at 299 Park Avenue, Floors 21-23, New York, New York 10171, telephone (212) 891-2100.

During the last five years, to the best knowledge of Cerberus, none of its current managing directors or managing members has been convicted in a criminal proceeding (excluding traffic violations or similar misdemeanors) or has been a party to any judicial or administrative proceeding that resulted in a judgment, decree or final order enjoining further violations of, or prohibiting activities subject to, federal or state securities laws, or a finding of any violation of such laws. All current managing directors and managing members of Cerberus are U.S. citizens.

Cerberus has the right to appoint a majority of the board of directors of EXCO pursuant to the Stockholders' Agreement among EXCO Holdings, Cerberus, other institutional investors and our stockholders, dated July 29, 2003 (the "Stockholders' Agreement"). Pursuant to the Stockholders' Agreement and so long as it is in effect, the following persons shall be elected to our board at each election of directors:

•: the Managing Member of EXCO Investors, LLC or, if EXCO Investors, LLC shall have dissolved or liquidated, the Chief Executive Officer of EXCO Holdings;
•: two representatives designated by holders of a majority of shares of our Class A Common Stock owned by Cerberus (the "Cerberus Directors") from time to time for so long as Cerberus owns at least 20% of the issued and outstanding shares of our common stock, or, for so long as Cerberus owns at least 10% but less than 20% of the issued and outstanding shares of our common stock, one Cerberus Director;provided, that the number of Cerberus Directors shall be increased by a number equal to the number of directors that the institutional investors shall at any time be entitled to appoint below; and
•: one representative designated by each institutional investor for so long as such institutional investor and their affiliates own at least 70% of such number of shares of our Class A Common Stock purchased by such institutional investor as of July 29, 2003 (the "Institutional Investor Directors");provided that in no event shall institutional investors be permitted to designate more than three Institutional Investor Directors in the aggregate;provided,further that no transferee of any institutional investor shall have any rights with respect to, among other things, the election or appointment of our board of directors under the Stockholders' Agreement.

The executive officers and directors of EXCO are as follows:

Name	Age	Position
Douglas H. Miller	56	Chairman and Chief Executive Officer
T. W. Eubank	61	Director, President and Treasurer
J. Douglas Ramsey, Ph.D.	43	Director, Vice President and Chief Financial Officer
Charles R. Evans	50	Vice President and Chief Operating Officer
Richard E. Miller	50	Director, Vice President, General Counsel and Secretary
J. David Choisser, CPA	53	Vice President and Chief Accounting Officer
Lenard Tessler	51	Director

Douglas H. Miller, 56, became our Chairman and Chief Executive Officer in December 1997. Mr. Miller also serves as Chairman and Chief Executive Officer of EXCO Holdings. Mr. Miller was Chairman of the Board and Chief Executive Officer of Coda Energy, Inc., an independent oil and natural gas company, from October 1989 until November 1997 and served as a director of Coda from 1987 until November 1997.

T. W. Eubank, 61, became our President, Treasurer and a director in December 1997. Mr. Eubank also serves as President and Treasurer of EXCO Holdings. Mr. Eubank was a consultant to various private companies from February 1996 to December 1997. Mr. Eubank served as President of Coda from March 1985 until February 1996. He was a director of Coda from 1981 until February 1996.

J. Douglas Ramsey, Ph.D., 43, became our Chief Financial Officer and a Vice President in December 1997. Dr. Ramsey has been one of our directors since March 1998. Dr. Ramsey also serves as Chief Financial Officer of EXCO Holdings. Dr. Ramsey most recently was Financial Planning Manager of Coda and worked in various capacities for Coda from 1992 until 1997. Dr. Ramsey also taught finance at Southern Methodist University.

Charles R. Evans, 50, joined us in February 1998, became a Vice President in March 1998 and was named our Chief Operating Officer in December 2000. Mr. Evans graduated from Oklahoma University with a B.S. degree in Petroleum Engineering in 1976. After working for Sun Oil Co., he joined TXO Production Corp. in 1979 and was appointed Vice President of Engineering and Evaluation in 1989. In 1990, he was named Vice President of Engineering and Project Development for Delhi Gas Pipeline Corporation, a natural gas gathering, processing and marketing company. Mr. Evans served as Director—Environmental Affairs and Safety for Delhi until December 1997.

Richard E. Miller, 50, became our General Counsel, General Land Manager and Secretary in December 1997, became a Vice President in July 2000 and became a director in July 2003. Mr. Miller was a senior partner and head of the Energy Section of Gardere & Wynne, L.L.P., a Dallas based law firm, from December 1991 to September 1994. Mr. Miller practiced law as a sole practitioner from September 1994 to December 1997.

J. David Choisser, CPA, 53, joined us in October 2001 and became our Chief Accounting Officer in November 2001 and a Vice President in February 2002. He began his career in 1972 with Deloitte Haskins & Sells (now Deloitte & Touche). During the past 25 years, he has served in various financial and accounting management capacities with several energy and energy-related companies, including Delhi Gas Pipeline Corporation, Coda Energy, Inc., Belco Oil & Gas Corp. and The Meridian Resource Corporation. He most recently served as Vice President—Finance of Noble Denton & Associates, Inc., an offshore engineering and marine consulting company.

Lenard Tessler, 51, became one of our directors in July 2003. Mr. Tessler also serves as a director of EXCO Holdings. Mr. Tessler is a Managing Director of Cerberus, which he joined in May 2001. Prior to joining Cerberus, he was a founding partner of TGV Partners, a private investment partnership formed in April 1990. Mr. Tessler served as Chairman of the Board of Empire Kosher Poultry from 1994 to 1997, after serving as its President and Chief Executive Officer from 1992 to 1994.

The executive officers and directors of EXCO Holdings are as follows:

Name	Age	Position
Douglas H. Miller*	56	Chairman and Chief Executive Officer
T. W. Eubank*	61	President and Treasurer
J. Douglas Ramsey, Ph.D.*	43	Chief Financial Officer
Jeffrey D. Benjamin	42	Director
Vincent J. Cebula	40	Director
Robert Davenport	37	Director
Mark Neporent	46	Director
Robert H. Niehaus	48	Director
Jeffrey Serota	37	Director
Lenard Tessler	51	Director
Alexander Wolf	29	Director

*: See biography set forth above.

Jeffrey D. Benjamin, 42, is a director of EXCO Holdings. Mr. Benjamin served as a director of EXCO from August 1998 until July 2003. Mr. Benjamin has been a senior advisor to Apollo Management, LP since September 2002. He had previously been a managing director of Libra Securities LLC, an investment banking firm, since January 2002 and served in various capacities, including co-chief executive officer of Libra Securities and its predecessors since May 1998. Mr. Benjamin is also a director of McLeod USA Incorporated, Dade Behring Holdings Inc., Chiquita Brands International, Inc. and NTL Incorporated.

Vincent J. Cebula, 40, is a director of EXCO Holdings. For the past five years, Mr. Cebula has been a Managing Director of Oaktree Capital Management, LLC. Mr. Cebula is a director of several private companies.

Robert Davenport, 37, is a director of EXCO Holdings. For the past five years, Mr. Davenport has been a Managing Director of Cerberus and its affiliates.

Mark Neporent, 46, is a director of EXCO Holdings. For the past five years, Mr. Neporent has been the Chief Operating Officer and Managing Director for Cerberus and its affiliates.

Robert H. Niehaus, 48, is the Chairman and Managing Partner of Greenhill Capital Partners, LLC, a private equity investment firm, and a Managing Director of Greenhill & Co., LLC. Prior to joining Greenhill in January 2000 to start its private equity business, Mr. Niehaus was a Managing Director in Morgan Stanley's private equity investment department from 1990 to 1999. Mr. Niehaus is a director of the American Italian Pasta Company, Global Signal Inc., Waterford Wedgewood plc and several private companies.

Jeffrey Serota, 37, is a director of EXCO Holdings. For the past five years, Mr. Serota has been a Managing Director of Ares Management, LLC and its related entities.

Lenard Tessler, 51, is a director of EXCO Holdings. Mr. Tessler also serves as a director of EXCO. Mr. Tessler is a Managing Director of Cerberus, which he joined in May 2001. Prior to joining Cerberus, he was a founding partner of TGV Partners, a private investment partnership formed in April 1990. Mr. Tessler served as Chairman of the Board of Empire Kosher Poultry from 1994 to 1997, after serving as its President and Chief Executive Officer from 1992 to 1994.

Alexander Wolf, 29, is a director of EXCO Holdings. Mr. Wolf is a Vice President of Cerberus, which he joined in December 2001. From 1999 through 2001, Mr. Wolf attended the Stanford University Graduate School of Business, from which he obtained an MBA in 2001. From 1997 through 1999, Mr. Wolf was an Associate at Ares Management.

Committees of the Board of Directors

We are a wholly-owned subsidiary of EXCO Holdings, which has an audit committee and a compensation committee. See "Change of Control Transaction" for more information regarding our relationship with EXCO Holdings. Our board of directors has not appointed any committees. As a result, EXCO Holdings establishes our compensation policies and the compensation and benefits of our officers. As long as Cerberus has the right to appoint a majority of our board of directors pursuant to the Stockholders' Agreement, Cerberus will have control over the appointment of our board committees. In addition, although we do not have an audit committee, we believe that our board of directors, taken as a whole, have the financial, accounting and other relevant education and experience necessary to qualify as audit committee financial experts under Item 401(h) of Regulation S-K.

Compensation of Directors

Directors will be reimbursed for reasonable out-of-pocket expenses incurred in connection with their attendance at meetings of the board of directors and committee meetings. We pay no additional remuneration to our employees or to executives of our affiliates for serving as directors.

Executive Compensation

Summary Compensation Table

The following table provides compensation information for the fiscal years 2001, 2002 and 2003 for EXCO's Chief Executive Officer, Douglas H. Miller, and the four most highly compensated executive officers other than Mr. D. H. Miller: T. W. Eubank, J. Douglas Ramsey, Richard E. Miller and Charles R. Evans.

								Long-Term Compensation Awards
		Annual Compensation						Long-Term Compensation Awards
		Annual Compensation						Common Stock Underlying Options
Name and Principal Position	Fiscal Year	Salary		Bonus		Other Annual Compensation		Common Stock Underlying Options	All Other Compensation
		($)		($)		($)		(# of shares)	($)(1)
Douglas H. Miller Chairman and Chief Executive Officer	2003 2002 2001	$ $ $	431,250 300,000 300,000	$ $ $	291,245 30,000 30,000	$ $ $	— — —	— — 30,000	$ $ $	14,257,044 9,600 6,300
T. W. Eubank President and Treasurer	2003 2002 2001	$ $ $	275,000 200,000 200,000	$ $ $	80,000 20,000 20,000	$ $ $	— — —	— — 20,000	$ $ $	4,006,445 8,800 6,300
J. Douglas Ramsey, Ph.D. Vice President and Chief Financial Officer	2003 2002 2001	$ $ $	168,750 150,000 150,000	$ $ $	43,750 15,000 15,000	$ $ $	— — —	— — 15,000	$ $ $	2,519,270 8,800 6,300
Richard E. Miller Vice President Secretary and General Counsel	2003 2002 2001	$ $ $	168,750 150,000 150,000	$ $ $	43,750 15,000 15,000	$ $ $	— — —	— — 15,000	$ $ $	863,021 8,800 6,300
Charles R. Evans Vice President and Chief Operating Officer	2003 2002 2001	$ $ $	225,000 150,000 150,000	$ $ $	65,000 15,000 15,000	$ $ $	— — —	— — 15,000	$ $ $	1,037,080 8,800 6,300

(1): Includes (i) the gross cash amounts received prior to any reinvestment upon completion of the going private transaction and (ii) EXCO's matching contributions under EXCO's 401(k) plan.

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The compensation described in this table does not include medical, group life insurance or other benefits that are available generally to all of EXCO's salaried employees. It also does not include certain perquisites and other personal benefits, securities or property received by these executive officers that are not material in amount.

Option Grants of Common Stock in Fiscal 2003

We did not grant any stock options to our named executive officers during the fiscal year ended December 31, 2003.

Option Exercises in Fiscal Year 2003 and Value at Fiscal Year End 2003

The following table shows the number of shares of common stock acquired upon exercise of stock options, or, if no shares were received, the number of securities with respect to which stock options were exercised and the aggregate dollar value realized upon such exercise during fiscal 2003. This table also shows the number of shares of common stock, if any, covered by both exercisable and non-exercisable stock options held by Messrs. D. H. Miller, Eubank, Ramsey, R. E. Miller, and Evans as of December 31, 2003, and the value on that date of their "in-the-money" common stock options.

	Shares Acquired on Exercise	Value Realized (Loss)	Number of Securities Underlying Unexercised Options at Fiscal Year-End		Value of unexercised In-the-Money Options at Fiscal Year-End
	(#)(1)	($)	(#)		($)
Name			Exercisable	Unexercisable	Exercisable	Unexercisable
Douglas H. Miller	—	2,171,875	—	—	—	—
T. W. Eubank	50,278	1,226,875	—	—	—	—
J. Douglas Ramsey, Ph.D.	64,133	1,203,750	—	—	—	—
Richard E. Miller	49,141	594,690	—	—	—	—
Charles R. Evans	68,974	795,972	—	—	—	—

(1): No shares or other securities were acquired upon exercise of non-qualified stock options because to the extent the holder owned unexercised options to purchase our common stock prior to the effective time of the going private transaction, the holder was entitled to receive, upon the completion of the going private transaction, cash for each non-qualified stock option they owned in an amount equal to the amount by which $18.00 exceeded the exercise price of the option, reduced by applicable withholding and employment taxes. All incentive stock options the holder owned where the exercise price of the option was less than $18.00 were exercised. The common stock received upon exercise was then sold for $18.00 per share upon completion of the going private transaction and/or exchanged for Class A common stock of EXCO Holdings Inc.

Severance Plan

In August 2002, our board of directors concluded that we should establish a severance plan for our employees. The severance plan generally applies to persons who were full-time employees, including our executive officers, on the date we adopted the severance plan. Under the severance plan, eligible employees are entitled to severance pay following a "termination of employment" if the termination of employment occurs on the date of, or within six months after, a change of control of us. A termination of employment includes an affirmative discharge from employment by us other than for "cause" or an eligible employee's voluntary termination of employment for "good reason."

A "change of control" occurs if (i) we are merged or consolidated into or with another entity and, as a result of the merger or consolidation, less than a majority of the combined voting power of the outstanding securities of the resulting entity after the merger or transaction is held by the holders of

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our voting stock immediately prior to the merger or transaction, (ii) if we sell or transfer all or substantially all of our assets to any person or entity and less than a majority of the combined voting power of the outstanding securities of the acquiring person or entity after the sale or transfer is held by the holders of our voting stock immediately prior to the sale or transfer, or (iii) if, during any two consecutive years, individuals who were serving on our board of directors at the beginning of the two-year period, together with any new board members whose election or nomination was approved by a majority of the directors who were serving at the beginning of the two-year period or whose election or nomination was previously so approved, cease to constitute a majority of our board directors then in office.

The maximum amount payable under the severance plan is approximately $4.4 million. The existence of the severance plan could serve to discourage potential third party buyers because of the increased costs that might have to be paid under the severance plan in the event of an acquisition by a third party.

However, under the severance plan, a change of control does not include a merger, consolidation or sale of assets between or among us and a group of investors that includes Mr. D. H. Miller, or any member of the group or any of their respective affiliates or associates. Therefore, the going private transaction did not constitute a change of control under the severance plan and any termination of employment of an eligible employee after the going private transaction will not result in severance payments to the eligible employee.

Employee Bonus Retention Plan

Our board of directors and the board of directors of Addison Energy Inc., our wholly-owned subsidiary, adopted identical employee bonus retention plans effective upon the completion of the going private transaction in order to provide certain employees with an incentive to remain employed with us and Addison Energy Inc. after the going private transaction. The employee bonus retention plan is governed, managed and controlled by the board of directors of each respective company. Under the employee bonus retention plan, participants who remain employed with the company will receive, until the fourth anniversary of the closing date of the going private transaction a portion of their total retention bonus after each three month anniversary of the closing date of the going private transaction and a lump sum payment of all unpaid retention bonus payments upon a change of control of EXCO Holdings Inc., except for a change of control that may occur upon an initial public offering of any class of equity securities of EXCO Holdings Inc. The participants in the plan agreed to customary confidentiality and nonsolicitation provisions. Messrs. Miller and Eubank, together with other of our continuing shareholders, agreed to customary non-compete provisions in connection with the employee bonus retention plan. The executive officers who are continuing shareholders will receive the following annual payments until the fourth anniversary of the closing date of the going private transaction: Douglas H. Miller—$820,000; T.W. Eubank—$100,000; J. Douglas Ramsey—$40,000; J. David Choisser—$60,000; Charles R. Evans—$80,000; Richard E. Miller—$40,000. Currently, none of Messrs. D. H. Miller, Eubank, Ramsey, R.E. Miller, Evans and Choisser is a party to an employment agreement.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS

We own 100% of the outstanding capital stock of all of our subsidiary co-registrants. EXCO Holdings owns 100% of our capital stock.

The following table sets forth as of April 15, 2004 the number and percentage of shares of common stock of EXCO Holdings beneficially owned by (i) each person known by us to beneficially own more than 5% of the outstanding shares of EXCO Holdings common stock, (ii) each of our directors, (iii) each named executive officer and (iv) all our directors and executive officers as a group.

Notwithstanding the beneficial ownership of common stock presented below, a stockholders' agreement governs the stockholders' exercise of their voting rights with respect to election of directors of EXCO Holdings and certain other material events. EXCO Holdings, as our sole stockholder, has the right to elect our board of directors. For so long as EXCO Acquisition L.L.C., an affiliate of Cerberus, owns at least 20% of the issued and outstanding shares of EXCO Holdings, it has the right to elect a majority of the board of directors of EXCO Holdings. See "Risk Factors—Our principal stockholder is in a position to affect our ongoing operations, corporate transactions and other matters." The parties agreed in the stockholders' agreement that the managing member of EXCO Investors, LLC, Douglas H. Miller or any subsequent managing member as elected pursuant to the Operating Agreement of EXCO Investors, LLC, would be elected to the board of directors of EXCO Holdings at each election of directors during the term of the stockholders' agreement. See "Change of Control Transaction."

Except as otherwise indicated in a footnote, each of the beneficial owners listed has, to our knowledge, sole voting and investment power with respect to the indicated shares of common stock. Unless otherwise indicated in a footnote, the address for each individual listed below is c/o EXCO Resources, Inc., 12377 Merit Drive, Suite 1700 Dallas, Texas 75251.

	Shares of Common Stock
Name and Address	Shares of Common Stock		Percent of Common Stock(1)
Name and Address	Class A	Class B	Percent of Common Stock(1)
Cerberus Capital Management, L.P.(2) 450 Park Avenue, 28^th Floor New York, New York 10022	71,000,000	—	55.5	%
Ares Corporate Opportunities Fund, L.P. 1999 Avenue of the Stars, Suite 1900 Los Angeles, California	6,666,667	—	5.2	%
OCM Principal Opportunities Fund II, L.P. 1301 Avenue of the Americas, 34^th Floor New York, New York 10019	6,666,667	—	5.2	%
Greenhill Capital Partners, L.P. Greenhill Capital Partners (Cayman), L.P. Greenhill Capital Partners (Executives), L.P. Greenhill Capital, L.P. 300 Park Avenue, 23^rd Floor New York, New York 10022	6,666,667	—	5.2	%
EXCO Investors, LLC	14,000,000	—	10.9	%
Douglas H. Miller(3)	3,690,000	5,314,815	7.0	%
T.W. Eubank(4)	450,000	648,148	*
J. Douglas Ramsey, Ph.D.(5)	180,000	259,259	*
Charles R. Evans(6)	360,000	518,518	*
Richard E. Miller(7)	180,000	259,259	*
Lenard Tessler(8)	—	—	—
All directors and executive officers as a group (7 people)	5,130,000	7,388,888	9.8	%

*: Indicates less than 1% of our common stock.

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(1): Represents the aggregate ownership of the Class A and Class B Common Stock of EXCO Holdings.
(2): Cerberus Capital Management, L.P., a Delaware limited partnership, and/or entities directly or indirectly controlled by it and/or its affiliates, or Cerberus, own 100% of the issued and outstanding equity securities of EXCO Acquisition L.L.C., which in turn owns approximately 55.5% of the Class A common stock of EXCO Holdings. Cerberus is an investment management firm, which, together with its affiliates, has in excess of $11.0 billion of equity capital under management.

Stephen A. Feinberg, through one or more intermediate entities, exercises ultimate discretion and control over Cerberus. During the last five years, neither Cerberus nor Stephen A. Feinberg have been convicted in a criminal proceeding (excluding traffic violations or similar misdemeanors) or has been a party to any judicial or administrative proceeding that resulted in a judgment, decree or final order enjoining further violations of, or prohibiting activities subject to, federal or state securities laws, or a finding of any violation of such laws. Stephen A. Feinberg is a U.S. citizen.

(3): Mr. Doug Miller is a Director and the Chief Executive Officer of EXCO Holdings, EXCO, North Coast Energy, Inc. and North Coast Energy Eastern, Inc.
(4): Mr. Eubank is a Director of EXCO, Taurus Acquisition, Inc., North Coast Energy, Inc. and North Coast Energy Eastern, Inc. and is a Manager of EXCO Investment I, LLC. Mr. Eubank holds the following executive offices: President and Secretary of EXCO Holdings, President and Treasurer of EXCO, President of Taurus Acquisition, Inc., President of EXCO Investment I, LLC and President of EXCO Investment II, LLC.
(5): Dr. Ramsey holds the following executive offices: Chief Financial Officer of EXCO Holdings, Vice President and Chief Financial Officer of EXCO, Vice President of Taurus Acquisition, Inc., Vice President and Chief Financial Officer of EXCO Investment I, LLC, Vice President and Chief Financial Officer of EXCO Investment II, LLC, Vice President of North Coast Energy, Inc. and Vice President of North Coast Energy Eastern, Inc. Dr. Ramsey's Class A and Class B common stock of EXCO Holdings was assigned to a limited partnership in which Dr. Ramsey holds a 98.0% limited partnership interest.
(6): Mr. Evans holds the following executive offices: Vice President and Chief Operating Officer of EXCO, Vice President of North Coast Energy, Inc. and Vice President of North Coast Energy Eastern, Inc.
(7): Mr. Richard Miller holds the following executive offices: Vice President, General Counsel and Secretary of EXCO, Vice President and Secretary of Taurus Acquisition, Inc., Vice President and Secretary of EXCO Investment I, LLC, Vice President and Secretary of EXCO Investment II, LLC, Vice President and Assistant Secretary of North Coast Energy, Inc. and Vice President and Assistant Secretary of North Coast Energy Eastern, Inc.
(8): Mr. Tessler is a Director of EXCO Holdings and EXCO. Mr. Tessler is a Managing Director of Cerberus Capital Management, L.P.

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CHANGE OF CONTROL TRANSACTION

The Acquisition

On March 11, 2003, we entered into an Agreement and Plan of Merger providing for the merger of ER Acquisition, Inc., a wholly-owned subsidiary of EXCO Holdings into EXCO. This transaction is referred to in this prospectus as the "going private transaction." EXCO Holdings was formed by our chairman and chief executive officer, Douglas H. Miller, and his buyout group for the purpose of completing the going private transaction, which closed on July 29, 2003. In the going private transaction, each outstanding share of our common stock, other than shares held by EXCO Holdings and its affiliates, was converted into the right to receive $18.00 in cash per share.

The Financing

The buyout was funded by borrowings of approximately $53.6 million under our existing credit facilities and approximately $172.0 million of equity. The equity capital for the going private transaction was provided by $106.5 million from investment funds and accounts managed by Cerberus Capital Management, L.P., or Cerberus, $12.4 million from our management and $55.0 million from institutional and other investors. Cerberus is a New York based investment management firm that, with its affiliates, manages investment funds and accounts in excess of $12.0 billion in equity capital.

Ownership Structure

The voting capital stock of EXCO Holdings is owned by:

•: members of our management and other of our employees, who own in the aggregate approximately 16% of the voting capital stock of EXCO Holdings;
•: EXCO Investors, LLC, a limited liability company formed prior to the merger for the purpose of holding capital stock of EXCO Holdings, the members of which include business acquaintances of Mr. Miller, owns approximately 11% of the voting capital stock of EXCO Holdings (the vote of which shares is controlled by Mr. Miller);
•: affiliates of Cerberus, which own in the aggregate approximately 55% of the voting capital stock of EXCO Holdings; and
•: other institutional investors, which own in the aggregate approximately 18% of the voting capital stock of EXCO Holdings.

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The following chart illustrates our ownership structure after the completion of the going private transaction:

The Structure of the Transaction

As a condition to the sale of Class A common stock of EXCO Holdings to affiliates of Cerberus, EXCO Investors, LLC, Mr. Miller, Mr. Eubank and the other continuing shareholders agreed to purchase shares of capital stock of EXCO Holdings pursuant to a management purchase agreement. With the exception of EXCO Investors, LLC, each purchaser of shares of Class A common stock and Class B common stock under the management purchase agreement was required to enter into a stock repurchase agreement with EXCO Holdings. Shares of common stock of EXCO Holdings acquired by Mr. Miller and Mr. Eubank pursuant to the management purchase agreement may be sold or transferred only in accordance with the stock repurchase agreement and the stockholders' agreement. The stock repurchase agreement permits EXCO Holdings to repurchase from Mr. Miller or Mr. Eubank any or all of the common stock they own of EXCO Holdings at any time within 90 days following Mr. Miller's or Mr. Eubank's (i) death; (ii) divorce in which beneficial ownership of the common stock is acquired by such stockholder's spouse; (iii) termination of employment because of disability; (iv) resignation of employment; (v) termination of employment with or without cause; or (vi) ceasing to remain in the employ of EXCO Holdings for any other reason not included in (i), (ii), (iii), (iv) or (v) above. In the stockholders' agreement, if a stockholder of EXCO Holdings, other than Cerberus, Mr. Miller or Mr. Eubank, wishes to sell or transfer any shares of common stock of EXCO Holdings to a third party, such stockholder must (i) first offer to sell their shares to EXCO Holdings and, if EXCO Holdings declines to purchase all of the shares, then (ii) offer the shares to Cerberus, Mr. Miller and Mr. Eubank. In addition, in the stockholders' agreement Cerberus, Mr. Miller and Mr. Eubank agreed to subject their shares of common stock of EXCO Holdings to a right of first offer in the event that one of them attempts to sell their shares to a third party. Cerberus, Mr. Miller and Mr. Eubank were also granted a right of co-sale in the event that they do not exercise their respective rights of first refusal or if the right of first offer is not consummated. Further, the parties agreed in the stockholders' agreement that the managing member of EXCO Investors, LLC would be elected to the board of directors of EXCO Holdings at each election of directors during the term of the stockholders' agreement. The managing member of EXCO Investors, LLC is Mr. Miller.

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The EXCO Merger Agreement also provided that EXCO Holdings and we will indemnify each of our present and former directors and officers until the later of six years after the effective time of the merger or the expiration of any statute of limitations applicable to the claim under which indemnification is sought against liabilities for their actions or omissions as directors or officers before the effective time of the merger. The EXCO Merger Agreement further provides that for a period of six years after the effective time of the merger, the surviving corporation will provide to our directors and officers liability insurance protection with the same coverage and in the same amount as and on terms no less favorable to such individuals than that provided by our insurance policies in effect immediately prior to the merger. The persons benefiting from the insurance provisions of the EXCO Merger Agreement include all persons who served as our directors and executive officers during the period from August 1, 2002 until the effective time of the merger.

Concurrently with the closing of transactions contemplated by the EXCO Merger Agreement, the affiliates of Cerberus, the non-Cerberus institutional investors, EXCO Investors, LLC, Mr. Miller, Mr. Eubank and other continuing shareholders entered into a registration rights agreement with EXCO Holdings. Under the registration rights agreement, EXCO Holdings granted to its holders of Class A common stock certain rights to register for public sale the shares of Class A common stock owned by the parties to the registration rights agreement.

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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Historically, we have reimbursed Mr. Miller for our use of his jet on corporate business. In 2003 the reimbursement totaled approximately $100,000.

For a description of additional transactions we engaged in with our management during 2003 please see the description of our going private transaction in "Change of Control Transaction" and "Management."

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DESCRIPTION OF CERTAIN INDEBTEDNESS

On January 27, 2004, in accordance with a commitment letter we received from Bank One, NA and Credit Suisse First Boston, we amended our U.S. and Canadian credit agreements.

U.S. Credit Agreement. On January 27, 2004, the U.S. credit agreement was amended and restated to set the borrowing base at $120.0 million. The amendment also provided for an extension of the U.S. credit agreement maturity date to January 27, 2007. Upon the issuance of the old notes on April 13, 2004, the U.S. credit agreement borrowing base was reduced to $95.0 million. The borrowing base will be redetermined as of May 1, 2004 and each November 1 and May 1 thereafter. Borrowings under the amended and restated credit agreement are secured by a first lien mortgage providing a security interest in 90% of EXCO's U.S. oil and natural gas properties and at least 90% of North Coast's oil and natural gas properties. At our election, interest on borrowings may be (i) the greater of the administrative agent's prime rate or the federal funds effective rate plus 0.50% plus an applicable margin or (ii) LIBOR (London InterBank Offered Rate) plus an applicable margin. At April 15, 2004, the six month LIBOR rate was 1.29%, which would result in an interest rate of approximately 2.54% on any new indebtedness we may incur under the amended and restated U.S. credit agreement.

Canadian Credit Agreement. On January 27, 2004, the Canadian credit agreement was amended and restated to provide for an extension of the Canadian credit agreement maturity date to January 27, 2007. The Canadian borrowing base remained at its previous level of $105.0 million. The borrowing base will be redetermined as of May 1, 2004 and each November 1 and May 1 thereafter. Borrowings under the amended and restated credit agreement are secured by a first lien mortgage providing a security interest in 90% of our Canadian oil and natural gas properties. At our election, interest on borrowings may be (i) the Canadian prime rate plus an applicable margin or (ii) the Banker's Acceptance rate plus an applicable margin. At April 15, 2004, the six month Banker's Acceptance rate was 2.11%, which would result in an interest rate of approximately 3.36% on any new indebtedness we incur under the amended and restated Canadian credit agreement.

Financial covenants and ratios. Our U.S. and Canadian credit agreements, dated January 27, 2004, contain financial covenants and other restrictions which require that we:

•: maintain a ratio of our consolidated current assets to consolidated current liabilities (as defined under our credit agreements) of at least 1.0 to 1.0 at the end of any fiscal quarter;
•: not permit our ratio of consolidated funded debt to consolidated EBITDA (as defined under our credit agreements) to be greater than (i) 4.35 to 1.00 at the end of each fiscal quarter ending prior to June 30, 2004 and (ii) 4.00 to 1.00 on June 30, 2004 and at the end of each fiscal quarter thereafter;
•: not permit our ratio of consolidated funded debt (other than the notes) to consolidated EBITDA (as defined under our credit agreements) to be greater than (i) 3.25 to 1.00 at the end of each fiscal quarter ending prior to June 30, 2004 and (ii) 3.00 to 1.00 on June 30, 2004 and at the end of each fiscal quarter thereafter; and
•: not permit our ratio of consolidated EBITDA (as defined under our credit agreements) to consolidated interest expense to be less than 2.50 to 1.00 at the end of each fiscal quarter.

7¹/4% Senior Notes Due 2011. On January 20, 2004, we issued $350.0 million principal amount of our 7¹/4% Senior Notes Due 2011 pursuant to Rule 144A and Regulation S under the Securities Act at a price of 100% of the principal amount. On April 13, 2004, we issued an additional $100.0 million principal amount of our 7¹/4% Senior Notes Due 2011 pursuant to Rule 144A at a price of 103.25% of the principal amount having the same terms and governed by the same Indenture as the notes issued on January 20, 2004. These 7¹/4% Senior Notes issued on January 20, 2004 and April 13, 2004 collectively constitute the old notes. The old notes were issued under our Indenture, dated January 20,

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2004, as supplemented by the First Supplemental Indenture, dated January 27, 2004, among EXCO, certain of its subsidiaries and Wilmington Trust Company, as Trustee. We used the proceeds from the sale of the old notes to fund the North Coast acquisition, repay the full amount of the senior term loan, repay substantially all of our U.S. and Canadian credit facilities and pay related fees and expenses incurred in connection with the Transactions. We have agreed to file this exchange offer registration statement or, under certain circumstances, a shelf registration statement, pursuant to registration rights agreements relating to the old notes. In the event we fail to comply with some of our obligations under the registration rights agreements relating to the old notes, we will pay additional interest on the old notes. We are currently offering to exchange up to $450.0 million aggregate principal amount of new 7¹/4% Senior Notes Due 2011, also referred to as the new notes, that have been registered under the Securities Act for an equal principal amount of old notes.

The old notes:

•: are senior obligations of EXCO secured by a second-priority security interest (subject to the limitation described under "Description of the New Notes—Share Pledges") in 65% of the Capital Stock of Addison and 100% of the Capital Stock of Taurus Acquisition, Inc. behind the first-priority security interest securing obligations relating to our indebtedness under the credit facilities;
•: are senior in right of payment to any of our future subordinated obligations;
•: are guaranteed by all of our current and some of our future domestic subsidiaries on a senior unsecured basis (except that the guarantee of Taurus Acquisition, Inc. is subordinated to its guarantee under the credit facilities); and
•: are subject to registration with the SEC pursuant to the registration rights agreements.

The old notes mature on January 15, 2011. Interest on the old notes accrue at a rate of 7¹/4% per annum and are payable semiannually in arrears on January 15 and July 15, commencing on July 15, 2004. We will make each interest payment to the holders of record of the old notes on the immediately preceding January 1 and July 1. We pay interest on overdue principal at 1% per annum in excess of the above rate and will pay interest on overdue installments of interest at such higher rate to the extent lawful. Interest on the new notes will accrue from the last interest payment date on which interest was paid on the old notes surrendered in exchange therefor, or, if no interest has been paid on such old notes, from January 20, 2004.

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DESCRIPTION OF THE NEW NOTES

EXCO Resources, Inc. will issue the new notes under an Indenture dated as of January 20, 2004, as supplemented by the First Supplemental Indenture dated as of January 27, 2004 (as so supplemented, the "Indenture") among itself, certain of its subsidiaries and Wilmington Trust Company, as Trustee.

The Company will issue the new notes under the Indenture. On January 20, 2004, EXCO issued $350.0 million aggregate principal amount of 7¹/4% Senior Notes Due 2011 under the Indenture. On April 13, 2004, EXCO issued an additional $100.0 million aggregate principal amount of 7¹/4% Senior Notes Due 2011 under the Indenture. The old notes issued on January 20, 2004 and the old notes issued on April 13, 2004 were treated as a single series under the Indenture, including for purposes of determining whether the required percentage of the holders of record has given approval or consent to an amendment or waiver or joined in directing the Trustee to take certain actions on behalf of all holders. The old notes issued April 13, 2004 represent approximately 22.2% of all the notes issued under the Indenture as of the date of this prospectus. The terms of the new notes include those stated in the Indenture and those made part of the Indenture by reference to the Trust Indenture Act. The Pledge Agreement referred to below under the caption "—Share Pledge" contains the terms of the security interests that will secure the new notes.

Certain terms used in this description are defined under the subheading "—Certain Definitions". In this description, the word "Company" refers only to EXCO Resources, Inc. and not to any of its subsidiaries.

The following description is only a summary of the material provisions of the Indenture, the Registration Rights Agreements, the Intercreditor Agreement and the Pledge Agreement. We urge you to read the Indenture, the Registration Rights Agreements, the Intercreditor Agreement and the Pledge Agreement because they, not this description, define your rights as holders of these new notes. Copies of these agreements are available as set forth under the heading "Where You Can Find More Information".

Brief Description of the New Notes

These new notes:

•: are senior obligations of the Company secured by a second-priority security interest (subject to the limitation described under "—Share Pledge") in 65% of the Capital Stock of Addison and 100% of the Capital Stock of Taurus Acquisition, Inc. behind the first-priority security interest securing Obligations relating to the Company's Indebtedness under the Credit Facilities;
•: are senior in right of payment to any future Subordinated Obligations of the Company;
•: are guaranteed by each Subsidiary Guarantor on a senior unsecured basis (except that the guarantee of Taurus Acquisition, Inc. is subordinated to its guarantee under the Credit Facilities); and
•: have been registered under the Securities Act.

Principal, Maturity and Interest

The Company will issue up to a maximum aggregate principal amount of $450.0 million of new notes in this exchange offer in exchange for any and all of our old notes. The Company will issue the new notes in denominations of $1,000 and any integral multiple of $1,000. The new notes will mature on January 15, 2011. Subject to our compliance with the covenant described under the subheading "—Certain Covenants—Limitation on Indebtedness", we are entitled to, without the consent of the holders, issue more notes under the Indenture in an unlimited aggregate principal amount (the "Additional Notes"). The old notes issued on April 13, 2004 constitute the first issuance of Additional

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Notes under the Indenture. The new notes, any old notes not exchanged in the exchange offer and the Additional Notes will be treated as a single class for all purposes of the Indenture, including waivers, amendments, redemptions and offers to purchase. Unless the context otherwise requires, for all purposes of the Indenture and this "Description of the New Notes", references to the notes includes the old notes, the new notes and any Additional Notes actually issued.

Interest on these new notes will accrue at the rate of 7¹/4% per annum and will be payable semiannually in arrears on January 15 and July 15, commencing on July 15, 2004. We will make each interest payment to the holders of record of these new notes on the immediately preceding January 1 and July 1. We will pay interest on overdue principal at 1% per annum in excess of the above rate and will pay interest on overdue installments of interest at such higher rate to the extent lawful.

Interest on the new notes will accrue from the last interest payment date on which interest was paid on the old notes surrendered in exchange therefor, or, if no interest has been paid on such old notes, from January 20, 2004. Interest will be computed on the basis of a 360-day year comprised of twelve 30-day months.

Additional interest may accrue on the notes in certain circumstances pursuant to the Registration Rights Agreements.

Optional Redemption

Except as set forth below, we will not be entitled to redeem the notes at our option prior to their Stated Maturity.

At any time prior to January 15, 2007, we will be entitled, at our option, to redeem all, but not less than all, of the notes at a redemption price equal to 100% of the principal amount of the notes plus the Applicable Premium as of, and accrued and unpaid interest to, the redemption date (subject to the right of Holders on the relevant record date to receive interest due on the relevant interest payment date). Notice of such redemption must be mailed by first-class mail to each Holder's registered address, not less than 30 nor more than 60 days prior to the redemption date.

"Applicable Premium" means, with respect to a note at any redemption date, the greater of (i) 1.00% of the principal amount of such note and (ii) the excess of (A) the present value at such redemption date of (1) the redemption price of such note on January 15, 2007 (such redemption price being described in the penultimate paragraph of this "—Optional Redemption" section, exclusive of any accrued interest) plus (2) all required remaining scheduled interest payments due on such note through January 15, 2007, computed using a discount rate equal to the Adjusted Treasury Rate, over (B) the principal amount of such note on such redemption date.

"Adjusted Treasury Rate" means, with respect to any redemption date, (i) the yield, under the heading which represents the average for the immediately preceding week, appearing in the most recently published statistical release designated "H.15(519)" or any successor publication which is published weekly by the Board of Governors of the Federal Reserve System and which establishes yields on actively traded United States Treasury securities adjusted to constant maturity under the caption "Treasury Constant Maturities," for the maturity corresponding to the Comparable Treasury Issue (if no maturity is within three months before or after January 15, 2007, yields for the two published maturities most closely corresponding to the Comparable Treasury Issue shall be determined and the Adjusted Treasury Rate shall be interpolated or extrapolated from such yields on a straight line basis, rounding to the nearest month) or (ii) if such release (or any successor release) is not published during the week preceding the calculation date or does not contain such yields, the rate per year equal to the semi-annual equivalent yield to maturity of the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such redemption date, in each case calculated on the third Business Day immediately preceding the redemption date, plus 0.50%.

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"Comparable Treasury Issue" means the United States Treasury security selected by the Quotation Agent as having a maturity comparable to the remaining term from the redemption date to January 15, 2007, that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of a maturity most nearly equal to January 15, 2007.

"Comparable Treasury Price" means, with respect to any redemption date, if clause (ii) of the Adjusted Treasury Rate is applicable, the average of three, or such lesser number as is obtained by the Trustee, Reference Treasury Dealer Quotations for such redemption date.

"Quotation Agent" means the Reference Treasury Dealer selected by the Trustee after consultation with the Company.

"Reference Treasury Dealer" means Credit Suisse First Boston LLC and its successors and assigns, Banc One Capital Markets, Inc. and its successors and assigns and one other nationally recognized investment banking firm selected by the Company that is a primary U.S. Government securities dealer.

"Reference Treasury Dealer Quotations" means, with respect to each Reference Treasury Dealer and any redemption date, the average, as determined by the Trustee, of the bid and asked prices for the Comparable Treasury Issue, expressed in each case as a percentage of its principal amount, quoted in writing to the Trustee by such Reference Treasury Dealer at 5:00 p.m., New York City Time, on the third Business Day immediately preceding such redemption date.

On and after January 15, 2007, we will be entitled at our option to redeem all or a portion of these notes upon not less than 30 nor more than 60 days' notice, at the redemption prices (expressed in percentages of principal amount on the redemption date), plus accrued interest 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), if redeemed during the 12-month period commencing on January 15 of the years set forth below:

Period	Redemption Price
2007	105.438	%
2008	103.625	%
2009	101.813	%
2010 and thereafter	100.000	%

Prior to January 15, 2007, we may at our option on one or more occasions redeem notes (which includes Additional Notes, if any) in an aggregate principal amount of not to exceed 35% of the aggregate principal amount of the notes (which includes Additional Notes, if any) originally issued at a redemption price (expressed as a percentage of principal amount) of 107.25%, plus accrued and unpaid interest to the redemption date, with the net cash proceeds from one or more Public Equity Offerings (provided, however, that if the Public Equity Offering is an offering by Parent, a portion of the Net Cash Proceeds thereof equal to the amount required to redeem any such notes is contributed to the equity capital of the Company); provided, however, that

(1): at least 65% of such aggregate principal amount of notes (which includes the Additional Notes, if any) remains outstanding immediately after the occurrence of each such redemption (other than notes held, directly or indirectly, by the Company or its Affiliates); and
(2): each such redemption occurs within 90 days after the date of the related Public Equity Offering.

Selection and Notice of Redemption

If we are redeeming less than all the notes at any time, the Trustee will select notes on a pro rata basis, to the extent practicable.

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We will redeem notes of $1,000 or less in whole and not in part. We will cause notices of redemption to be mailed by first-class mail at least 30 but not more than 60 days before the redemption date to each holder of notes to be redeemed at its registered address.

If any note is to be redeemed in part only, the notice of redemption that relates to that note will state the portion of the principal amount thereof to be redeemed. We will issue another note in a principal amount equal to the unredeemed portion of the original note in the name of the holder upon cancelation of the original note. Notes called for redemption become due on the date fixed for redemption. On and after the redemption date, interest ceases to accrue on notes or portions of them called for redemption.

Mandatory Redemption; Offers to Purchase; Open Market Purchases

We are not required to make any mandatory redemption or sinking fund payments with respect to the new notes. However, under certain circumstances, we may be required to offer to purchase notes as described under the captions "—Change of Control", "—Permitted MLP Transaction" and "—Certain Covenants—Limitation on Sales of Assets and Subsidiary Stock". We may at any time and from time to time purchase notes in the open market or otherwise.

Share Pledge

The notes are secured by a second-priority security interest (subject to Specified Permitted Liens) on the collateral (the "Collateral"). The Collateral consists of 65% of the Capital Stock of Addison Energy Inc. and 100% of the Capital Stock of Taurus Acquisition, Inc. (subject to the limitation described in the next two sentences). Notwithstanding the foregoing, at no time will any shares of Capital Stock of such Subsidiaries constitute Collateral to the extent that at such time Rule 3-16 of Regulation S-X under the Securities Act requires (or is replaced with another rule or regulation or any other law, rule or regulation is adopted which would require) the filing with the SEC (or any other governmental agency) of separate financial statements of any Subsidiary of the Company as a result of the fact that such shares of Capital Stock secure the notes, but only to the extent and for so long as necessary to not be subject to such requirement. At such times, the Pledge Agreement may be amended or modified, without the consent of any Holder of notes, to the extent considered necessary to reflect the operation of the foregoing sentence.

The Company and the Trustee entered into a pledge agreement (the "Pledge Agreement") defining the terms of the security interests that secure the notes. These security interests secure the payment and performance when due of all of the Obligations of the Company under the notes, the Indenture and the Pledge Agreement, as provided in the Pledge Agreement. The Company completed on or prior to the Issue Date all filings and other similar actions required in connection with the perfection of such security interests.

The security interests securing the notes are second in priority (subject to Specified Permitted Liens) to any and all security interests on the Capital Stock of Addison Energy Inc. and Taurus Acquisition, Inc. at any time granted to secure the First Lien Obligations. The First Lien Obligations include Obligations relating to the Company's Indebtedness under the Credit Facilities and Obligations under any future Indebtedness that is Incurred by the Company pursuant to clause (b)(1) of the covenant described below under "—Certain Covenants—Limitation on Indebtedness" and that is secured by a Permitted Lien described in clause (7) of the definition thereof, as well as certain Hedging Obligations.

On the Issue Date, the Trustee, the Credit Agent (as defined in the Intercreditor Agreement), the Company and the Subsidiary Guarantors entered into the Intercreditor Agreement. The Credit Agent is initially the administrative agent under the Credit Agreement. Pursuant to the terms of the Intercreditor Agreement, prior to the discharge in full of the First Lien Obligations, the Credit Agent will determine the time and method by which the security interests in the Collateral will be enforced.

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The Trustee will not be permitted to enforce the security interests even if an Event of Default has occurred and the notes have been accelerated except (a) in any insolvency or liquidation proceeding, as necessary to file a claim or statement of interest with respect to the notes or (b) as necessary to take any action not adverse to the first-priority Liens in order to preserve or protect its rights in the second-priority Liens. After the discharge in full of the First Lien Obligations, the Trustee in accordance with the provisions of the Indenture and the Pledge Agreement will distribute all cash proceeds (after payment of the costs of enforcement and collateral administration) of the Collateral received by it under the Pledge Agreement for the ratable benefit of the Holders of the notes.

Whether prior to or after the discharge of the First Lien Obligations, the Company will be entitled to releases of the Collateral from the Liens securing the notes as described under "—Amendments and Waivers" below.

The second-priority security interests on all Collateral also will be released upon:

•: payment in full of the principal of, accrued and unpaid interest (including additional interest, if any) on the notes and all other Obligations under the Indenture and the Pledge Agreement that are due and payable at or prior to the time such principal, accrued and unpaid interest (including additional interest, if any) are paid or
•: a discharge of our obligations under the Indenture or a legal defeasance or covenant defeasance as described below under the headings "—Satisfaction and Discharge" and "—Defeasance."

The second-priority security interests on certain Collateral will be released upon:

•: to the extent permitted under the Indenture, the sale or other disposition (including by way of consolidation or merger) of any Subsidiary whose Capital Stock is pledged as Collateral under the Pledge Agreement to the MLP Subsidiary or following which such Subsidiary is no longer a Subsidiary;
•: the sale or other disposition (other than to the Company or a Restricted Subsidiary, but including to the MLP Subsidiary) of all or substantially all of the assets of any Subsidiary whose Capital Stock is pledged as Collateral under the Pledge Agreement;
•: as to Collateral that constitutes Net Available Cash from the sale of Collateral that has been offered to, but not accepted by, the Holders and is used by the Company as set forth in the last sentence of paragraph (b) of the covenant described under "—Certain Covenants—Limitation on Sales of Assets and Subsidiary Stock", the consummation of such offering; or
•: the release by the holders of the First Lien Obligations of their first liens on such Collateral; provided, however, that after giving effect to the release, First Lien Obligations (including commitments in respect thereof to the extent that such commitments are subject only to borrowing base requirements or other reasonable and customary funding conditions and are then available to be funded at the election of the Company) of no less than $20.0 million (after giving effect to all borrowing base calculations) secured by the first-priority Liens on the remaining Collateral remain outstanding.

Guaranties

Each of the Subsidiary Guarantors jointly and severally guarantees, on a senior basis, our obligations under the notes (except that the guarantee of Taurus Acquisition, Inc. is subordinated to its guarantee under the Credit Facilities). The obligations of each Subsidiary Guarantor under its Subsidiary Guaranty is limited as necessary to prevent that Subsidiary Guaranty from constituting a fraudulent conveyance under applicable law. See "Risk Factors—Risks Relating to the New Notes—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 notes from relying on the subsidiary to satisfy our payment obligations under the notes".

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Each Subsidiary Guarantor that makes a payment under its Subsidiary Guaranty will be entitled upon payment in full of all guarantied obligations under the Indenture to a contribution from each other Subsidiary Guarantor in an amount equal to such other Subsidiary Guarantor's pro rata portion of such payment based on the respective net assets of all the Subsidiary Guarantors at the time of such payment determined in accordance with GAAP (except that such contribution right against Taurus Acquisition, Inc. is subordinated to the same extent as its Subsidiary Guaranty).

If a Subsidiary Guaranty were rendered voidable, it could be subordinated by a court to all other indebtedness (including guarantees and other contingent liabilities) of the applicable Subsidiary Guarantor, and, depending on the amount of such indebtedness, a Subsidiary Guarantor's liability on its Subsidiary Guaranty could be reduced to zero. See "Risk Factors—Risks Relating to the New Notes—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 notes from relying on the subsidiary to satisfy our payment obligations under the notes".

Pursuant to the Indenture, (A) a Subsidiary Guarantor may consolidate with, merge with or into, or transfer all or substantially all its assets to any other Person to the extent described below under "—Certain Covenants—Merger and Consolidation" and (B) the Capital Stock of a Subsidiary Guarantor may be sold or otherwise disposed of to another Person to the extent described below under "—Certain Covenants—Limitation on Sales of Assets and Subsidiary Stock"; provided, however, that in the case of the consolidation, merger or transfer of all or substantially all the assets of such Subsidiary Guarantor, if such other Person is not the Company or a Subsidiary Guarantor, such Subsidiary Guarantor's obligations under its Subsidiary Guaranty must be expressly assumed by such other Person, except that such assumption will not be required in the case of:

(1): the sale or other disposition (including by way of consolidation or merger) of a Subsidiary Guarantor, including the sale or disposition of Capital Stock of a Subsidiary Guarantor to the MLP Subsidiary or following which such Subsidiary Guarantor is no longer a Restricted Subsidiary; or
(2): the sale or disposition of all or substantially all the assets of a Subsidiary Guarantor;

in each case other than to the Company or a Subsidiary of the Company and as permitted by the Indenture and if in connection therewith the Company provides an Officers' Certificate to the Trustee to the effect that the Company will comply with its obligations under the covenant described under "—Limitation on Sales of Assets and Subsidiary Stock" in respect of such disposition. Upon any sale or disposition described in clause (1) or (2) above, the obligor on the related Subsidiary Guaranty will be released from its obligations thereunder.

The Subsidiary Guaranty of a Subsidiary Guarantor also will be released:

(1): upon the designation of such Subsidiary Guarantor as an Unrestricted Subsidiary;
(2): at such time as such Subsidiary Guarantor does not have any Indebtedness outstanding that would have required such Subsidiary Guarantor to enter into a Guaranty Agreement pursuant to the covenant described under "—Certain Covenants—Future Guarantors"; or
(3): if we exercise our legal defeasance option or our covenant defeasance option as described under "—Defeasance" or if our obligations under the Indenture are discharged in accordance with the terms of the Indenture.

Ranking

Senior Indebtedness versus Notes

The indebtedness evidenced by the notes and the Subsidiary Guaranties rank pari passu in right of payment to the Senior Indebtedness of the Company and the Subsidiary Guarantors, as the case may

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be, have the benefit of the second-priority security interest on the Capital Stock of certain Subsidiaries of the Company as described under the heading "—Share Pledge", in the case of the notes, and rank senior in right of payment to all existing and future Subordinated Obligations of the Company and the Subsidiary Guarantors, as the case may be. Pursuant to the Pledge Agreement and the Intercreditor Agreement, the security interests securing the notes are second in priority (subject to Specified Permitted Liens and to certain exceptions described under the heading "—Share Pledge") to all security interests on the Capital Stock of Addison and Taurus Acquisition, Inc. at any time granted to secure First Lien Obligations. The notes are guaranteed by the Subsidiary Guarantors.

As of December 31, 2003, after giving pro forma effect to the offerings of the old notes and the Transactions:

(1): the Company's Senior Indebtedness would have been approximately $450.0 million, including the $450.0 million of old notes and no guarantees on a senior secured basis of Indebtedness of Addison; and
(2): excluding Guarantees of the Indebtedness of the Company, the Subsidiary Guarantors would have had no Indebtedness.

Liabilities of Subsidiaries versus Notes

A substantial portion of our operations are conducted through our subsidiaries. Our Canadian subsidiary is not Guaranteeing the notes, and, as described above under "—Guaranties", Subsidiary Guaranties may be released under certain circumstances. In addition, our future subsidiaries may not be required to Guarantee the notes. Claims of creditors of such non-guarantor subsidiaries, including trade creditors and creditors holding indebtedness or Guarantees issued by such non-guarantor subsidiaries, and claims of preferred stockholders of such non-guarantor subsidiaries, generally will have priority with respect to the assets and earnings of such non-guarantor subsidiaries over the claims of our creditors, including holders of the notes. Accordingly, the notes will be effectively subordinated to creditors (including trade creditors) and preferred stockholders, if any, of our non-guarantor subsidiaries.

At December 31, 2003, after giving effect to the Transactions, the total Indebtedness of our subsidiaries (other than the Subsidiary Guarantors) was approximately $0.0 million. Although the Indenture limits the incurrence of Indebtedness and preferred stock of certain of our subsidiaries, such limitation is subject to a number of significant qualifications. Moreover, the Indenture does not impose any limitation on the incurrence by such subsidiaries of liabilities that are not considered Indebtedness under the Indenture. See "—Certain Covenants—Limitation on Indebtedness".

Book-Entry, Delivery and Form

We will issue the new notes in the form of one or more global notes (the "Global Exchange Note"). The Global Exchange Note will be deposited with, or on behalf of, DTC and registered in the name of DTC or its nominee. Except as set forth below, the Global Exchange Note may be transferred, in whole and not in part, and only to DTC or another nominee of DTC. You may hold your beneficial interests in the Global Exchange Note directly through DTC if you have an account with DTC or indirectly through organizations that have accounts with DTC.

Depository Procedures

The following description of the operations and procedures of DTC is provided solely as a matter of convenience. These operations and procedures are solely within the control of the respective settlement systems and are subject to changes by them. We take no responsibility for these operations and procedures and urge investors to contact the system or their participants directly to discuss these matters.

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DTC has advised us that DTC is a limited-purpose trust company created to hold securities for its participating organizations (collectively, the "Participants") and to facilitate the clearance and settlement of transactions in those securities between Participants through electronic book-entry changes in accounts of its Participants. The Participants include securities brokers and dealers (including the initial purchasers), banks, trust companies, clearing corporations and certain other organizations. Access to DTC's system is also available to other entities such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a Participant, either directly or indirectly (collectively, the "Indirect Participants"). Persons who are not Participants may beneficially own securities held by or on behalf of DTC only through the Participants or the Indirect Participants. The ownership interests in, and transfers of ownership interests in, each security held by or on behalf of DTC are recorded on the records of the Participants and Indirect Participants.

DTC has also advised us that, pursuant to procedures established by it:

(1): upon deposit of the Global Exchange Notes, DTC will credit the accounts of Participants designated by the Initial Purchasers with portions of the principal amount of the Global Exchange Notes; and
(2): ownership of these interests in the Global Exchange Notes will be shown on, and the transfer of ownership of these interests will be effected only through, records maintained by DTC (with respect to the Participants) or by the Participants and the Indirect Participants (with respect to other owners of beneficial interests in the Global Exchange Notes).

Investors in the Global Exchange Notes who are Participants in DTC's system may hold their interests therein directly through DTC. Investors in the Global Exchange Notes who are not Participants may hold their interests therein indirectly through organizations which are Participants in such system. All interests in a Global Exchange Note may be subject to the procedures and requirements of DTC. The laws of some states require that certain Persons take physical delivery in definitive form of securities that they own. Consequently, the ability to transfer beneficial interests in a Global Exchange Note to such Persons will be limited to that extent. Because DTC can act only on behalf of Participants, which in turn act on behalf of Indirect Participants, the ability of a Person having beneficial interests in a Global Exchange Note to pledge such interests to Persons that do not participate in the DTC system, or otherwise take actions in respect of such interests, may be affected by the lack of a physical certificate evidencing such interests.

Except as described below, owners of interests in the Global Exchange Notes will not have notes registered in their names, will not receive physical delivery of notes in certificated form and will not be considered the registered owners or "Holders" thereof under the Indenture for any purpose.

Payments in respect of the principal of, and interest and premium, if any, on a Global Exchange Note registered in the name of DTC or its nominee will be payable to DTC in its capacity as the registered Holder under the Indenture. Under the terms of the Indenture, the Company and the Trustee will treat the Persons in whose names the notes, including the Global Exchange Notes, are registered as the owners of the notes for the purpose of receiving payments and for all other purposes. Consequently, neither the Company, the Trustee nor any agent of the Company or the Trustee has or will have any responsibility or liability for:

(1): any aspect of DTC's records or any Participant's or Indirect Participant's records relating to or payments made on account of beneficial ownership interests in the Global Exchange Notes or for maintaining, supervising or reviewing any of DTC's records or any Participant's or Indirect Participant's records relating to the beneficial ownership interests in the Global Exchange Notes; or
(2): any other matter relating to the actions and practices of DTC or any of its Participants or Indirect Participants.

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DTC has advised us that its current practice, upon receipt of any payment in respect of securities such as the Global Exchange Notes (including principal and interest), is to credit the accounts of the relevant Participants with the payment on the payment date unless DTC has reason to believe it will not receive payment on such payment date. Each relevant Participant is credited with an amount proportionate to its beneficial ownership of an interest in the principal amount of the relevant security as shown on the records of DTC. Payments by the Participants and the Indirect Participants to the beneficial owners of Global Exchange Notes will be governed by standing instructions and customary practices and will be the responsibility of the Participants or the Indirect Participants and will not be the responsibility of DTC, the Trustee or the Company. Neither the Company nor the Trustee will be liable for any delay by DTC or any of its Participants in identifying the beneficial owners of the Global Exchange Notes, and the Company and the Trustee may conclusively rely on and will be protected in relying on instructions from DTC or its nominee for all purposes.

DTC has advised the Company that it will take any action permitted to be taken by a Holder of Global Exchange Notes only at the direction of one or more Participants to whose account DTC has credited the interests in the Global Exchange Notes and only in respect of such portion of the aggregate principal amount of the Global Exchange Notes as to which such Participant or Participants has or have given such direction. However, if there is an Event of Default under the notes, DTC reserves the right to exchange the Global Exchange Notes for legended notes in certificated form, and to distribute such new notes to its Participants.

Neither the Company nor the Trustee nor any of their respective agents will have any responsibility for the performance by DTC or its Participants or Indirect Participants of their respective obligations under the rules and procedures governing their operations.

Certificated Notes

Subject to certain conditions, the new notes represented by the Global Exchange Notes are exchangeable for certificated notes in definitive form of like tenor in denominations of $1,000 and integral multiples thereof if:

(1): DTC (A) notifies the Company that it is unwilling or unable to continue as depositary for the Global Exchange Notes or (B) has ceased to be a clearing agency registered under the Exchange Act and, in each case, a successor depositary is not appointed;
(2): the Company, at its option, notifies the Trustee in writing that it elects to cause the issuance of the certificated notes; or
(3): there has occurred and is continuing a Default with respect to the notes.

In addition, beneficial interests in a Global Exchange Note may be exchanged for certificated notes upon prior written notice given to the Trustee by or on behalf of DTC in accordance with the Indenture. In all cases, certificated notes delivered in exchange for any Global Exchange Note or beneficial interests in Global Exchange Notes will be registered in the names, and issued in any approved denominations, requested by or on behalf of the depositary (in accordance with its customary procedures) and will bear a restrictive legend, unless that legend is not required by applicable law.

Same Day Settlement and Payment

The Company will make payments in respect of the new notes represented by the Global Exchange Notes (including principal, premium, if any, and interest, if any) by wire transfer of immediately available funds to the accounts specified by the Global Exchange Note Holder. The Company will make all payments of principal, interest and premium, if any, with respect to certificated notes by wire transfer of immediately available funds to the accounts specified by the Holders of the certificated notes or, if no such account is specified, by mailing a check to each such Holder's registered address.

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Registered Exchange Offer; Registration Rights

In connection with the offerings of the old notes, we, the Subsidiary Guarantors and the initial purchasers entered into Registration Rights Agreements relating to the old notes, which provide for this exchange offer. The Registration Rights Agreements entered into in connection with each of the issuances of old notes contain terms and conditions that are substantially the same. As such, we refer to these agreements collectively as the "Registration Rights Agreements." A copy of each of the Registration Rights Agreements relating to the old notes is filed as an exhibit to the registration statement of which this prospectus is a part. Please read the section captioned "The Exchange Offer" for a more details regarding the terms of the Registration Rights Agreements.

Change of Control

Upon the occurrence of any of the following events (each a "Change of Control"), each Holder shall have the right to require that the Company repurchase such Holder's notes at a purchase price in cash equal to 101% of the principal amount thereof on the date of purchase 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):

(1): any "person" (as such term is 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 for purposes of this clause (1) such person shall be deemed to have "beneficial ownership" of all shares that any such person has the right to acquire, whether such right is exercisable immediately or only after the passage of time), directly or indirectly, of more than 35% of the total voting power of the Voting Stock of the Company; provided, however, that the Permitted Holders beneficially own (as defined above), directly or indirectly, in the aggregate a lesser percentage of the total voting power of the Voting Stock of the Company than such other person and do not have the right or ability by voting power, contract or otherwise to elect or designate for election a majority of the Board of Directors (for purposes of this clause (1), such other person shall be deemed to beneficially own any Voting Stock of a specified person held by a parent entity, if such other person is the beneficial owner (as defined in Rules 13d-3 and 13d-5 under the Exchange Act), directly or indirectly, of more than 35% of the voting power of the Voting Stock of such parent entity and the Permitted Holders beneficially own (as defined in this proviso), directly or indirectly, in the aggregate a lesser percentage of the voting power of the Voting Stock of such parent entity and do not have the right or ability by voting power, contract or otherwise to elect or designate for election a majority of the board of directors of such parent entity);
(2): individuals who on the Issue Date constituted the Board of Directors of the Company or the Parent Board (together with any new directors whose election by such Board of Directors of the Company or the Parent Board or whose nomination for election by the shareholders of the Company or Parent, as the case may be, was approved by a vote of 66²/3% of the directors of the Company or of Parent, as the case may be, then still in office who were either directors on the Issue Date or whose election or nomination for election was previously so approved) cease for any reason to constitute a majority of the Board of Directors of the Company or the Parent Board then in office;
(3): the adoption of a plan relating to the liquidation or dissolution of the Company; or
(4): the merger or consolidation of the Company with or into another Person or the merger of another Person with or into the Company, or the sale of all or substantially all the assets of the Company (determined on a consolidated basis) to another Person other than (A) a transaction in which the survivor or transferee is a Person that is controlled by the Permitted

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Holders or (B) a transaction following which (i) in the case of a merger or consolidation transaction, holders of securities that represented 100% of the Voting Stock of the Company immediately prior to such transaction (or other securities into which such securities are converted as part of such merger or consolidation transaction) own directly or indirectly at least a majority of the voting power of the Voting Stock of the surviving Person in such merger or consolidation transaction immediately after such transaction and (ii) in the case of a sale of assets transaction, each transferee becomes an obligor in respect of the notes and a Subsidiary of the transferor of such assets.

Notwithstanding the foregoing, a Permitted MLP Transaction shall not constitute a Change of Control.

Within 30 days following any Change of Control, we will mail a notice to each Holder with a copy to the Trustee (the "Change of Control Offer") stating:

(1): that a Change of Control has occurred and that such Holder has the right to require us to purchase such Holder's notes at a purchase price in cash equal to 101% of the principal amount thereof on the date of purchase, 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 on the relevant interest payment date);
(2): the circumstances and relevant facts regarding such Change of Control (including information with respect to pro forma historical income, cash flow and capitalization, in each case after giving effect to such Change of Control);
(3): the purchase date (which shall be no earlier than 30 days nor later than 60 days from the date such notice is mailed); and
(4): the instructions, as determined by us, consistent with the covenant described hereunder, that a Holder must follow in order to have its notes purchased.

We will not be required to make a Change of Control Offer following 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 us and purchases all notes validly tendered and not withdrawn under such Change of Control Offer.

We 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 as a result of a Change of Control. To the extent that the provisions of any securities laws or regulations conflict with the provisions of the covenant described hereunder, we will comply with the applicable securities laws and regulations and shall not be deemed to have breached our obligations under the covenant described hereunder by virtue of our compliance with such securities laws or regulations.

The Change of Control purchase feature of the notes may in certain circumstances make more difficult or discourage a sale or takeover of Parent and the Company and, thus, the removal of incumbent management. The Change of Control purchase feature is a result of negotiations among the Company and the Initial Purchasers. Neither the Company nor Parent has the present intention to engage in a transaction involving a Change of Control, although it is possible that we or they could decide to do so in the future. Subject to the limitations discussed below, we or Parent could, in the future, enter into certain transactions, including acquisitions, refinancings or other recapitalizations, that would not constitute a Change of Control under the Indenture, but that could increase the amount of indebtedness outstanding at such time or otherwise affect our capital structure or credit ratings. Restrictions on our ability to Incur additional Indebtedness are contained in the covenants described under "—Certain Covenants—Limitation on Indebtedness", "—Limitation on Liens" and "—Limitation

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on Sale/Leaseback Transactions". Such restrictions can only be waived with the consent of the holders of a majority in principal amount of the notes then outstanding. Except for the limitations contained in such covenants, however, the Indenture will not contain any covenants or provisions that may afford holders of the notes protection in the event of a highly leveraged transaction.

The Credit Agreement will provide that the occurrence of certain change of control events with respect to Parent or the Company would constitute a default thereunder. In the event a Change of Control occurs at a time when we are prohibited from purchasing notes, we may seek the consent of our lenders to the purchase of notes or may attempt to refinance the borrowings that contain such prohibition. If we do not obtain such a consent or repay such borrowings, we will remain prohibited from purchasing notes. In such case, our failure to offer to purchase notes would constitute a Default under the Indenture, which would, in turn, constitute a default under the Credit Agreement.

Future indebtedness that we may incur may contain prohibitions on the occurrence of certain events that would constitute a Change of Control or require the repurchase of such indebtedness upon a Change of Control. Moreover, the exercise by the holders of their right to require us to repurchase their 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 us. Finally, our ability to pay cash to the holders of notes following the occurrence of a Change of Control may be limited by our then existing financial resources. There can be no assurance that sufficient funds will be available when necessary to make any required repurchases.

The definition of "Change of Control" includes a disposition of all or substantially all of the assets of the Company to any Person. 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 assets of the Company. As a result, it may be unclear as to whether a Change of Control has occurred and whether a holder of notes may require the Company to make an offer to repurchase the notes as described above.

The provisions under the Indenture relative to our obligation to make an offer to repurchase the notes as a result of a Change of Control may be waived or modified with the written consent of the holders of a majority in principal amount of the notes.

Permitted MLP Transaction

At least 30 days but not more than 60 days prior to the consummation of a Permitted MLP Transaction, we will mail a notice to each Holder with a copy to the Trustee (the "MLP Offer") stating:

(1): that a Permitted MLP Transaction is planned and that such Holder has the right to require us to purchase such Holder's notes at a purchase price in cash equal to (A) if the Permitted MLP Transaction is consummated at any time prior to January 15, 2007, 107.25% or (B) if the Permitted MLP Transaction is consummated at any time on or after January 15, 2007, the redemption price set forth under the caption "—Optional Redemption" that would be applicable at such time if the notes were being redeemed on the date of the Permitted MLP Transaction under such provision, in each case, such MLP Offer price being expressed as a percentage of the principal amount of the notes on the date of purchase, plus accrued and unpaid interest, if any, to the date of purchase (subject to the rights of Holders of record on the relevant record date to receive interest on the relevant interest payment date);
(2): the circumstances and relevant facts regarding such Permitted MLP Transaction (including information with respect to pro forma historical income, cash flow and capitalization, in each case after giving effect to such Permitted MLP Transaction);

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(3): the expected closing date of such Permitted MLP Transaction (the actual, if any, closing date being the purchase date);
(4): the instructions, as determined by us, consistent with the covenant described hereunder, that a Holder must follow in order to have its notes purchased.

We 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 as a result of a Permitted MLP Transaction. To the extent that the provisions of any securities laws or regulations conflict with the provisions of the covenant described hereunder, we will comply with the applicable securities laws and regulations and shall not be deemed to have breached our obligations under the covenant described hereunder by virtue of our compliance with such securities laws or regulations.

The provisions under the Indenture with respect to our obligation to make an offer to repurchase the notes as a result of a Permitted MLP Transaction may be waived or modified with the written consent of the holders of a majority in principal amount of the notes.

Certain Covenants

Covenant Suspension

During any period that the notes have a rating equal to or higher than BBB- by S&P and Baa3 by Moody's ("Investment Grade Ratings") and no Default has occurred and is continuing, the Company and the Restricted Subsidiaries will not be subject to the following covenants:

(a): "—Limitation on Indebtedness;"
(b): "—Limitation on Restricted Payments;"
(c): "—Limitation on Restrictions on Distributions from Restricted Subsidiaries;"
(d): "—Limitation on Sales of Assets and Subsidiary Stock;"
(e): "—Limitation on Affiliate Transactions;"
(f): clause (3) of the covenant described under "—Merger and Consolidation;" and
(g): "—Future Guarantors"

(collectively, the "Suspended Covenants"). In the event that the Company and the Restricted Subsidiaries are not subject to the Suspended Covenants for any period of time as a result of the preceding sentence, and subsequently one or both of S&P and Moody's downgrades the rating assigned to the notes below BBB-, in the case of S&P, and below Baa3, in the case of Moody's, then the Company and the Restricted Subsidiaries will thereafter again be subject to the Suspended Covenants (subject to subsequent suspension if the notes again receive Investment Grade Ratings).

Limitation on Indebtedness

(a) The Company will not, and will not permit any Restricted Subsidiary to, Incur, directly or indirectly, any Indebtedness; provided, however, that the Company and the Subsidiary Guarantors will be entitled to Incur Indebtedness if, on the date of such Incurrence and after giving effect thereto on a pro forma basis, the Consolidated Coverage Ratio exceeds 2.5 to 1.

(b) Notwithstanding the foregoing paragraph (a), the Company and the Restricted Subsidiaries will be entitled to Incur any or all of the following Indebtedness:

(1): Indebtedness Incurred by the Company, the Subsidiary Guarantors and Addison Energy Inc. pursuant to the Credit Agreement; provided, however, that, immediately after giving effect to any such Incurrence, the aggregate principal amount of all Indebtedness Incurred under this

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clause (1) and then outstanding does not exceed an amount equal to the greater of (A) $325.0 million less (x) the sum of all principal payments with respect to such Indebtedness pursuant to paragraph (a)(3)(A) of the covenant described under "—Limitation on Sales of Assets and Subsidiary Stock" and (y) the amount of Indebtedness then outstanding pursuant to clause (b)(15) below and (B) 40% of ACNTA as of the date of such Incurrence;

(2): Indebtedness owed to and held by the Company or a Restricted Subsidiary; provided, however, that (A) any subsequent issuance or transfer of any Capital Stock which results in any such Restricted Subsidiary ceasing to be a Restricted Subsidiary or any subsequent transfer of such Indebtedness (other than to the Company or a Restricted Subsidiary) shall be deemed, in each case, to constitute the Incurrence of such Indebtedness by the obligor thereon, (B) if the Company is the obligor on such Indebtedness, such Indebtedness is expressly subordinated to the prior payment in full in cash of all obligations with respect to the notes and (C) if a Subsidiary Guarantor is the obligor on such Indebtedness, such Indebtedness is expressly subordinated to the prior payment in full in cash of all obligations of such obligor with respect to its Subsidiary Guaranty (it being understood that any Indebtedness owed by Addison Energy Inc. to Taurus Acquisition, Inc. need not comply with the requirements of this clause (C));
(3): the old notes and notes issued in exchange for those old notes (other than any Additional Notes);
(4): Indebtedness outstanding on the Issue Date (other than Indebtedness described in clause (1), (2) or (3) of this covenant);
(5): Indebtedness of a Restricted Subsidiary Incurred and outstanding on or prior to the date on which such Restricted Subsidiary was acquired by the Company (other than Indebtedness Incurred in connection with, or to provide all or any portion of the funds or credit support utilized to consummate, the transaction or series of related transactions pursuant to which such Subsidiary became a Subsidiary or was acquired by the Company); provided, however, that on the date of such acquisition and after giving pro forma effect thereto, the Company would have been able to Incur at least $1.00 of additional Indebtedness pursuant to paragraph (a) of this covenant;
(6): Refinancing Indebtedness in respect of Indebtedness Incurred pursuant to paragraph (a) or pursuant to clause (3), (4) or (5) or this clause (6); provided, however, that to the extent such Refinancing Indebtedness directly or indirectly Refinances Indebtedness of a Subsidiary Incurred pursuant to clause (5), such Refinancing Indebtedness shall be Incurred only by such Subsidiary;
(7): Hedging Obligations consisting of Interest Rate Agreements directly related to Indebtedness permitted to be Incurred by the Company and the Restricted Subsidiaries pursuant to the Indenture;
(8): Hedging Obligations consisting of Oil and Natural Gas Hedging Contracts and Currency Agreements entered into in the ordinary course of business for the purpose of limiting risks that arise in the ordinary course of business of the Company and its Subsidiaries;
(9): obligations in respect of performance, bid and surety bonds and completion guarantees provided by the Company or any Restricted Subsidiary in the ordinary course of business;
(10): Indebtedness arising from the honoring by a bank or other financial institution of a check, draft or similar instrument drawn against insufficient funds in the ordinary course of business; provided, however, that such Indebtedness is extinguished within five Business Days of its Incurrence;

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(11): Indebtedness consisting of the Subsidiary Guaranty of a Subsidiary Guarantor and any Guarantee by the Company or a Subsidiary Guarantor of Indebtedness Incurred pursuant to paragraph (a) or pursuant to clause (1), (3), (4), (13) or (14) or pursuant to clause (6) to the extent the Refinancing Indebtedness Incurred thereunder directly or indirectly Refinances Indebtedness Incurred pursuant to paragraph (a) or pursuant to clause (3), (4), (13) or (14);
(12): in-kind obligations relating to net oil or natural gas balancing positions arising in the ordinary course of business;
(13): Indebtedness (including Capital Lease Obligations) Incurred by the Company or a Restricted Subsidiary to finance the construction, purchase or lease of, or repairs, improvements or additions to, property, plant or equipment of such Person not more than 180 days after the later of the acquisition, completion of construction, repair, improvement, addition or commencement of full operation of such property, plant or equipment, in an aggregate principal amount which, when added together with the amount of Indebtedness previously Incurred pursuant to this clause (13) and then outstanding, does not exceed $10.0 million;
(14): Indebtedness of a Foreign Subsidiary in an aggregate principal amount which, when added together with the amount of Indebtedness previously Incurred pursuant to this clause (14) and then outstanding, does not exceed $5.0 million;
(15): following a Permitted MLP Transaction, Indebtedness Incurred by the MLP Subsidiary and its Subsidiaries pursuant to the Credit Agreement; provided, however, that immediately after giving effect to any such Incurrence, the aggregate principal amount of all Indebtedness Incurred under this clause (15) and then outstanding does not exceed $75.0 million; and
(16): Indebtedness of the Company or any Subsidiary Guarantor in an aggregate principal amount which, when taken together with all other Indebtedness of the Company and the Subsidiary Guarantors outstanding on the date of such Incurrence (other than Indebtedness permitted by clauses (1) through (15) above or paragraph (a)), does not exceed $20.0 million.

(c) Notwithstanding the foregoing, neither the Company nor any Subsidiary Guarantor will Incur any Indebtedness pursuant to the foregoing paragraph (b) if the proceeds thereof are used, directly or indirectly, to Refinance any Subordinated Obligations of the Company or any Subsidiary Guarantor unless such Indebtedness shall be subordinated to the notes or the applicable Subsidiary Guaranty to at least the same extent as such Subordinated Obligations.

(d) For purposes of determining compliance with this covenant:

(1): any Indebtedness outstanding under the Credit Agreement (prior to the amendment and restatement thereof) on the Issue Date will be treated as Incurred on the Issue Date under clause (1) of paragraph (b) above; any Indebtedness remaining outstanding under the Credit Agreement after the application of the net proceeds from the sale of the notes will be treated as Incurred on the Merger Date under clause (1) of paragraph (b) above;
(2): in the event that an item of Indebtedness (or any portion thereof) meets the criteria of more than one of the types of Indebtedness described above, the Company, in its sole discretion, will classify such item of Indebtedness (or any portion thereof) at the time of Incurrence and will only be required to include the amount and type of such Indebtedness in one of the above clauses (provided, however, that any Indebtedness originally classified as Incurred pursuant to clause (b)(16) above may later be reclassified as having been Incurred pursuant to paragraph (a) above to the extent that such reclassified Indebtedness could be Incurred pursuant to paragraph (a) above at the time of such reclassification); and
(3): at the time of Incurrence, the Company will be entitled to divide and classify an item of Indebtedness in more than one of the types of Indebtedness described above.

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(e) For purposes of determining compliance with any U.S. dollar-denominated restriction on the Incurrence of Indebtedness where the Indebtedness Incurred is denominated in a different currency, the amount of such Indebtedness will be the U.S. Dollar Equivalent determined on the date of the Incurrence of such Indebtedness; provided, however, that if any such Indebtedness denominated in a different currency is subject to a Currency Agreement with respect to U.S. dollars covering all principal, premium, if any, and interest payable on such Indebtedness, the amount of such Indebtedness expressed in U.S. dollars will be as provided in such Currency Agreement. The principal amount of any Refinancing Indebtedness Incurred in the same currency as the Indebtedness being Refinanced will be the U.S. Dollar Equivalent of the Indebtedness Refinanced, except to the extent that (1) such U.S. Dollar Equivalent was determined based on a Currency Agreement, in which case the Refinancing Indebtedness will be determined in accordance with the preceding sentence, and (2) the principal amount of the Refinancing Indebtedness exceeds the principal amount of the Indebtedness being Refinanced, in which case the U.S. Dollar Equivalent of such excess will be determined on the date such Refinancing Indebtedness is Incurred.

Limitation on Restricted Payments

(a) The Company will not, and will not permit any Restricted Subsidiary, directly or indirectly, to make a Restricted Payment if at the time the Company or such Restricted Subsidiary makes such Restricted Payment:

(1)

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

(2)

the Company is not entitled to Incur an additional $1.00 of Indebtedness pursuant to paragraph (a) of the covenant described under "—Limitation on Indebtedness"; or

(3)

the aggregate amount of such Restricted Payment and all other Restricted Payments since the Issue Date would exceed the sum of (without duplication):

(A): 50% of the Consolidated Net Income accrued during the period (treated as one accounting period) from the beginning of the fiscal quarter immediately following the fiscal quarter during which the Issue Date occurs to the end of the most recent fiscal quarter ending at least 45 days prior to the date of such Restricted Payment (or, in case such Consolidated Net Income shall be a deficit, minus 100% of such deficit); plus
(B): 100% of the aggregate Net Cash Proceeds and 100% of the fair market value (as determined by the Board of Directors in good faith) of property other than cash received by the Company from the issuance or sale of its Capital Stock (other than Disqualified Stock) subsequent to the Issue Date (other than an issuance or sale to a Subsidiary of the Company and other than an issuance or sale financed directly or indirectly with Indebtedness to an employee stock ownership plan or to a trust established by the Company or any of its Subsidiaries for the benefit of their employees) and 100% of any cash capital contribution received by the Company from its shareholder subsequent to the Issue Date; plus
(C): the amount by which Indebtedness is reduced on the Company's consolidated balance sheet upon the conversion or exchange (other than by a Subsidiary of the Company) subsequent to the Issue Date of any Indebtedness convertible or exchangeable for Capital Stock (other than Disqualified Stock) of the Company (plus the amount of any accrued interest then outstanding on such Indebtedness to the extent the obligation to pay such interest is extinguished less the amount of any cash, or the fair value of any other property, distributed by the Company upon such conversion or exchange); provided, however, that the foregoing amount shall not exceed the Net Cash Proceeds received by the Company or any Restricted Subsidiary from the sale of such Indebtedness (excluding

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Net Cash Proceeds from sales to a Subsidiary of the Company or, in the case of a sale financed directly or indirectly with Indebtedness, to an employee stock ownership plan or to a trust established by the Company or any of its Subsidiaries for the benefit of their employees); plus

(D): an amount equal to the sum of (i) the net reduction in the Investments (other than Permitted Investments) made by the Company or any Restricted Subsidiary in any Person resulting from repurchases, repayments or redemptions of such Investments by such Person, proceeds realized on the sale of such Investment and proceeds representing the return of capital (excluding dividends and distributions), in each case received by the Company or any Restricted Subsidiary, and (ii) to the extent such Person is an Unrestricted Subsidiary, the portion (proportionate to the Company's equity interest in such Subsidiary) of the fair market value of the net assets of such Unrestricted Subsidiary at the time such Unrestricted Subsidiary is designated a Restricted Subsidiary; provided, however, that the foregoing sum shall not exceed, in the case of any such Person or Unrestricted Subsidiary, the amount of Investments (excluding Permitted Investments) previously made (and treated as a Restricted Payment) by the Company or any Restricted Subsidiary in such Person or Unrestricted Subsidiary.

(b) The preceding provisions will not prohibit:

(1): any Restricted Payment made out of the Net Cash Proceeds of the substantially concurrent sale of, or made by exchange for, Capital Stock of the Company (other than Disqualified Stock and other than Capital Stock issued or sold to a Subsidiary of the Company or an employee stock ownership plan or to a trust established by the Company or any of its Subsidiaries for the benefit of their employees) or a substantially concurrent cash capital contribution received by the Company from its shareholder; provided, however, that (A) such Restricted Payment shall be excluded in the calculation of the amount of Restricted Payments and (B) the Net Cash Proceeds from such sale or such cash capital contribution (to the extent so used for such Restricted Payment) shall be excluded from the calculation of amounts under clause (3)(B) of paragraph (a) above;
(2): any purchase, repurchase, redemption, defeasance or other acquisition or retirement for value of Subordinated Obligations of the Company or a Subsidiary Guarantor made by exchange for, or out of the proceeds of the substantially concurrent sale of, Indebtedness of such Person which is permitted to be Incurred pursuant to the covenant described under "—Limitation on Indebtedness"; provided, however, that such purchase, repurchase, redemption, defeasance or other acquisition or retirement for value shall be excluded in the calculation of the amount of Restricted Payments;
(3): dividends paid within 60 days after the date of declaration thereof if at such date of declaration such dividend would have complied with this covenant; provided, however, that such dividends shall be included in the calculation of the amount of Restricted Payments;
(4): so long as no Default has occurred and is continuing, Restricted Payments to effect the repurchase or other acquisition of shares of Capital Stock of the Company or any of its Subsidiaries from employees, former employees, directors or former directors of the Company or any of its Subsidiaries (or permitted transferees of such employees, former employees, directors or former directors), pursuant to the terms of the agreements (including employment agreements) or plans (or amendments thereto) approved by the Board of Directors under which such individuals purchase or sell or are granted the option to purchase or sell, shares of such Capital Stock; provided, however, that the aggregate amount of such repurchases and other acquisitions (excluding amounts representing cancelation of Indebtedness) shall not exceed in any calendar year $2.0 million plus any unused amount permitted under this

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clause (4) for the immediately preceding year, but not to exceed $4.0 million in any single calendar year; provided further, however, that such repurchases and other acquisitions shall be excluded in the calculation of the amount of Restricted Payments;

(5): payments of dividends on Disqualified Stock issued pursuant to the covenant described under "—Limitation on Indebtedness"; provided, however, that, at the time of payment of such dividend, no Default shall have occurred and be continuing (or result therefrom); provided further, however, that such dividends shall be excluded in the calculation of the amount of Restricted Payments;
(6): repurchases of Capital Stock deemed to occur upon exercise of stock options if such Capital Stock represents a portion of the exercise price of such options; provided, however, that such Restricted Payments shall be excluded in the calculation of the amount of Restricted Payments;
(7): cash payments in lieu of the issuance of fractional shares in connection with the exercise of warrants, options or other securities convertible into or exchangeable for Capital Stock of the Company; provided, however, that any such cash payment shall not be for the purpose of evading the limitation of the covenant described under this subheading (as determined in good faith by the Board of Directors); provided further, however, that such payments shall be excluded in the calculation of the amount of Restricted Payments;
(8): in the event of a Change of Control, and if no Default shall have occurred and be continuing, the payment, purchase, redemption, defeasance or other acquisition or retirement of Subordinated Obligations of the Company or any Subsidiary Guarantor, in each case, at a purchase price not greater than 101% of the principal amount of such Subordinated Obligations, plus any accrued and unpaid interest thereon; provided, however, that prior to such payment, purchase, redemption, defeasance or other acquisition or retirement, the Company (or a third party to the extent permitted by the Indenture) has made a Change of Control Offer with respect to the notes as a result of such Change of Control and has repurchased all notes validly tendered and not withdrawn in connection with such Change of Control Offer; provided further, however, that such repurchase and other acquisitions shall be included in the calculation of the amount of Restricted Payments;
(9): payments of intercompany subordinated Indebtedness, the Incurrence of which was permitted under clause (2) of paragraph (b) of the covenant described under "—Limitation on Indebtedness"; provided, however, that no Default has occurred and is continuing or would otherwise result therefrom; provided further, however, that such payments shall be excluded in the calculation of the amount of Restricted Payments;
(10): payments required pursuant to the terms of the Merger Agreement to consummate the Tender Offer and the Merger; provided, however, that such payments shall be excluded in the calculation of the amount of Restricted Payments;
(11): following a Public Equity Offering of common stock by the Company, the declaration or payment of dividends on such common stock of up to 6.00% per annum of the net cash proceeds received by the Company in all Public Equity Offerings; provided, however, that at the time of such declaration or payment, no Default shall have occurred and be continuing (or result therefrom); provided further, however, that such dividends shall be included in the calculation of the amount of Restricted Payments;
(12): dividends and other payments to Parent to be used by Parent solely to pay its franchise taxes and other fees required to maintain its corporate existence and to pay for general corporate and overhead expenses (including salaries and other compensation of employees) incurred by Parent in the ordinary course of its business; provided, however, that such dividends and other

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payments shall not exceed $500,000 in any calendar year; provided further, however, that such dividends and other payments shall be excluded in the calculation of the amount of Restricted Payments;

(13): any payment by the Company to Parent pursuant to a Tax Sharing Agreement; provided, however, that the amount of any such payment shall not exceed the amount of taxes that the Company would have been liable for on a stand-alone basis on a consolidated tax return with its Subsidiaries; provided further, however, that such payments shall be excluded in the calculation of the amount of Restricted Payments; or
(14): Restricted Payments in an amount which, when taken together with all Restricted Payments made pursuant to this clause (14), does not exceed $5.0 million; provided, however, that such payments shall be excluded in the calculation of the amount of Restricted Payments.

Limitation on Restrictions on Distributions from Restricted Subsidiaries

The Company will not, and will not permit any Restricted Subsidiary to, create or otherwise cause or permit to exist or become effective any consensual encumbrance or restriction on the ability of any Restricted Subsidiary to (a) pay dividends or make any other distributions on its Capital Stock to the Company or a Restricted Subsidiary or pay any Indebtedness owed to the Company, (b) make any loans or advances to the Company or (c) transfer any of its property or assets to the Company, except:

(1)

with respect to clauses (a), (b) and (c),

(A): any encumbrance or restriction pursuant to an agreement in effect at or entered into on the Issue Date;
(B): any encumbrance or restriction with respect to a Restricted Subsidiary (other than the MLP Subsidiary) pursuant to an agreement relating to any Indebtedness Incurred by such Restricted Subsidiary, or otherwise binding on such Restricted Subsidiary, on or prior to the date on which such Restricted Subsidiary was acquired by the Company or any Restricted Subsidiary (other than Indebtedness Incurred as consideration in, or to provide all or any portion of the funds or credit support utilized to consummate, and other than any encumbrance or restriction entered into in contemplation of, the transaction or series of related transactions pursuant to which such Restricted Subsidiary became a Restricted Subsidiary or was acquired by the Company) and outstanding on such date;
(C): any encumbrance or restriction pursuant to an agreement effecting a Refinancing of Indebtedness Incurred pursuant to an agreement referred to in clause (A) or (B) of clause (1) of this covenant or this clause (C) or contained in any amendment to an agreement referred to in clause (A) or (B) of clause (1) of this covenant or this clause (C); provided, however, that the encumbrances and restrictions with respect to such Restricted Subsidiary contained in any such refinancing agreement or amendment are no more restrictive than the encumbrances and restrictions with respect to such Restricted Subsidiary contained in such predecessor agreements;
(D): any encumbrance or restriction with respect to a Restricted Subsidiary imposed pursuant to an agreement entered into for the sale or disposition of all or substantially all the Capital Stock or assets of such Restricted Subsidiary pending the closing of such sale or disposition;
(E): customary encumbrances and restrictions contained in agreements of the type described in the definition of the term "Permitted Business Investments";

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(F): any encumbrance or restriction pursuant to an agreement relating to any Capital Lease Obligations, purchase money Indebtedness or Indebtedness owed by any Foreign Subsidiary other than Addison Energy Inc., in each case not Incurred in violation of the Indenture; provided, however, that (1) with respect to purchase money Indebtedness or Capital Lease Obligations, such restrictions relate only to the property financed with such Indebtedness and (2) with respect to any Indebtedness owed by any such Foreign Subsidiary, such encumbrance or restriction relates only to property owned by such Foreign Subsidiary and is not materially more restrictive to such Foreign Subsidiary than is customary in comparable financings, as determined in good faith by the Board of Directors;
(G): provisions in agreements or instruments which prohibit the payment of dividends or the making of other distributions with respect to any Capital Stock of a Person other than on a pro rata basis; and
(H): any encumbrance or restriction with respect to the MLP Subsidiary pursuant to an agreement relating to Indebtedness Incurred by such MLP Subsidiary to the extent such encumbrance or restriction only becomes operative following receipt of a notice of default with respect to such Indebtedness; and

(2)

with respect to clause (c) only,

(A): any encumbrance or restriction consisting of customary nonassignment provisions in leases governing leasehold interests to the extent such provisions restrict the transfer of the lease or the property leased thereunder; and
(B): any encumbrance or restriction contained in security agreements or mortgages securing Indebtedness of a Restricted Subsidiary to the extent such encumbrance or restriction restricts the transfer of the property subject to such security agreements or mortgages.

Limitation on Sales of Assets and Subsidiary Stock

(a) The Company will not, and will not permit any Restricted Subsidiary to, directly or indirectly, consummate any Asset Disposition unless:

(1)

the Company or such Restricted Subsidiary receives consideration at the time of such Asset Disposition at least equal to the fair market value (including as to the value of all non-cash consideration), as determined in good faith by the Board of Directors, of the shares and assets subject to such Asset Disposition;

(2)

at least 75% of the consideration thereof received by the Company or such Restricted Subsidiary is in the form of cash or cash equivalents, oil and natural gas properties or other assets to be used by the Company or any Restricted Subsidiary in the Oil and Gas Business or the Capital Stock of a Person that is engaged in the Oil and Gas Business and that becomes a Restricted Subsidiary; and

(3)

an amount equal to 100% of the Net Available Cash from such Asset Disposition is applied by the Company (or such Restricted Subsidiary, as the case may be)

(A): to the extent the Company elects (or is required by the terms of any Applicable Indebtedness), to prepay, repay, redeem or purchase Applicable Indebtedness of the Company or a Subsidiary Guarantor (other than any Disqualified Stock), or, in the case of an Asset Disposition by the MLP Subsidiary, Applicable Indebtedness of such MLP Subsidiary or its Subsidiaries, in each case other than Indebtedness owed to the Company or a Subsidiary of the Company, within one year from the later of the date of such Asset Disposition or the receipt of such Net Available Cash;

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(B): to the extent the Company elects, to acquire Additional Assets (provided, however, that if the assets that were the subject of such Asset Disposition constituted Collateral, then such Additional Assets shall be pledged at the time of their acquisition to the Trustee as Collateral for the Noteholders, subject to Specified Permitted Liens and the Intercreditor Agreement, unless such Additional Assets are then owned by a Subsidiary Guarantor or by the MLP Subsidiary or one of its Subsidiaries) or to make capital expenditures in the Oil and Gas Business, in each case within one year from the later of the date of such Asset Disposition or the receipt of such Net Available Cash; and
(C): to the extent of the balance of such Net Available Cash after any application in accordance with either or both of clauses (A) and (B), to make an offer to the holders of the notes (and to holders of other Applicable Senior Indebtedness of the Company or of a Subsidiary Guarantor designated by the Company) to purchase notes (and such other Applicable Senior Indebtedness of the Company or of a Subsidiary Guarantor) pursuant to and subject to the conditions contained in the Indenture;

provided, however, that in connection with any prepayment, repayment or purchase of Indebtedness pursuant to clause (A) or (C) above, the Company or such Restricted Subsidiary shall permanently retire such Indebtedness and shall cause the related loan commitment (if any) to be permanently reduced in an amount equal to the principal amount so prepaid, repaid or purchased.

Notwithstanding the foregoing, the 75% limitation referred to in clause (a)(2) above shall be deemed satisfied with respect to any Asset Disposition in which the cash or cash equivalents portion of the consideration received therefrom, determined in accordance with the foregoing provision on an after-tax basis, is equal to or greater than what the after-tax cash proceeds would have been had such Asset Disposition complied with such 75% limitation.

The requirement of clause (a)(3)(B) above shall be deemed to be satisfied if an agreement (including a lease, whether a capital lease or an operating lease) committing to make the acquisitions or expenditures referred to therein is entered into by the Company or a Restricted Subsidiary within the time period specified in such clause and such Net Available Cash is subsequently applied in accordance with such agreement within six months following such agreement.

Notwithstanding the foregoing provisions of this covenant, unless the Asset Disposition involves the disposition of Collateral, the Company and the Restricted Subsidiaries will not be required to apply any Net Available Cash in accordance with this covenant except to the extent that the aggregate Net Available Cash from all Asset Dispositions which is not applied in accordance with this covenant exceeds $15.0 million. Pending application of Net Available Cash pursuant to this covenant, such Net Available Cash shall be invested in Temporary Cash Investments (which, if the assets that were the subject of such Asset Disposition constituted Collateral, then such Temporary Cash Investments shall be pledged to the Trustee as Collateral for the benefit of the Noteholders, subject to Specified Permitted Liens and the Intercreditor Agreement, pending such application) or applied to temporarily reduce revolving credit indebtedness that is Applicable Indebtedness.

For the purposes of this covenant, the following are deemed to be cash or cash equivalents:

(1): the assumption of Indebtedness of the Company or any Restricted Subsidiary (other than obligations in respect of Disqualified Stock or Preferred Stock of the Company or a Subsidiary Guarantor) and the release of the Company or such Restricted Subsidiary from all liability on such Indebtedness in connection with such Asset Disposition; and
(2): securities received by the Company or any Restricted Subsidiary from the transferee that are promptly converted by the Company or such Restricted Subsidiary into cash, to the extent of cash received in that conversion.

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(b) In the event of an Asset Disposition that requires the purchase of notes (and other Applicable Senior Indebtedness of the Company or a Subsidiary Guarantor) pursuant to clause (a)(3)(C) above, the Company will purchase notes tendered pursuant to an offer by the Company for the notes (and such other Applicable Senior Indebtedness) at a purchase price of 100% of their principal amount (or, in the event such other Applicable Senior Indebtedness of the Company or such Subsidiary Guarantor was issued with significant original issue discount, 100% of the accreted value thereof) without premium, plus accrued but unpaid interest (or, in respect of such other Applicable Senior Indebtedness of the Company or such Subsidiary Guarantor, such lesser price, if any, as may be provided for by the terms of such Applicable Senior Indebtedness) in accordance with the procedures (including prorating in the event of oversubscription) set forth in the Indenture; provided, however, that the procedures for making an offer to holders of other Applicable Senior Indebtedness will be as provided for by the terms of such Applicable Senior Indebtedness. If the aggregate purchase price of the Indebtedness tendered exceeds the Net Available Cash allotted to their purchase, the Company will select the Indebtedness to be purchased on a pro rata basis but in round denominations, which in the case of the notes will be denominations of $1,000 principal amount or multiples thereof. The Company shall not be required to make such an offer to purchase notes (and other Applicable Senior Indebtedness of the Company or a Subsidiary Guarantor) pursuant to this covenant if the Net Available Cash available therefor is less than $15.0 million (which lesser amount shall be carried forward for purposes of determining whether such an offer is required with respect to the Net Available Cash from any subsequent Asset Disposition). Upon completion of such an offer to purchase, Net Available Cash will be deemed to be reduced by the aggregate amount of such offer (whether or not accepted) and any then remaining Net Available Cash following such offer may be used for any purpose not prohibited by the Indenture.

(c) 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 this covenant, the Company will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under this covenant by virtue of its compliance with such securities laws or regulations.

Limitation on Affiliate Transactions

(a) The Company will not, and will not permit any Restricted Subsidiary to, enter into or permit to exist any transaction (including the purchase, sale, lease or exchange of any property, employee compensation arrangements or the rendering of any service) with, or for the benefit of, any Affiliate of the Company (an "Affiliate Transaction") unless:

(1): the terms of the Affiliate Transaction are no less favorable to the Company or such Restricted Subsidiary than those that could be obtained at the time of the Affiliate Transaction in arm's-length dealings with a Person who is not an Affiliate;
(2): if such Affiliate Transaction involves an amount in excess of $10.0 million, the terms of the Affiliate Transaction are set forth in writing and a majority of the non-employee directors of the Company disinterested with respect to such Affiliate Transaction have determined in good faith that the criteria set forth in clause (1) are satisfied and have approved the relevant Affiliate Transaction as evidenced by a resolution of the Board of Directors; and
(3): if such Affiliate Transaction involves an amount in excess of $25.0 million, the Board of Directors shall also have received a written opinion from an Independent Qualified Party to the effect that such Affiliate Transaction is fair, from a financial standpoint, to the Company and the Restricted Subsidiaries or is not less favorable to the Company and the Restricted

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Subsidiaries than could reasonably be expected to be obtained at the time in an arm's-length transaction with a Person who was not an Affiliate.

(b) The provisions of the preceding paragraph (a) will not prohibit:

(1): any Investment (other than a Permitted Investment) or other Restricted Payment, in each case 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 arrangements, stock options and stock ownership plans approved by the Board of Directors;
(3): loans or advances to officers or employees in the ordinary course of business in accordance with the past practices of the Company or the Restricted Subsidiaries, but in any event not to exceed $3.0 million in the aggregate outstanding at any one time;
(4): the payment of reasonable fees to directors of the Company and the Restricted Subsidiaries who are not employees of the Company or the Restricted Subsidiaries and the indemnification of, and reimbursement of reasonable out-of-pocket expenses incurred by, directors of the Company and the Restricted Subsidiaries in attending meetings of such directors;
(5): any transaction between or among the Company and a Restricted Subsidiary or joint venture or similar entity which would constitute an Affiliate Transaction solely because the Company or a Restricted Subsidiary owns an equity interest in or otherwise controls such Restricted Subsidiary, joint venture or similar entity;
(6): the issuance or sale of any Capital Stock (other than Disqualified Stock) of the Company; and
(7): any agreement as in effect on the Issue Date and described in the Offering Circular or any amendments or other modifications, renewals or extensions of any such agreement (so long as such amendments or other modifications, renewals or extensions are not materially less favorable to the Company or the Restricted Subsidiaries) and the transactions evidenced thereby.

Limitation on Line of Business

The Company will not, and will not permit any Restricted Subsidiary to, engage in any business other than a Related Business.

Limitation on Liens

The Company will not, and will not permit any Restricted Subsidiary to, directly or indirectly, Incur or permit to exist any Lien of any nature whatsoever on any of its properties (including Capital Stock of a Restricted Subsidiary), whether owned at the Issue Date or thereafter acquired, other than

(1): with respect to Collateral, (w) Specified Permitted Liens, (x) Liens securing the notes (including Additional Notes, if any) and the Subsidiary Guarantees, (y) Liens securing First Lien Obligations and (z) Liens securing Permitted Collateral Debt and
(2): with respect to non-Collateral, Permitted Liens, without, in the case of this clause (2), effectively providing that the notes shall be secured equally and ratably with (or prior to) the obligation so secured for so long as such obligation is secured.

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Limitation on Sale/Leaseback Transactions

The Company will not, and will not permit any Restricted Subsidiary to, enter into any Sale/Leaseback Transaction with respect to any property unless:

(1): the Company or such Restricted Subsidiary would be entitled to (A) Incur Indebtedness in an amount equal to the Attributable Debt with respect to such Sale/Leaseback Transaction pursuant to the covenant described under "—Limitation on Indebtedness" and (B) create a Lien on such property securing such Attributable Debt without equally and ratably securing the notes pursuant to the covenant described under "—Limitation on Liens";
(2): the net proceeds received by the Company or any Restricted Subsidiary in connection with such Sale/Leaseback Transaction are at least equal to the fair market value (as determined by the Board of Directors) of such property; and
(3): the Company applies the proceeds of such transaction in compliance with the covenant described under "—Limitation on Sale of Assets and Subsidiary Stock".

Merger and Consolidation

The Company will not consolidate with or merge with or into, or convey, transfer or lease, in one transaction or a series of transactions, directly or indirectly, all or substantially all its assets to, any Person, unless:

(1): the resulting, surviving or transferee Person (the "Successor Company") shall be a Person organized and existing under the laws of the United States of America, any State thereof or the District of Columbia and the Successor Company (if not the Company) shall expressly assume, by an indenture supplemental thereto, executed and delivered to the Trustee, in form satisfactory to the Trustee, all the obligations of the Company under the notes and the Indenture;
(2): immediately after giving pro forma effect to such transaction (and treating any Indebtedness which becomes an obligation of the Successor Company or any Subsidiary as a result of such transaction as having been Incurred by such Successor Company or such Subsidiary at the time of such transaction), no Default shall have occurred and be continuing;
(3): immediately after giving pro forma effect to such transaction, the Successor Company would be able to Incur an additional $1.00 of Indebtedness pursuant to paragraph (a) of the covenant described under "—Limitation on Indebtedness";
(4): the Company shall have delivered to the Trustee an Officers' Certificate and an Opinion of Counsel, each stating that such consolidation, merger or transfer and such supplemental indenture (if any) comply with the Indenture; and
(5): the Company shall have delivered to the Trustee an Opinion of Counsel to the effect that the Holders will not recognize income, gain or loss for Federal income tax purposes as a result of such transaction and will be subject to Federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such transaction had not occurred;

provided, however, that (x) clauses (1), (3) and (5) will not be applicable to a Permitted MLP Transaction and (y) clause (3) will not be applicable to (A) a Restricted Subsidiary consolidating with, merging into or transferring all or part of its properties and assets to the Company or another Subsidiary Guarantor that is a Wholly Owned Subsidiary or (B) the Company merging with an Affiliate of the Company solely for the purpose and with the sole effect of reincorporating the Company in another jurisdiction.

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For purposes of this covenant, the sale, lease, conveyance, assignment, transfer or other disposition in a single transaction or a series of related transactions 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 such 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 Successor Company will be the successor to the Company and shall succeed to, and be substituted for, and may exercise every right and power of, the Company under the Indenture, and the predecessor Company, except in the case of a lease, shall be released from the obligation to pay the principal of and interest on the notes.

The Company will not permit any Subsidiary Guarantor to consolidate with or merge with or into, or convey, transfer or lease, in one transaction or a series of transactions, all or substantially all of its assets to any Person unless:

(1): except in the case of a Subsidiary Guarantor (x) that has been disposed of in its entirety to another Person, including the MLP Subsidiary (other than to the Company or any other Subsidiary of the Company), whether through a merger, consolidation or sale of Capital Stock or assets, (y) that, as a result of the disposition of all or a portion of its Capital Stock, ceases to be a Subsidiary or (z) that has otherwise been released from its Subsidiary Guaranty in accordance with the terms thereof and the terms of the Indenture, in each case, if in connection therewith the Company provides an Officers' Certificate to the Trustee to the effect that the Company will comply with its obligations under the covenant described under "—Limitation on Sales of Assets and Subsidiary Stock" in respect of such disposition, the resulting, surviving or transferee Person (if not such Subsidiary) shall be a Person organized and existing under the laws of the jurisdiction under which such Subsidiary was organized or under the laws of the United States of America, or any State thereof or the District of Columbia, and such Person shall expressly assume, by a Guaranty Agreement, in a form satisfactory to the Trustee, all the obligations of such Subsidiary, if any, under its Subsidiary Guaranty;
(2): immediately after giving effect to such transaction or transactions on a pro forma basis (and treating any Indebtedness which becomes an obligation of the resulting, surviving or transferee Person as a result of such transaction as having been issued by such Person at the time of such transaction), no Default shall have occurred and be continuing; and
(3): the Company delivers to the Trustee an Officers' Certificate and an Opinion of Counsel, each stating that such consolidation, merger or transfer and such Guaranty Agreement, if any, complies with the Indenture.

Impairment of Security Interest

The Company will not, and will not permit any of the Restricted Subsidiaries to, take or knowingly or negligently omit to take, any action which action or omission might or would have the result of materially impairing the security interest with respect to the Collateral for the benefit of the Trustee and the Holders of the notes, and the Company will not, and will not permit any of the Restricted Subsidiaries to, grant to any Person other than the Credit Agent or the Trustee, for the benefit of the Trustee and the Holders of the notes and the other beneficiaries described in the Pledge Agreement, any interest whatsoever in any of the Collateral; provided, however, that a Permitted MLP Transaction shall not be deemed to constitute a violation of this covenant.

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Future Guarantors

The Company will cause each domestic Restricted Subsidiary (other than the MLP Subsidiary and any Subsidiary of the MLP Subsidiary) that is a Significant Subsidiary and that Incurs any Indebtedness in an original principal amount greater than $5.0 million to, and each Foreign Subsidiary that is a Significant Subsidiary and that enters into a Guarantee of any Senior Indebtedness (other than a Foreign Subsidiary that Guarantees Senior Indebtedness Incurred by another Foreign Subsidiary) to, in each case, at the same time, execute and deliver to the Trustee a Guaranty Agreement pursuant to which such Restricted Subsidiary will Guarantee payment of the notes on the same terms and conditions as those set forth in the Indenture.

SEC Reports

Whether or not the Company is subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act, the Company will file with the SEC (subject to the next sentence) and provide the Trustee and Noteholders with such annual and other reports as are specified in Sections 13 and 15(d) of the Exchange Act and applicable to a U.S. corporation subject to such Sections, such reports to be so filed and provided at the times specified for the filings of such reports under such Sections and containing all the information, audit reports and exhibits required for such reports. If at any time, the Company is not subject to the periodic reporting requirements of the Exchange Act for any reason, the Company will nevertheless continue filing the reports specified in the preceding sentence with the SEC within the time periods required unless the SEC will not accept such a filing. The Company agrees that it will not take any action for the purpose of causing the SEC not to accept any such filings. If, notwithstanding the foregoing, the SEC will not accept such filings for any reason, the Company will post the reports specified in the preceding sentence on its website within the time periods that would apply if the Company were required to file those reports with the SEC. Notwithstanding the foregoing, the Company may satisfy such requirements prior to the effectiveness of the exchange offer registration statement or the shelf registration statement by filing with the SEC the exchange offer registration statement or shelf registration statement, to the extent that any such registration statement contains substantially the same information as would be required to be filed by the Company if it were subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act, and by providing the Trustee and Noteholders with such registration statement (and any amendments thereto) promptly following the filing thereof.

At any time that any of the Company's Subsidiaries are Unrestricted Subsidiaries, then the quarterly and annual financial information required by the preceding paragraph will include a reasonably detailed presentation, either on the face of the financial statements or in the footnotes thereto, and in "Management's Discussion and Analysis of Financial Condition and Results of Operations", of the financial condition and results of operations of the Company and its Restricted Subsidiaries separate from the financial condition and results of operations of the Unrestricted Subsidiaries of the Company.

In addition, the Company will furnish to the Holders of the notes and to prospective investors, upon the requests of such Holders, any information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act so long as the notes are not freely transferable under the Securities Act.

Defaults

Each of the following is an Event of Default:

(1): a default in the payment of interest on the notes when due, continued for 30 days;

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(2): a default in the payment of principal of any note when due at its Stated Maturity, upon optional redemption, upon required purchase, upon declaration of acceleration or otherwise;
(3): the failure by the Company to comply with its obligations under "—Certain Covenants—Merger and Consolidation" above, "—Permitted MLP Transaction" above or with any of its obligations in the Escrow Agreement;
(4): the failure by the Company to comply for 30 days after notice (as specified below) with any of its obligations in the covenants described above under "—Change of Control" (other than a failure to purchase notes) or under "—Certain Covenants" under "—Limitation on Indebtedness", "—Limitation on Restricted Payments", "—Limitation on Restrictions on Distributions from Restricted Subsidiaries", "—Limitation on Sales of Assets and Subsidiary Stock" (other than a failure to purchase notes), "—Limitation on Affiliate Transactions", "—Limitation on Line of Business", "—Limitation on Liens", "—Limitation on Sale/Leaseback Transactions", "—Impairment of Security Interest", "—Future Guarantors" or "—SEC Reports";
(5): the failure by the Company or any Subsidiary Guarantor to comply for 60 days after notice (as specified below) with its other agreements contained in the Indenture or in the Pledge Agreement;
(6): Indebtedness of the Company, any Subsidiary Guarantor or any Significant Subsidiary is not paid within any applicable grace period after final maturity or is accelerated by the holders thereof because of a default and the total amount of such Indebtedness unpaid or accelerated exceeds $5.0 million (the "cross acceleration provision");
(7): certain events of bankruptcy, insolvency or reorganization of the Company, a Subsidiary Guarantor or any Significant Subsidiary (the "bankruptcy provisions");
(8): any judgment or decree (to the extent not covered by insurance) for the payment of money in excess of $5.0 million is entered against the Company, a Subsidiary Guarantor or any Significant Subsidiary, remains outstanding for a period of 60 consecutive days following such judgment and is not discharged, waived or stayed (the "judgment default provision");
(9): any Subsidiary Guaranty ceases to be in full force and effect (other than in accordance with the terms of such Subsidiary Guaranty) or any Subsidiary Guarantor denies or disaffirms its obligations under its Subsidiary Guaranty, as the case may be (the "guaranty default provision"); or
(10): the security interest under the Pledge Agreement shall, at any time, fail or cease to be in full force and effect for any reason, other than the satisfaction in full of all Obligations under the Indenture and discharge of the Indenture or the release of such security interest in accordance with the provisions of the Indenture, for 30 days after notice as specified below or the Company or any Subsidiary Guarantor shall assert, in any pleading in any court of competent jurisdiction, that any such security interest is invalid or unenforceable (the "security default provision").

However, a default under clause (4), (5) or (10) will not constitute an Event of Default until the Company receives from the Trustee or the holders of 25% in principal amount of the outstanding notes a notice specifying the default, demanding that the default be remedied and stating that such notice is a "Notice of Default" and the Company does not cure such default within the time specified above after receipt of such notice.

If an Event of Default occurs and is continuing, the Trustee or the holders of at least 25% in principal amount of the outstanding notes may declare the principal of and accrued but unpaid interest on all the notes to be due and payable by notice in writing to the Company specifying such Event of

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Default and stating that such notice is a "Notice of Acceleration". Upon such a declaration, such principal and interest shall be due and payable immediately. If an Event of Default relating to certain events of bankruptcy, insolvency or reorganization of the Company occurs and is continuing, the principal of and interest on all the notes will ipso facto become and be immediately due and payable without any declaration or other act on the part of the Trustee or any holders of the notes. Under certain circumstances, the holders of a majority in principal amount of the outstanding notes may waive an existing or past Event of Default and its consequences and may also rescind any such acceleration with respect to the notes and its consequences.

Subject to the provisions of the Indenture relating to the duties of the Trustee, in case an Event of Default occurs and is continuing, the Trustee will be under no obligation to exercise any of the rights or powers under the Indenture at the request or direction of any of the holders of the notes unless such holders have offered to the Trustee reasonable indemnity or security against any loss, liability or expense. Except to enforce the right to receive payment of principal, premium (if any) or interest when due, no holder of a note may pursue any remedy with respect to the Indenture or the notes unless:

(1): such holder has previously given the Trustee notice that an Event of Default is continuing;
(2): holders of at least 25% in principal amount of the outstanding notes have requested the Trustee to pursue the remedy;
(3): such holders have offered the Trustee reasonable security or indemnity against any loss, liability or expense;
(4): the Trustee has not complied with such request within 60 days after the receipt thereof and the offer of security or indemnity; and
(5): holders of a majority in principal amount of the outstanding notes have not given the Trustee a direction inconsistent with such request within such 60-day period.

Subject to certain restrictions, the holders of a majority in principal amount of the outstanding notes are given the right to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee or of exercising any trust or power conferred on the Trustee. The Trustee, however, may refuse to follow any direction that conflicts with law or the Indenture or that the Trustee determines is unduly prejudicial to the rights of any other holder of a note or that would involve the Trustee in personal liability.

If a Default occurs, is continuing and is known to the Trustee, the Trustee must mail to each holder of the notes notice of the Default within 90 days after it occurs. Except in the case of a Default in the payment of principal of or interest on any note, the Trustee may withhold notice if and so long as a committee of its Trust Officers determines that withholding notice is not opposed to the interest of the holders of the notes. In addition, we are required to deliver to the Trustee, within 120 days after the end of each fiscal year, a certificate indicating whether the signers thereof know of any Default that occurred during the previous year. We are required to deliver to the Trustee, within 30 days after we became aware of any event which would constitute certain Defaults, written notice of such event and what action we are taking or propose to take in respect thereof.

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Amendments and Waivers

Subject to certain exceptions, the Indenture, the Pledge Agreement and the Intercreditor Agreement may be amended with the consent of the holders of a majority in principal amount of the notes then outstanding (including consents obtained in connection with a tender offer or exchange for the notes) and any past default or non-compliance with any provisions may also be waived with the consent of the holders of a majority in principal amount of the notes then outstanding. However, without the consent of each holder of an outstanding note affected thereby, an amendment or waiver may not, among other things:

(1): reduce the amount of notes whose holders must consent to an amendment;
(2): reduce the rate of or extend the time for payment of interest on any note;
(3): reduce the principal of or change the Stated Maturity of any note;
(4): change the provisions applicable to the redemption of any note as described under "—Optional Redemption" above;
(5): make any note payable in money other than that stated in the note;
(6): impair the right of any holder of the notes to receive payment of principal of and interest on such holder's notes on or after the due dates therefor or to institute suit for the enforcement of any payment on or with respect to such holder's notes;
(7): make any change in, the amendment provisions which require each holder's consent or in the waiver provisions;
(8): make any change in the ranking or priority of any note that would adversely affect the Noteholders;
(9): make any change in, or release other than in accordance with the Indenture or any Subsidiary Guaranty that would adversely affect the Noteholders; or
(10): make any change in the Pledge Agreement, the Intercreditor Agreement or the provisions in the Indenture dealing with the Pledge Agreement or application of proceeds of the Collateral that would adversely affect the Noteholders, including, except as otherwise explicitly set forth in the Indenture, the Pledge Agreement or the Intercreditor Agreement, any release of any Collateral from the Lien of the Indenture and the Pledge Agreement.

Notwithstanding the preceding, without the consent of any holder of the notes, the Company, the Subsidiary Guarantors and Trustee may amend the Indenture:

(1): to cure any ambiguity, omission, defect or inconsistency;
(2): to provide for the assumption by a successor corporation of the obligations of the Company or any Subsidiary Guarantor under the Indenture;
(3): to provide for uncertificated notes in addition to or in place of certificated notes (provided that the uncertificated notes are issued in registered form for purposes of Section 163(f) of the Code, or in a manner such that the uncertificated notes are described in Section 163(f)(2)(B) of the Code);
(4): to add Guarantees with respect to the notes, including any Subsidiary Guaranties, or to further secure the notes;
(5): to add to the covenants of the Company or a Subsidiary Guarantor for the benefit of the holders of the notes or to surrender any right or power conferred upon the Company or a Subsidiary Guarantor;

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(6): to make any change that does not adversely affect the rights of any holder of the notes;
(7): to comply with any requirement of the SEC in connection with the qualification of the Indenture under the Trust Indenture Act; or
(8): to make any amendment to the provisions of the Indenture relating to the form, authentication, transfer and legending of notes; provided, however, that (a) compliance with the Indenture as so amended would not result in notes being transferred in violation of the Securities Act or any other applicable securities law and (b) such amendment does not materially affect the rights of Holders to transfer notes.

Notwithstanding the second preceding paragraph, without the consent of any Holder of notes, any amendment, waiver or consent agreed to by the Credit Agent or the holders of First Lien Obligations under any provision of the Pledge Agreement granting the first-priority Lien on any Collateral to secure the First Lien Obligations will automatically apply to the comparable provision of the Pledge Agreement entered into in connection with the notes; provided, however, that if any such amendment, waiver or consent could reasonably be expected to be adverse to the Noteholders or the interest of the Noteholders in the Collateral, such amendment, waiver or consent will not be applicable to the Pledge Agreement entered into in connection with the notes as provided above unless First Lien Obligations (including commitments in respect thereof to the extent that such commitments are subject only to borrowing base requirements or other reasonable and customary funding conditions and are then available to be funded at the election of the Company) of no less than $20.0 million (after giving effect to all borrowing base calculations) secured by first-priority Liens on the Collateral are then outstanding. Notwithstanding the foregoing, no such amendment, waiver or consent may have the effect of releasing the Collateral, except to the extent described under the caption "—Share Pledge".

The consent of the holders of the notes is not necessary under the Indenture to approve the particular form of any proposed amendment, waiver or consent. It is sufficient if such consent approves the substance of the proposed amendment, waiver or consent.

After an amendment under the Indenture becomes effective, we are required to mail to holders of the notes a notice briefly describing such amendment. However, the failure to give such notice to all holders of the notes, or any defect therein, will not impair or affect the validity of the amendment.

Neither the Company nor any Affiliate of the Company may, directly or indirectly, pay or cause to be paid any consideration, whether by way of interest, fee or otherwise, to any Holder 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 to all Holders that so consent, waive or agree to amend in the time frame set forth in solicitation documents relating to such consent, waiver or agreement.

Transfer

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. We may require payment of a sum sufficient to cover any tax, assessment or other governmental charge payable in connection with certain transfers and exchanges.

Satisfaction and Discharge

When we (1) deliver to the Trustee all outstanding notes for cancelation or (2) all outstanding notes have become due and payable, whether at maturity or on a redemption date as a result of the mailing of notice of redemption (it being understood that all outstanding notes will be deemed to be due and payable on such redemption date upon the mailing of such notice of redemption), and, in the case of clause (2), we irrevocably deposit with the Trustee funds sufficient to pay at maturity or upon

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redemption all outstanding notes, including interest thereon to maturity or such redemption date, and if in any case we pay all other sums payable under the Indenture by us, then the Indenture shall, subject to certain exceptions, cease to be of further effect.

Defeasance

At any time, we may terminate all our obligations under the notes and the Indenture ("legal defeasance"), except for certain obligations, including those respecting the defeasance trust and obligations to register the transfer or exchange of the notes, to replace mutilated, destroyed, lost or stolen notes and to maintain a registrar and paying agent in respect of the notes.

In addition, at any time we may terminate our obligations under "—Change of Control", "—Permitted MLP Transaction" and under the covenants described under "—Certain Covenants" (other than the covenant described under "—Merger and Consolidation"), the operation of the cross acceleration provision, the bankruptcy provisions with respect to the Subsidiary Guarantors and Significant Subsidiaries, the security default provision, the guaranty default provision and the judgment default provision described under "—Defaults" above and the limitations contained in clause (3) of the first paragraph under "—Certain Covenants—Merger and Consolidation" above ("covenant defeasance").

We may exercise our legal defeasance option notwithstanding our prior exercise of our covenant defeasance option. If we exercise our legal defeasance option, payment of the notes may not be accelerated because of an Event of Default with respect thereto. If we exercise our covenant defeasance option, payment of the notes may not be accelerated because of an Event of Default specified in clause (4), (5) (with respect to the Pledge Agreement and certain provisions of the Indenture), (6), (7) (with respect only to Significant Subsidiaries and Subsidiary Guarantors) or (8), (9) or (10) under "—Defaults" above or because of the failure of the Company to comply with clause (3) of the first paragraph under "—Certain Covenants—Merger and Consolidation" above. If we exercise our legal defeasance option or our covenant defeasance option, each Subsidiary Guarantor will be released from all of its obligations with respect to its Subsidiary Guaranty and we will be released from our obligations with respect to the Pledge Agreement.

In order to exercise either of our defeasance options, we must irrevocably deposit in trust (the "defeasance trust") with the Trustee money or U.S. Government Obligations for the payment of principal and interest on the notes to redemption or maturity, as the case may be, and must comply with certain other conditions, including delivery to the Trustee of an Opinion of Counsel to the effect that holders of the notes will not recognize income, gain or loss for Federal income tax purposes as a result of such deposit and defeasance and will be subject to Federal income tax on the same amounts and in the same manner and at the same times as would have been the case if such deposit and defeasance had not occurred (and, in the case of legal defeasance only, such Opinion of Counsel must be based on a ruling of the Internal Revenue Service or other change in applicable Federal income tax law).

Concerning the Trustee

Wilmington Trust Company is the Trustee under the Indenture. We have appointed Wilmington Trust Company as Registrar and Paying Agent with regard to the notes.

The Indenture contains certain limitations on the rights of the Trustee, should it become a creditor of the Company, to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The Trustee is permitted to engage in other transactions; provided, however, if it acquires any conflicting interest it must either eliminate such conflict within 90 days, apply to the SEC for permission to continue or resign.

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The Holders of a majority in principal amount of the outstanding notes have the right to direct the time, method and place of conducting any proceeding for exercising any remedy available to the Trustee, subject to certain exceptions. If an Event of Default occurs (and is not cured), the Trustee will be required, in the exercise of its power, to use the degree of care of a prudent man in the conduct of his own affairs. Subject to such provisions, the Trustee will be under no obligation to exercise any of its rights or powers under the Indenture at the request of any Holder of notes, unless such Holder shall have offered to the Trustee security and indemnity satisfactory to it against any loss, liability or expense and then only to the extent required by the terms of the Indenture.

No Personal Liability of Directors, Officers, Employees and Stockholders

No director, officer, employee, incorporator or stockholder of the Company or any Subsidiary Guarantor will have any liability for any obligations of the Company or any Subsidiary Guarantor under the notes, any Subsidiary Guaranty, any Pledge Agreement or the Indenture or for any claim based on, in respect of, or by reason of such obligations or their creation. Each Holder of the notes 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 and release may not be effective to waive liabilities under the U.S. Federal securities laws, and it is the view of the SEC that such a waiver is against public policy.

Governing Law

The Indenture, the Pledge Agreement, the Intercreditor Agreement and the notes are governed by, and construed in accordance with, the laws of the State of New York.

Certain Definitions

"Additional Assets" means:

(1): any property, plant or equipment or other assets (including Capital Stock of a Person engaged in a Related Business) used in a Related Business;
(2): 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 another Restricted Subsidiary; or
(3): Capital Stock constituting a minority interest in any Person that at such time is a Restricted Subsidiary;

provided, however, that any such Restricted Subsidiary described in clause (2) or (3) above is primarily engaged in a Related Business.

"Adjusted Consolidated Net Tangible Assets" or "ACNTA" means (without duplication), as of the date of determination:

(a) the sum of:

(1)

discounted future net revenue from proved crude oil and natural gas reserves of the Company and its Restricted Subsidiaries calculated in accordance with SEC guidelines before any state or federal income taxes, as estimated in a reserve report prepared as of the end of the fiscal year ending at least 45 days prior to the date of determination, which reserve report is prepared or audited by independent petroleum engineers, as increased by, as of the date of determination, the discounted future net revenue calculated in accordance with SEC guidelines (utilizing the prices utilized in such year end reserve report) of:

(A): estimated proved crude oil and natural gas reserves of the Company and its Restricted Subsidiaries attributable to acquisitions consummated since the date of such reserve report, and

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(B): estimated crude oil and natural gas reserves of the Company and its Restricted Subsidiaries attributable to extensions, discoveries and other additions and upward determinations of estimates of proved crude oil and natural gas reserves (including previously estimated development costs incurred during the period and the accretion of discount since the prior period end) due to exploration, development or exploitation, production or other activities which reserves were not reflected in such reserve report which would, in accordance with standard industry practice, result in such determinations, in each case calculated in accordance with SEC guidelines (utilizing the prices utilized in such year end reserve report)

and decreased by, as of the date of determination, the discounted future net revenue attributable to:

(C): estimated proved crude oil and natural gas reserves of the Company and its Restricted Subsidiaries reflected in such reserve report produced or disposed of since the date of such reserve report, and
(D): reductions in the estimated oil and natural gas reserves of the Company and its Restricted Subsidiaries reflected in such reserve report since the date of such reserve report attributable to downward determinations of estimates of proved crude oil and natural gas reserves due to exploration, development or exploitation, production or other activities conducted or otherwise occurring since the date of such reserve report which would, in accordance with standard industry practice, result in such determinations, in each case calculated in accordance with SEC guidelines (utilizing the prices utilized in such reserve report); provided, however, that, in the case of each of the determinations made pursuant to clauses (A) through (D), such increases and decreases shall be estimated by the Company's engineers, except that if as a result of such acquisitions, dispositions, discoveries, extensions or revisions, there is a Material Change, then such increases and decreases in the discounted future net revenue shall be confirmed in writing by an independent petroleum engineer;

(2): the capitalized costs that are attributable to crude oil and natural gas properties of the Company and its Restricted Subsidiaries to which no proved crude oil and natural gas reserves are attributed, based on the Company's books and records as of a date no earlier than the end of the most recent fiscal quarter for which financial statements of the Company have been made publicly available prior to the date of determination;
(3): the Net Working Capital as of the end of the most recent fiscal quarter ending at least 45 days prior to the date of determination; and
(4): the greater of (i) the net book value as of a date no earlier than the end of the most recent fiscal quarter ending at least 45 days prior to the date of determination and (ii) the appraised value, as estimated by independent appraisers, of all other tangible assets, including mineral rights held under leases or other contractual arrangements, of the Company and its Restricted Subsidiaries as of a date no earlier than the most recent fiscal year ending at least 45 days prior to the date of determination (provided, however, that the Company shall not be required to obtain such an appraisal of such assets if no such appraisal has, been performed); minus

(b) to the extent not otherwise taken into account in the immediately preceding clause (a), the sum of

(1): minority interests;
(2): any natural gas balancing liabilities of the Company and its Restricted Subsidiaries reflected in the Company's latest audited consolidated financial statements;

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(3): the discounted future net revenue, calculated in accordance with SEC guidelines (utilizing the same prices utilized in the Company's year-end reserve report), attributable to reserves subject to participation interests, overriding royalty interests or other interests of third parties, pursuant to participation, partnership, vendor financing or other agreements then in effect, or which otherwise are required to be delivered to third parties;
(4): the discounted future net revenue calculated in accordance with SEC guidelines (utilizing the same prices utilized in the Company's year-end reserve report), attributable to reserves that 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 on the schedules specified with respect thereto; and
(5): the discounted future net revenue, calculated in accordance with SEC guidelines, attributable to reserves subject to Dollar-Denominated Production Payments that, based on the estimates of production included in determining the discounted future net revenue specified in the immediately preceding clause (a) (1) (utilizing the same prices utilized in the Company's year-end reserve report), would be necessary to satisfy fully the obligations of the Company and its Restricted Subsidiaries with respect to Dollar-Denominated Production Payments on the schedules specified with respect thereto.

Whether or not the Company uses the successful efforts method of accounting or the full cost (or similar method) method of accounting, ACNTA will be calculated as if the Company were using the full cost (or similar method) method of accounting.

"Affiliate" of any specified Person means any other Person, directly or indirectly, controlling or controlled by or under direct or indirect common control with such specified Person. For the purposes of this definition, "control" when used with respect to any 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 to the foregoing. For purposes of the covenants described under "—Certain Covenants—Limitation on Restricted Payments", "—Certain Covenants—Limitation on Affiliate Transactions" and "—Certain Covenants—Limitation on Sales of Assets and Subsidiary Stock" only, "Affiliate" shall also mean any beneficial owner of Capital Stock representing 10% or more of the total voting power of the Voting Stock (on a fully diluted basis) of the Company or Parent or of rights or warrants to purchase such Capital Stock (whether or not currently exercisable) and any Person who would be an Affiliate of any such beneficial owner pursuant to the first sentence hereof.

"Applicable Indebtedness" means:

(1): in respect of any asset that is the subject of an Asset Disposition at a time when such asset is included in the Collateral, Senior Indebtedness or Indebtedness of a Subsidiary or any other non-debt obligation that, in each case, is secured at such time by Collateral under a Lien that takes priority over the Lien in respect of the notes under the Pledge Agreement; or
(2): in respect of any asset that is the subject of an Asset Disposition at a time when such asset is not included in the Collateral but is owned, directly or indirectly, by a Foreign Subsidiary the stock of which is included in the Collateral, any Indebtedness or other obligation referred to in clause (1) above, any Indebtedness of such Foreign Subsidiary or any Indebtedness of any other Foreign Subsidiary; provided, however, that such Foreign Subsidiary has not guaranteed unsecured Indebtedness of the Company or a Subsidiary Guarantor; or
(3): in respect of any other asset, Senior Indebtedness.

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"Applicable Senior Indebtedness" means:

(1): in respect of any asset that is the subject of an Asset Disposition at a time when such asset is included in the Collateral, Senior Indebtedness that is secured at such time by Collateral; or
(2): in respect of any asset that is the subject of an Asset Disposition at a time when such asset is not included in the Collateral but is owned, directly or indirectly, by a Foreign Subsidiary the stock of which is included in the Collateral, Senior Indebtedness that is secured at such time by Collateral or Senior Indebtedness of such Foreign Subsidiary; or
(3): in respect of any other asset, Senior Indebtedness.

"Asset Disposition" means any sale, lease, transfer or other disposition (or series of related sales, leases, transfers or dispositions) by the Company or any Restricted Subsidiary, including any disposition by means of a merger, consolidation or similar transaction (each referred to for the purposes of this definition as a "disposition"), of:

(1): any shares of Capital Stock of a Restricted Subsidiary (other than directors' qualifying shares or shares required by applicable law to be held by a Person other than the Company or a Restricted Subsidiary);
(2): all or substantially all the assets of any division or line of business of the Company or any Restricted Subsidiary; or
(3): any other assets of the Company or any Restricted Subsidiary outside of the ordinary course of business of the Company or such Restricted Subsidiary

(other than, in the case of clauses (1), (2) and (3) above,

(A): a disposition by a Restricted Subsidiary to the Company or by the Company or a Restricted Subsidiary to a Restricted Subsidiary;
(B): for purposes of the covenant described under "—Certain Covenants—Limitation on Sales of Assets and Subsidiary Stock" only, (i) a disposition (other than a disposition of Collateral) that constitutes a Restricted Payment (or would constitute a Restricted Payment but for the exclusions from the definition thereof) and that is not prohibited by the covenant described under "—Certain Covenants—Limitation on Restricted Payments" and (ii) a disposition, other than a Permitted MLP Transaction, of all or substantially all the assets of the Company in accordance with the covenant described under "—Certain Covenants—Merger and Consolidation";
(C): a disposition of assets (other than any assets that constitute Collateral) in a single transaction or a series of related transactions with a fair market value of less than $2.0 million;
(D): a disposition of cash or Temporary Cash Investments;
(E): the trade or exchange, other than a Permitted MLP Transaction, by the Company or any Restricted Subsidiary of any oil or natural gas property or interest therein of the Company or such Restricted Subsidiary for any oil or natural gas property or interest therein of another Person or for the Capital Stock of a Person engaged in the Oil and Gas Business, including any cash or cash equivalents necessary in order to achieve an exchange of equivalent value; provided, however, that the value of the oil or natural gas property or interest therein received by the Company or any Restricted Subsidiary in such trade or exchange (including any cash or cash equivalents) is at least equal to the fair market value (as determined in good faith by the Board of Directors, which determination shall be conclusive evidence of compliance with this provision) of the oil or

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natural gas property or interest therein or Capital Stock of a Person engaged in the Oil and Gas Business (including any cash or cash equivalents) so traded or exchanged; and

(F): the creation of a Lien (but not the sale or other disposition of the property subject to such Lien)).

For purposes of the covenant described under "—Certain Covenants—Limitation on Sales of Assets and Subsidiary Stock" only, the disposition of Capital Stock of a Person will be treated as a disposition of all Collateral owned by such Person if after giving effect to such disposition of such Capital Stock, the Company and the Restricted Subsidiaries do not control such Person.

"Attributable Debt" 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, compounded 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); provided, however, that if such Sale/Leaseback Transaction results in a Capital Lease Obligation, the amount of Indebtedness represented thereby will be determined in accordance with the definition of "Capital Lease Obligation".

"Average Life" means, as of the date of determination, with respect to any Indebtedness, 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 or redemption or similar payment with respect to such Indebtedness multiplied by the amount of such payment by
(2): the sum of all such payments.

"Board of Directors" means the Board of Directors of the Company or any committee thereof duly authorized to act on behalf of such Board.

"Business Day" means each day which is not a Legal Holiday.

"Capital Lease Obligation" means an obligation that is required to be classified and accounted for as a capital lease for financial reporting purposes in accordance with GAAP, and the amount of Indebtedness represented by such obligation shall be the capitalized amount of such obligation determined in accordance with GAAP; and the Stated Maturity thereof shall be the date of the last payment of rent or any other amount due under such lease prior to the first date upon which such lease may be terminated by the lessee without payment of a penalty. For purposes of the covenant described under "—Certain Covenants—Limitation on Liens", a Capital Lease Obligation will be deemed to be secured by a Lien on the property being leased.

"Capital Stock" of any Person means any and all shares, interests (including partnership interests), rights to purchase, warrants, options, participations 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.

"Code" means the Internal Revenue Code of 1986, as amended.

"Collateral" means all the collateral provided for and described in the Pledge Agreement.

"Collateral Agent" means Wilmington Trust Company, in its capacity as collateral agent for the Noteholders, until a successor replaces it and, thereafter, means the successor.

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"Consolidated Coverage Ratio" as of any date of determination means the ratio of (a) the aggregate amount of EBITDA for the period of the most recent four consecutive fiscal quarters ending at least 45 days prior to the date of such determination to (b) Consolidated Interest Expense for such four fiscal quarters; provided, however, that:

(1): if the Company or any Restricted Subsidiary has Incurred any Indebtedness since the beginning of such period that remains outstanding or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio is an Incurrence of Indebtedness, or both, EBITDA and Consolidated Interest Expense for such period shall 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;
(2): if the Company or any Restricted Subsidiary has repaid, repurchased, defeased or otherwise discharged any Indebtedness since the beginning of such period or if any Indebtedness is to be repaid, repurchased, defeased or otherwise discharged (in each case other than Indebtedness Incurred under any revolving credit facility unless such Indebtedness has been permanently repaid and has not been replaced) on the date of the transaction giving rise to the need to calculate the Consolidated Coverage Ratio, EBITDA and Consolidated Interest Expense for such period shall be calculated on a pro forma basis as if such discharge had occurred on the first day of such period and as if the Company or such Restricted Subsidiary has not earned the interest income actually earned during such period in respect of cash or Temporary Cash Investments used to repay, repurchase, defease or otherwise discharge such Indebtedness;
(3): if since the beginning of such period the Company or any Restricted Subsidiary shall have made any Asset Disposition, EBITDA for such period shall be reduced by an amount equal to 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 EBITDA (if negative), directly attributable thereto for such period and Consolidated Interest Expense for such period shall 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 the 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 the continuing Restricted Subsidiaries are no longer liable for such Indebtedness after such sale);
(4): 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 an acquisition of assets, including any acquisition of assets occurring in connection with a transaction requiring a calculation to be made hereunder, which constitutes all or substantially all of an operating unit of a business, EBITDA and Consolidated Interest Expense for such period shall 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
(5): 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 made any Asset Disposition, any Investment or acquisition of assets that would have required an adjustment pursuant to clause (3) or (4) above if made by the Company or a Restricted Subsidiary during such period, EBITDA and Consolidated Interest Expense for such period shall be calculated after giving pro forma

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effect thereto as if such Asset Disposition, Investment or acquisition occurred on the first day of such period.

For purposes of this definition, whenever pro forma effect is to be given to an acquisition of assets, the amount of income or earnings relating thereto and the amount of Consolidated Interest Expense associated with any Indebtedness Incurred in connection therewith, the pro forma calculations shall be determined in good faith by a responsible financial or accounting Officer of the Company. If any Indebtedness bears a floating rate of interest and is being given pro forma effect, the interest on such Indebtedness shall 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, but if the remaining term of such Interest Rate Agreement is less than 12 months, then such Interest Rate Agreement shall only be taken into account for that portion of the period equal to the remaining term thereof).

If any Indebtedness is incurred under a revolving credit facility and is being given pro forma effect, the interest on such Indebtedness shall be calculated based on the average daily balance of such Indebtedness for the four fiscal quarters subject to the pro forma calculation to the extent that such Indebtedness was incurred solely for working capital purposes.

"Consolidated Interest Expense" means, for any period, the total interest expense of the Company and the consolidated Restricted Subsidiaries, plus, to the extent not included in such total interest expense, and to the extent incurred by the Company or the Restricted Subsidiaries, without duplication:

(1): interest expense attributable to Capital Lease Obligations;
(2): amortization of debt discount and debt issuance cost;
(3): capitalized interest;
(4): non-cash interest expense;
(5): commissions, discounts and other fees and charges owed with respect to letters of credit and bankers' acceptance financing;
(6): net payments pursuant to Currency Agreements and Interest Rate Agreements;
(7): dividends accrued in respect of all Preferred Stock held by Persons other than the Company or a Wholly Owned Subsidiary (other than dividends payable solely in Capital Stock (other than Disqualified Stock) of the Company); provided, however, that such dividends will be multiplied by a fraction the numerator of which is one and the denominator of which is one minus the effective combined tax rate of the issuer of such Preferred Stock (expressed as a decimal) for such period (as estimated by the chief financial officer of the Company in good faith);
(8): interest incurred in connection with Investments in discontinued operations;
(9): interest accruing on any Indebtedness of any other Person to the extent such Indebtedness is Guaranteed by (or secured by the assets of) the Company or any Restricted Subsidiary; 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;

provided, however, that there shall be excluded from Consolidated Interest Expense (A) any non-cash amortization or write-off of fees and expenses incurred in connection with the Transactions and (B) dividends and distributions in respect of the master limited partnership interests, general partnership interests, limited liability company interests or royalty trust interests, as the case may be, in the MLP Subsidiary.

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"Consolidated Net Income" means, for any period, the net income of the Company and its consolidated Subsidiaries; provided, however, that there shall not be included in such Consolidated Net Income:

(1)

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

(A): subject to the exclusion contained in clause (5) below, the Company's equity in the net income of any such Person for such period shall 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 paid to a Restricted Subsidiary, to the limitations contained in clause (3) below); and
(B): the Company's equity in a net loss of any such Person for such period shall be included in determining such Consolidated Net Income;

(2)

any net income (or loss) of any Person acquired by the Company or a Subsidiary in a pooling of interests transaction (or any transaction accounted for in a manner similar to a pooling of interests) for any period prior to the date of such acquisition;

(3)

any net income of any Restricted Subsidiary (other than the MLP Subsidiary) if such Restricted 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 exclusion contained in clause (5) below, the Company's equity in the net income of any such Restricted Subsidiary for such period shall be included in such Consolidated Net Income up to the aggregate amount of cash actually distributed (or, if greater, for purposes of calculation of the Consolidated Coverage Ratio only, permitted at the date of determination to be distributed) by such Restricted Subsidiary during such period to the Company or another Restricted Subsidiary as a dividend or other distribution (subject, in the case of a dividend or other distribution paid to another 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 shall be included in determining such Consolidated Net Income;

(4)

any net income of the MLP Subsidiary, except that:

(A): subject to the exclusion contained in clause (5) below, the Company's equity in the net income of the MLP Subsidiary for such period shall be included in such Consolidated Net Income up to the aggregate amount of cash permitted at the date of determination to be distributed by the MLP Subsidiary during such period to the Company or another Restricted Subsidiary as a dividend or other distribution (subject, in the case of a dividend or other distribution paid to another Restricted Subsidiary, to the limitation contained in clause (3) above); and
(B): the Company's equity in a net loss of the MLP Subsidiary for such period shall be included in determining such Consolidated Net Income;

(5)

any gain (or loss) realized upon the sale or other disposition of any assets of the Company, its consolidated Subsidiaries or any other Person (including pursuant to any sale-and-leaseback arrangement) which are not sold or otherwise disposed of in the ordinary course of business and any gain (or loss) realized upon the sale or other disposition of any Capital Stock of any Person;

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(6): any impairment losses on oil and natural gas properties;
(7): extraordinary gains or losses;
(8): any unrealized non-cash gains or losses or charges in respect of Hedging Obligations (including those resulting from the application of FAS 133);
(9): any non-cash compensation charge arising from any grant of stock, stock options or other equity-based awards; and
(10): the cumulative effect of a change in accounting principles;

in each case, for such period. Notwithstanding the foregoing, for the purposes of the covenant described under "—Certain Covenants—Limitation on Restricted Payments" only (but not the calculation of the Consolidated Coverage Ratio for purposes of determining compliance with such covenant), there shall be excluded from Consolidated Net Income any repurchases, repayments or redemptions of Investments, proceeds realized on the sale of Investments or return of capital to the Company or a Restricted Subsidiary to the extent such repurchases, repayments, redemptions, proceeds or returns increase the amount of Restricted Payments permitted under such covenant pursuant to clause (a)(3)(D) thereof.

"Credit Agreement" means (i) the Second Amended and Restated Credit Agreement among Parent, the Company, certain of the Company's Subsidiaries, the lenders referred to therein, Bank One, NA, as Administrative Agent, BNP Paribas and JPMorgan Chase Bank, as Co-Syndication Agents, The Bank of Nova Scotia and Toronto-Dominion (Texas), as Co-Documentation Agents, and Banc One Capital Markets, Inc., as Lead Arranger and Sole Bookrunner, (ii) the Second Amended and Restated Credit Agreement, dated as of July 29, 2003 by and among Addison Energy Inc., the institutions named therein as lenders, Bank One, NA, Canada Branch, as Administrative Agent, BNP Paribas (Canada) and JPMorgan Chase Bank, Toronto Branch, as Co-Syndication Agents, The Bank of Nova Scotia and The Toronto-Dominion Bank, as Co-Documentation Agents, and Banc One Capital Markets, Inc., as Lead Arranger and Bookrunner, and (iii) the Credit Agreement among North Coast Energy, Inc., the lenders referred to therein and Union Bank of California, N.A., as Agent, in each case with respect to the foregoing clauses (i) through (iii), together with the related documents thereto (including the term loans and revolving loans thereunder, any guarantees and security documents), as amended, extended, renewed, restated, supplemented or otherwise modified (in whole or in part, and without limitation as to amount, terms, conditions, covenants and other provisions, including increasing the amount of available borrowings thereunder or adding Subsidiaries of Parent as additional borrowers or guarantors thereunder) from time to time, and any agreement (and related document) governing Indebtedness incurred to Refinance but without limitation as to borrowers or guarantors, in whole or in part, the borrowings and commitments then outstanding or permitted to be outstanding under such Credit Agreement or a successor Credit Agreement, whether by the same or any other lender or group of lenders.

"Credit Facilities" means the revolving credit facilities contained in the Credit Agreement and any other facilities or financing arrangements that Refinance, in whole or in part, any such revolving credit facilities.

"Currency Agreement" means any foreign exchange contract, currency swap agreement or other similar agreement with respect to currency values.

"Default" means any event which is, or after notice or passage of time or both would be, an Event of Default.

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

(1): matures or is mandatorily redeemable (other than redeemable only for Capital Stock of such Person which is not itself Disqualified Stock) pursuant to a sinking fund obligation or otherwise;
(2): is convertible or exchangeable at the option of the holder for Indebtedness or Disqualified Stock; or
(3): is mandatorily redeemable or must be purchased upon the occurrence of certain events or otherwise, in whole or in part;

in each case on or prior to the 91st day after the Stated Maturity of the notes; provided, however, that any Capital Stock that would not constitute Disqualified Stock but for provisions thereof giving holders thereof the right to require such Person to purchase or redeem such Capital Stock upon the occurrence of an "asset sale" or "change of control" occurring prior to the 91st day after the Stated Maturity of the notes shall not constitute Disqualified Stock if:

(1): the "asset sale" or "change of control" provisions applicable to such Capital Stock are not more favorable to the holders of such Capital Stock than the terms applicable to the notes and described under "—Certain Covenants—Limitation on Sales of Assets and Subsidiary Stock" and "—Certain Covenants—Change of Control"; and
(2): any such requirement only becomes operative after compliance with such terms applicable to the notes, including the purchase of any notes tendered pursuant thereto.

The amount of any Disqualified Stock that does not have a fixed redemption, repayment or repurchase price will be calculated in accordance with the terms of such Disqualified Stock as if such Disqualified Stock were redeemed, repaid or repurchased on any date on which the amount of such Disqualified Stock is to be determined pursuant to the Indenture; provided, however, that if such Disqualified Stock could not be required to be redeemed, repaid or repurchased at the time of such determination, the redemption, repayment or repurchase price will be the book value of such Disqualified Stock as reflected in the most recent financial statements of such Person.

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

"EBITDA" for any period means the sum of Consolidated Net Income, plus the following to the extent deducted in calculating such Consolidated Net Income:

(1): all income tax expense of the Company and the consolidated Restricted Subsidiaries;
(2): Consolidated Interest Expense;
(3): depreciation, depletion, exploration and amortization expense of the Company and the consolidated Restricted Subsidiaries (excluding amortization expense attributable to a prepaid operating activity item that was paid in cash in a prior period); and
(4): all other non-cash charges of the Company and the consolidated Restricted Subsidiaries (excluding any such non-cash charge to the extent that it represents an accrual of or reserve for cash expenditures in any future period other than non-cash charges resulting from the application of FAS 143);

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in each case for such period, and less, to the extent included in calculating such Consolidated Net Income and in excess of any costs or expenses attributable thereto and deducted in calculating such Consolidated Net Income, the sum of:

(A): the amount of deferred revenues that are amortized during such period and are attributable to reserves that are subject to Volumetric Production Payments; and
(B): amounts recorded in accordance with GAAP as repayments of principal and interest pursuant to Dollar-Denominated Production Payments.

Notwithstanding the foregoing, the provision for taxes based on the income or profits of, and the depreciation and amortization and non- cash charges of, a Restricted Subsidiary shall be added to Consolidated Net Income to compute EBITDA only to the extent (and in the same proportion, including by reason of minority interests) that the net income or loss of such Restricted Subsidiary was included in calculating Consolidated Net Income and only if a corresponding amount would be permitted at the date of determination to be dividended to the Company by such Restricted Subsidiary without prior approval (that has not been obtained), pursuant to the terms of its charter and all agreements, instruments, judgments, decrees, orders, statutes, rules and governmental regulations applicable to such Restricted Subsidiary or its stockholders.

"Exchange Act" means the U.S. Securities Exchange Act of 1934, as amended.

"First Lien Obligations" means (1) all Indebtedness Incurred by Parent, the Company and its Subsidiaries pursuant to clause (b)(1) or (b)(15) of the covenant described under the caption "—Limitation on Indebtedness" and secured by a Lien permitted under clause (7) or clause (20) of the definition of Permitted Liens, (2) all other Obligations (not constituting Indebtedness) of Parent, the Company and its Subsidiaries under the agreements governing such Indebtedness and (3) all other Obligations of Parent, the Company and its Subsidiaries in respect of Hedging Obligations or Obligations in respect of cash management services in connection with such first lien Indebtedness.

"Foreign Subsidiary" means any Restricted Subsidiary of the Company that is not organized under the laws of the United States of America or any State thereof or the District of Columbia.

"GAAP" means generally accepted accounting principles in the United States of America as in effect as of the Issue Date, including those set forth in:

(1): the opinions and pronouncements of the Accounting Principles Board of the American Institute of Certified Public Accountants;
(2): statements and pronouncements of the Financial Accounting Standards Board;
(3): such other statements by such other entity as approved by a significant segment of the accounting profession; and
(4): the rules and regulations of the SEC governing the inclusion of financial statements (including pro forma financial statements) in periodic reports required to be filed pursuant to Section 13 of the Exchange Act, including opinions and pronouncements in staff accounting bulletins and similar written statements from the accounting staff of the SEC.

"Guarantee" means any obligation, contingent or otherwise, of any Person directly or indirectly guaranteeing any Indebtedness of any 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 Person (whether arising by virtue of partnership arrangements, or by agreements to keep-well, to purchase assets, goods, securities or services, to take-or-pay or to maintain financial statement conditions or otherwise); or

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(2): entered into for the purpose 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" shall not include endorsements for collection or deposit in the ordinary course of business. The term "Guarantee" used as a verb has a corresponding meaning. The term "Guarantor" shall mean any Person Guaranteeing any obligation.

"Guaranty Agreement" means a supplemental indenture, in a form satisfactory to the Trustee, pursuant to which a Subsidiary Guarantor guarantees the Company's obligations with respect to the notes on the terms provided for in the Indenture.

"Hedging Obligations" of any Person means the obligations of such Person pursuant to any Oil and Natural Gas Hedging Contract, Interest Rate Agreement or Currency Agreement.

"Holder" or "Noteholder" means the Person in whose name a note is registered on the Registrar's books.

"Incur" means issue, assume, Guarantee, incur or otherwise become liable for; provided, however, that any Indebtedness of a Person existing at the time such Person becomes a Restricted Subsidiary (whether by merger, consolidation, acquisition or otherwise) shall be deemed to be Incurred by such Person at the time it becomes a Restricted Subsidiary. The term "Incurrence" when used as a noun shall have a correlative meaning. Solely for purposes of determining compliance with "—Certain Covenants—Limitation on Indebtedness":

(1): amortization of debt discount or the accretion of principal with respect to a non-interest bearing or other discount security;
(2): the payment of regularly scheduled interest in the form of additional Indebtedness of the same instrument or the payment of regularly scheduled dividends on Capital Stock in the form of additional Capital Stock of the same class and with the same terms;
(3): the obligation to pay a premium in respect of Indebtedness arising in connection with the issuance of a notice of redemption or making of a mandatory offer to purchase such Indebtedness; and
(4): unrealized losses or charges in respect of Hedging Obligations (including those resulting from the application of FAS 133)

will not be deemed to be the Incurrence of Indebtedness.

"Indebtedness" means, with respect to any Person on any date of determination (without duplication):

(1): the principal in respect of (A) indebtedness of such Person for money borrowed and (B) indebtedness evidenced by notes, debentures, bonds or other similar instruments for the payment of which such Person is responsible or liable, including, in each case, any premium on such indebtedness to the extent such premium has become due and payable;
(2): all Capital Lease Obligations of such Person and all Attributable Debt in respect of Sale/Leaseback Transactions entered into by such Person;
(3): all obligations of such Person issued or assumed as the deferred purchase price of property, all conditional sale obligations of such Person and all obligations of such Person under any title retention agreement (but excluding trade accounts payable arising in the ordinary course of business);

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(4): all obligations of such Person for the reimbursement of any obligor on any letter of credit, bankers' acceptance or similar credit transaction (other than obligations with respect to letters of credit securing obligations (other than obligations described in clauses (1) through (3) above) entered into in the ordinary course of business of such Person to the extent such letters of credit are not drawn upon or, if and to the extent drawn upon, such drawing is reimbursed no later than the tenth Business Day following payment on the letter of credit);
(5): the amount of all obligations of such Person with respect to the redemption, repayment or other repurchase of any Disqualified Stock of such Person or, with respect to any Subsidiary of such Person the amount of all obligations of such Subsidiary with respect to any Preferred Stock of such Subsidiary, the principal amount of such Disqualified Stock or Preferred Stock to be determined in accordance with the Indenture;
(6): all obligations of the type referred to in clauses (1) through (5) of other Persons and all dividends of other Persons for the payment of which, in either case, such Person is responsible or liable, directly or indirectly, as obligor, guarantor or otherwise, including by means of any Guarantee;
(7): all obligations of the type referred to in clauses (1) through (6) of other Persons secured by any Lien on any property or asset of such Person (whether or not such obligation is assumed by such Person), the amount of such obligation being deemed to be the lesser of the value of such property or assets and the amount of the obligation so secured;
(8): to the extent not otherwise included in this definition, Hedging Obligations of such Person; and
(9): any Guarantee by such Person of production or payment with respect to a Production Payment.

Except as expressly provided in clause (9) above, Production Payments and Reserve Sales shall not constitute "Indebtedness".

Notwithstanding the foregoing, (A) in connection with the purchase by the Company or any Restricted Subsidiary of any business or assets, the term "Indebtedness" will exclude post-closing payment adjustments to which the seller may become entitled to the extent such payment is determined by a final closing balance sheet or such payment depends on the performance of such business or assets after the closing; provided, however, that, at the time of closing, the amount of any such payment is not determinable and, to the extent such payment thereafter becomes fixed and determined, the amount is paid within 30 days thereafter and (B) following a Permitted MLP Transaction, the term "Indebtedness" will exclude the master limited partnership interests, general partnership interests, limited liability company interests or royalty trust interests, as the case may be, in the MLP Subsidiary.

The amount of Indebtedness of any Person at any date shall be the outstanding balance at such date of all obligations as described above; provided, however, that in the case of Indebtedness sold at a discount, the amount of such Indebtedness at any time will be the accreted value thereof at such time.

"Independent Qualified Party" means an investment banking firm, accounting firm or appraisal firm of national standing; provided, however, that such firm is not an Affiliate of the Company.

"Intercreditor Agreement" means the Intercreditor Agreement, dated as of January 20, 2004, among the Trustee, Bank One, NA, the Company and the Subsidiary Guarantors, as it may be amended from time to time in accordance with the Indenture.

"Interest Rate Agreement" means any interest rate swap agreement, interest rate cap agreement or other financial agreement or arrangement with respect to exposure to interest rates.

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"Investment" in any Person means any direct or indirect advance, loan (other than advances to customers in the ordinary course of business that are recorded as accounts receivable on the balance sheet of the lender) or other extensions of credit (including by way of Guarantee or similar arrangement) or capital contribution to (by means of any transfer of cash or other property to others or any payment for property or services for the account or use of others), or any purchase or acquisition of Capital Stock, Indebtedness or other similar instruments issued by such Person. If the Company or any Restricted Subsidiary issues, sells or otherwise disposes of any Capital Stock of a Person that is a Restricted Subsidiary such that, after giving effect thereto, such Person is no longer a Restricted Subsidiary, the Company or any Restricted Subsidiary shall be deemed to have made an Investment on the date of such issuance, sale or other disposition equal to the fair market value of the Capital Stock of such Restricted Subsidiary not sold or disposed of or, if less, the value of the Investment when made by the Company or such Restricted Subsidiary in the portion of such Person represented by such Capital Stock. The acquisition by the Company or any Restricted Subsidiary of a Person that holds an Investment in a third Person will be deemed to be an Investment by the Company or such Restricted Subsidiary in such third Person at such time. Except as otherwise provided for herein, the amount of an Investment shall be its fair market value at the time the Investment is made and without giving effect to subsequent changes in value.

For purposes of the definition of "Unrestricted Subsidiary", the definition of "Restricted Payment" and the covenant described under "—Certain Covenants—Limitation on Restricted Payments":

(1): "Investment" shall include the portion (proportionate to the Company's equity interest in such Subsidiary) of the fair market value of the net assets of any Subsidiary of the Company at the time that such Subsidiary is designated an Unrestricted Subsidiary; and
(2): any property transferred to or from an Unrestricted Subsidiary shall 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.

"Issue Date" means January 20, 2004.

"Legal Holiday" means a Saturday, a Sunday or a day on which banking institutions are not required to be open in the State of New York.

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

"Material Change" means an increase or decrease (excluding changes that result solely from changes in prices and changes resulting from the incurrence of previously estimated development costs) of more than 50% during a fiscal quarter in the discounted future net revenues from proved oil and natural gas reserves of the Company and the Restricted Subsidiaries, calculated in accordance with clause (a)(1) of the definition of ACNTA; provided, however, that the following will be excluded from the calculation of Material Change:

(1): any acquisitions during the fiscal quarter of oil and natural gas reserves that have been estimated by independent petroleum engineers and with respect to which a report or reports of such engineers exist; and
(2): any disposition of properties existing at the beginning of such fiscal quarter that have been disposed of in compliance with the covenant described under "—Certain Covenants—Limitation on Sales of Assets and Subsidiary Stock".

"Merger" means the merger of NCE Acquisition, Inc. with and into North Coast Energy, Inc. pursuant to the Merger Agreement.

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"Merger Agreement" means the agreement and plan of merger dated as of November 26, 2003, among the Company, NCE Acquisition, Inc., North Coast Energy, Inc. and Nuon Energy & Water, as amended and restated on December 4, 2003.

"Merger Date" means the date the Merger is consummated.

"Moody's" means Moody's Investors Service, Inc. and any successor to its rating agency business.

"Net Available Cash" from an Asset Disposition means cash payments received therefrom (including any cash payments received by way of deferred payment of principal pursuant to a note or installment receivable or otherwise and cash proceeds from the sale or other disposition of any 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 such properties or assets or received in any other non-cash form), in each case net of (without duplication):

(1): all legal, title and recording tax expenses, commissions and other fees and expenses incurred, and all Federal, state, provincial, foreign and local taxes required to be accrued as a liability under GAAP, 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 or other security agreement of any kind with respect to 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 Restricted Subsidiaries as a result of such Asset Disposition;
(4): the deduction of appropriate amounts provided by the seller as a reserve, in accordance with GAAP, against any liabilities associated with the property or other assets disposed in such Asset Disposition and retained by the Company or any Restricted Subsidiary after such Asset Disposition; and
(5): any portion of the purchase price from an Asset Disposition placed in escrow, whether as a reserve for adjustment of the purchase price, for satisfaction of indemnities in respect of such Asset Disposition or otherwise in connection with that Asset Disposition; provided, however, that upon the termination of that escrow, Net Available Cash will be increased by any portion of funds in the escrow that are released to the Company or any Restricted Subsidiary.

"Net Cash Proceeds", with respect to any issuance or sale of Capital Stock or Indebtedness, means the cash proceeds of such issuance or sale net of attorneys' fees, accountants' fees, underwriters' or placement agents' fees, discounts or commissions and brokerage, consultant and other fees actually incurred in connection with such issuance or sale and net of taxes paid or payable as a result thereof.

"Net Working Capital" of the Company means:

(1): all current assets of the Company and its Restricted Subsidiaries, except current assets from commodity price risk management activities arising in the ordinary course of business; minus
(2): all current liabilities of the Company and its Restricted Subsidiaries, except current liabilities included in Indebtedness and current liabilities from commodity price risk management activities arising in the ordinary course of business, determined in accordance with GAAP.

"Obligations" means, with respect to any Indebtedness, all obligations for principal, premium, interest, penalties, fees, indemnifications, reimbursements, and other amounts payable pursuant to the documentation governing such Indebtedness.

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"Offering Circular" means the confidential offering circular dated January 14, 2004, used in connection with the offering of the old notes on the Issue Date.

"Officer" means the Chairman of the Board, the President, any Vice President, the Treasurer or the Secretary of the Company.

"Officers' Certificate" means a certificate signed by two Officers.

"Oil and Gas Business" means:

(1): the acquisition, exploration, exploitation, development, operation and disposition of interests in oil, natural gas, other hydrocarbon and mineral properties;
(2): the gathering, marketing, distribution, treating, processing, storage, refining, selling and transporting of any production from such interests or properties and the marketing of oil, natural gas, other hydrocarbons and minerals obtained from unrelated Persons;
(3): any business relating to or arising from exploration for or exploitation, development, production, treatment, processing, storage, refining, transportation, gathering or marketing of oil, natural gas, other hydrocarbons and minerals and products produced in association therewith;
(4): any other related energy business, including power generation and electrical transmission business where fuel required by such business is supplied, directly or indirectly, from oil, natural gas, other hydrocarbons and minerals produced substantially from properties in which the Company or the Restricted Subsidiaries, directly or indirectly, participate;
(5): any business relating to oil field sales and service; and
(6): any activity necessary, appropriate or incidental to the activities described in the preceding clauses (1) through (5) of this definition.

"Oil and Natural Gas Hedging Contract" means any oil and natural gas hedging agreement and other agreement or arrangement designed to protect the Company or any Restricted Subsidiary against fluctuations in oil and natural gas prices.

"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.

"Parent" means EXCO Holdings Inc., a Delaware corporation, and its successors.

"Parent Board" means the Board of Directors of Parent or any committee thereof duly authorized to act on behalf of such Board.

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"Permitted Business Investments" means Investments and expenditures made in the ordinary course of, and of a nature that is or shall have become customary in, the Oil and Gas Business as means of actively exploiting, exploring for, acquiring, developing, processing, gathering, marketing or transporting oil, natural gas, other hydrocarbons and minerals through agreements, transactions, interests or arrangements that 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, natural gas, other hydrocarbon and mineral properties or gathering, transportation, processing, storage or related systems; and
(2): entry into, and Investments and expenditures in the form of or pursuant to, operating agreements, joint venture agreements, partnership agreements, working interests, royalty interests, mineral leases, processing agreements, farm-in agreements, farm-out agreements, contracts for the sale, transportation or exchange of oil, natural gas, other hydrocarbons and minerals, production sharing agreements, development agreements, area of mutual interest agreements, unitization agreements, pooling arrangements, joint bidding agreements, service contracts and other similar agreements with third parties (including Unrestricted Subsidiaries).

"Permitted Collateral Debt" means (1) Refinancing Indebtedness in respect of the notes and (2) Refinancing Indebtedness in respect of First Lien Obligations.

"Permitted Holders" means any combination of Persons that beneficially own Capital Stock of Parent as of the Issue Date.

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

(1): the Company, a Restricted Subsidiary or a Person that will, upon the making of such Investment, become a Restricted Subsidiary; provided, however, that the primary business of such Restricted Subsidiary is a Related Business;
(2): another Person (A) 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 or (B) for consideration consisting solely of Capital Stock of the Company; provided, however, that, in both cases, such Person's primary business is a Related Business;
(3): cash and Temporary Cash Investments;
(4): receivables owing to the Company or any Restricted Subsidiary if created or acquired in the ordinary course of 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 made in the ordinary course of business consistent with past practices of the Company or such Restricted Subsidiary;
(7): 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;
(8): any Person to the extent such Investment represents the non-cash portion of the consideration received for (A) an Asset Disposition as permitted pursuant to the covenant described under

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"—Certain Covenants—Limitation on Sales of Assets and Subsidiary Stock" or (B) a disposition of assets not constituting an Asset Disposition;

(9): any Person where such Investment was acquired by the Company or any of the Restricted Subsidiaries (A) in exchange for any other Investment or accounts receivable held by the Company or any such Restricted Subsidiary in connection with or as a result of a bankruptcy, workout, reorganization or recapitalization of the issuer of such other Investment or accounts receivable or (B) as a result of a foreclosure by the Company or any of the Restricted Subsidiaries with respect to any secured Investment or other transfer of title with respect to any secured Investment in default;
(10): any Person to the extent such Investments consist of prepaid expenses, negotiable instruments held for collection and lease, utility and workers' compensation, performance and other similar deposits made in the ordinary course of business by the Company or any Restricted Subsidiary;
(11): any Person to the extent such Investments consist of Hedging Obligations otherwise permitted under the covenant described under "—Certain Covenants—Limitation on Indebtedness";
(12): any Person to the extent such Investment exists on the Issue Date, and any extension, modification or renewal of any such Investments existing on the Issue Date, but only to the extent not involving additional advances, contributions or other Investments of cash or other assets or other increases thereof (other than as a result of the accrual or accretion of interest or original issue discount or the issuance of pay-in-kind securities, in each case, pursuant to the terms of such Investment as in effect on the Issue Date);
(13): Permitted Business Investments;
(14): Guarantees of performance or other obligations (other than Indebtedness) arising in the ordinary course in the Oil and Gas Business, including obligations under oil and natural gas exploration, development, joint operating and related agreements and licenses or concessions related to the Oil and Gas Business;
(15): Persons to the extent such Investments, when taken together with all other Investments made pursuant to this clause (15) outstanding on the date such Investment is made, do not exceed $20.0 million.

"Permitted Liens" means, with respect to any Person:

(1): pledges or deposits by such Person under worker's compensation laws, unemployment insurance laws or similar legislation, or good faith 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 or statutory obligations of such Person or deposits of cash or United States government bonds to secure surety or appeal bonds to which such Person is a party, or deposits as security for contested taxes or import duties or for the payment of rent, in each case Incurred in the ordinary course of business;
(2): Liens imposed by law, such as carriers', warehousemen's and mechanics' Liens, in each case for sums not yet due or being contested in good faith by appropriate proceedings or other Liens arising out of judgments or awards against such Person with respect to which such Person shall then be proceeding with an appeal or other proceedings for review and Liens arising solely by virtue of any statutory or common law provision relating to banker's Liens, rights of set-off or similar rights and remedies as to deposit accounts or other funds maintained with a creditor depository institution; provided, however, 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

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

(3): Liens for property taxes not yet subject to penalties for non-payment or which are being contested in good faith by appropriate proceedings;
(4): Liens in favor of issuers of performance, bid or surety bonds, completion guarantees or letters of credit 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;
(5): survey exceptions, encumbrances, easements or reservations of, or rights of others for, licenses, rights-of-way, sewers, electric lines, telegraph and telephone lines and other similar purposes, or zoning or other restrictions as to the use of real property or Liens incidental to the conduct of the business of such Person or to the ownership of its properties which were not Incurred in connection with Indebtedness and 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;
(6): Liens securing Indebtedness Incurred to finance the construction, purchase or lease of, or repairs, improvements or additions to, property, plant or equipment of such Person; provided, however, that the Lien may not extend to any other property owned by such Person or any of its Restricted Subsidiaries at the time the Lien is Incurred (other than assets and property affixed or appurtenant thereto), and the Indebtedness (other than any interest thereon) secured by the Lien may not be Incurred more than 180 days after the later of the acquisition, completion of construction, repair, improvement, addition or commencement of full operation of the property subject to the Lien;
(7): Liens to secure Indebtedness permitted under the provisions described in clause (b)(1) under "—Certain Covenants—Limitation on Indebtedness" and any of the First Lien Obligations;
(8): Liens existing on the Issue Date;
(9): Liens on property or shares of Capital Stock of another Person at the time such other Person becomes a Subsidiary of such Person; provided, however, that the Liens may not extend to any other property owned by such Person or any of its Restricted Subsidiaries (other than assets and property affixed or appurtenant thereto);
(10): Liens on property at the time such Person or any of its Subsidiaries acquires the property, including any acquisition by means of a merger or consolidation with or into such Person or a Subsidiary of such Person; provided, however, that the Liens may not extend to any other property owned by such Person or any of its Restricted Subsidiaries (other than assets and property affixed or appurtenant thereto);
(11): Liens securing Indebtedness or other obligations of a Subsidiary of such Person owing to such Person or a Restricted Subsidiary of such Person;
(12): Liens securing Hedging Obligations so long as such Hedging Obligations relate to Indebtedness that is, and is permitted to be under the Indenture, secured by a Lien on the same property securing such Hedging Obligations;
(13): Liens on, or related to, assets to secure all or part of the costs incurred in the ordinary course of the Oil and Gas Business for the exploration, drilling, development, production, processing, transportation, marketing, storage or operation thereof;
(14): Liens on pipeline or pipeline facilities that arise under operation of law;

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(15)

Liens arising in the ordinary course of business under operating agreements, joint venture agreements, partnership agreements, oil, natural gas, other hydrocarbon and mineral leases, farm-out or farm-in agreements, division orders, contracts for the sale, transportation or exchange of oil or natural gas, unitization and pooling declarations and agreements, area of mutual interest agreements and other agreements that are customary in the Oil and Gas Business and Liens securing Production Payments and Reserve Sales that are not prohibited by the Indenture; provided, however, that such Liens do not extend to any property other than the property that is the subject of such Production Payments and Reserve Sales;

(16)

Liens reserved in oil, natural gas, other hydrocarbon and mineral leases for bonus or rental payments and for compliance with the terms of such leases;

(17)

Liens to secure any Refinancing (or successive Refinancings) as a whole, or in part, of any Indebtedness secured by any Lien referred to in the foregoing clause (6), (8), (9) or (10); provided, however, that:

(A): such new Lien shall be limited to all or part of the same property and assets that secured or, under the written agreements pursuant to which the original Lien arose, could secure the original Lien (plus improvements and accessions to, such property or proceeds or distributions thereof); and
(B): the Indebtedness secured by such Lien at such time is not increased to any amount greater than the sum of (i) the outstanding principal amount or, if greater, committed amount of the Indebtedness described under clause (6), (8), (9) or (10) at the time the original Lien became a Permitted Lien and (ii) an amount necessary to pay any fees and expenses, including premiums, related to such refinancing, refunding, extension, renewal or replacement;

(18)

Liens upon the Collateral securing the notes and any Additional Notes, if any;

(19)

Liens securing Indebtedness of a Foreign Subsidiary other than Addison Energy Inc. permitted to be Incurred under "—Certain Covenants—Limitations on Indebtedness"; provided, however, that such Liens do not extend to any property not owned by such Foreign Subsidiary;

(20)

Liens to secure Indebtedness permitted under the provisions described in clauses (b)(15) and (b)(16) under "—Certain Covenants—Limitation on Indebtedness"; provided, however, that Liens to secure Indebtedness Incurred pursuant to such clause (b)(15) do not extend to any property other then property of such MLP Subsidiary and its Subsidiaries; and

(21)

In addition to Liens permitted by clauses (1) through (20) above, Liens that are incurred in the ordinary course of business of the Company or any Restricted Subsidiary with respect to Indebtedness and other obligations that do not exceed $10.0 million at any time outstanding.

In each case set forth above, notwithstanding any stated limitation on the assets that may be subject to such Lien, a Permitted Lien on a specified asset or group or type of assets may include Liens on all improvements, additions and accessions thereto and all products and proceeds thereof.

Notwithstanding the foregoing, "Permitted Liens" will not include any Lien described in clause (6), (9) or (10) above to the extent such Lien applies to any Additional Assets acquired directly or indirectly from Net Available Cash pursuant to the covenant described under "—Certain Covenants—Limitation on Sale of Assets and Subsidiary Stock". For purposes of this definition, the term "Indebtedness" shall be deemed to include interest on such Indebtedness.

"Permitted MLP Transaction" means, on one occasion only, the sale, transfer or other disposition of all, substantially all or a substantial portion of the assets of the Company (determined on a consolidated basis) to one or more newly formed master limited partnerships, limited liability

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companies or royalty trusts (collectively, the "MLP Subsidiary"); provided, however, that (1) at the time of, and at all times following, such sale, transfer or disposition, the Company is the managing general partner, managing member or operator, as the case may be, of the MLP Subsidiary and holds at least 40% of the master limited partnership interests, limited liability company interests or royalty trust interests, as the case may be, and a majority of the general partnership interests, if applicable, in the MLP Subsidiary, (2) on a pro forma basis for such sale, transfer or disposition, the notes are rated one level higher than their ratings immediately prior to such sale, transfer or other disposition (and, in any event, not less than one level higher than the notes were rated as of the Issue Date) by each of Moody's and Standard & Poor's, in each case, with no negative outlook, (3) the MLP Subsidiary at the time of, and at all times following such sale, transfer or disposition, is a Restricted Subsidiary, (4) there are no restrictions in the master limited partnership agreement, limited liability company agreement or royalty trust agreement, as the case may be, any other governing documents of the MLP Subsidiary, any debt instruments to which the MLP Subsidiary is a party or otherwise that limit or prevent the MLP Subsidiary from making any pro rata (based on ownership percentage) distributions to the Company (except in the case of receipt of a notice of default with respect to Indebtedness permitted to be Incurred by the MLP Subsidiary under the covenant described under "—Certain Covenants—Limitation on Indebtedness") and (5) on a pro forma basis after giving effect to such sale, transfer or disposition and assuming that (x) such sale, transfer or disposition had occurred at the beginning of the four consecutive fiscal quarters ended at least 45 days prior to the date of such sale, transfer or disposition, (y) none of the notes are purchased in the MLP Offer and (z) the Company had received in cash during such four fiscal quarter period its proportionate share (based on its ownership percentage of the MLP Subsidiary) of the consolidated net income of the MLP Subsidiary, the Company could Incur at least $1.00 of Indebtedness under paragraph (a) of the covenant described under "—Certain Covenants—Limitation on Indebtedness".

"Person" means any individual, corporation, partnership, limited liability company, joint venture, association, joint-stock company, trust, unincorporated organization, government or any agency or political subdivision thereof or any other entity.

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

"principal" of a note means the principal of the note plus the premium, if any, payable on the note which is due or overdue or is to become due at the relevant time.

"Production Payments and Reserve Sales" means the grant or transfer to any Person of a Dollar-Denominated Production Payment, Volumetric Production Payment, royalty, overriding royalty, net profits interest, master limited partnership interest or other interest in oil and natural gas properties, reserves or the right to receive all or a portion of the production or the proceeds from the sale of production attributable to such properties.

"Public Equity Offering" means an underwritten primary public offering of common stock of the Company or Parent pursuant to an effective registration statement under the Securities Act.

"Refinance" means, in respect of any Indebtedness, to refinance, extend, renew, refund, repay, prepay, purchase, redeem, defease or retire, or to issue other Indebtedness in exchange or replacement for, such Indebtedness. "Refinanced" and "Refinancing" shall have correlative meanings.

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"Refinancing Indebtedness" means Indebtedness that Refinances any Indebtedness of the Company or any Restricted Subsidiary existing on the Issue Date or Incurred in compliance with the Indenture, including Indebtedness that Refinances Refinancing Indebtedness; provided, however, that:

(1): such Refinancing Indebtedness has a Stated Maturity no earlier than the Stated Maturity of the Indebtedness being Refinanced;
(2): such 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 has an aggregate principal amount (or if Incurred with original issue discount, an aggregate issue price) that is equal to or less than the aggregate principal amount (or if Incurred with original issue discount, the aggregate accreted value) then outstanding (plus fees and expenses, including any premium and defeasance costs) under the Indebtedness being Refinanced; and
(4): if the Indebtedness being Refinanced is subordinated in right of payment to the notes, such Refinancing Indebtedness is subordinated in right of payment to the notes at least to the same extent as the Indebtedness being Refinanced;

provided further, however, that Refinancing Indebtedness shall not include (A) Indebtedness of a Subsidiary of the Company that Refinances Indebtedness of the Company or (B) Indebtedness of the Company or a Restricted Subsidiary that Refinances Indebtedness of an Unrestricted Subsidiary.

"Registration Rights Agreements" means (i) the Registration Rights Agreement dated January 20, 2004, among the Company, the Subsidiary Guarantors, Credit Suisse First Boston LLC, Banc One Capital Markets, Inc., Banc of America Securities LLC, BNP Paribas Securities Corp., Comerica Securities, Inc., Fleet Securities, Inc., Scotia Capital (USA) Inc. and TD Securities (USA) Inc. and (ii) the Registration Rights Agreement dated April 1, 2004, among the Company, the Subsidiary Guarantors, Credit Suisse First Boston LLC, Bank One Capital Markets, Inc., BNP Paribas Securities Corp., Comerica Securities Inc., Scotia Capital (USA) Inc. and TD Securities (USA) Inc.

"Related Business" means any Oil and Gas Business and any other business in which the Company or any of the Restricted Subsidiaries was engaged on the Issue Date and any business related, ancillary or complementary to such business.

"Restricted Payment" with respect to any Person means:

(1): the declaration or payment of any dividends or any other distributions of any sort in respect of its Capital Stock (including any payment in connection with any merger or consolidation involving such Person) or similar payment to the direct or indirect holders of its Capital Stock (other than (A) dividends or distributions payable solely in its Capital Stock (other than Disqualified Stock), (B) dividends or distributions payable solely to the Company or a Restricted Subsidiary and (C) pro rata dividends or other distributions made by a Subsidiary that is not a Wholly Owned Subsidiary to minority stockholders (or owners of an equivalent interest in the case of a Subsidiary that is an entity other than a corporation));
(2): the purchase, redemption or other acquisition or retirement for value of any Capital Stock of the Company or a Restricted Subsidiary held by any Affiliate of the Company (other than by a Restricted Subsidiary), including in connection with any merger or consolidation and including the exercise of any option to exchange any Capital Stock (other than into Capital Stock of the Company that is not Disqualified Stock);
(3): the purchase, repurchase, redemption, defeasance or other acquisition or retirement for value, prior to scheduled maturity, scheduled repayment or scheduled sinking fund payment of any

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Subordinated Obligations of the Company or any Subsidiary Guarantor (other than (A) from the Company or a Restricted Subsidiary or (B) the purchase, repurchase, redemption, defeasance or other acquisition of 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 such purchase, repurchase, redemption, defeasance or other acquisition); or

(4): the making of any Investment (other than a Permitted Investment) in any Person.

"Restricted Subsidiary" means any Subsidiary of the Company that is not an Unrestricted Subsidiary.

"Sale/Leaseback Transaction" means an arrangement relating to property owned by the Company or a Restricted Subsidiary on the Issue Date or thereafter acquired by the Company or a Restricted Subsidiary 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.

"SEC" means the U.S. Securities and Exchange Commission.

"Securities Act" means the U.S. Securities Act of 1933.

"Senior Indebtedness" means with respect to any Person:

(1): Indebtedness of such Person, whether outstanding on the Issue Date or thereafter Incurred; and
(2): all other Obligations of such Person (including interest accruing on or after the filing of any petition in bankruptcy or for reorganization relating to such Person whether or not post-filing interest is allowed in such proceeding) in respect of Indebtedness described in clause (1) above

unless, in the case of clauses (1) and (2), in the instrument creating or evidencing the same or pursuant to which the same is outstanding, it is provided that such Indebtedness or other obligations are subordinate in right of payment to the notes or the Subsidiary Guaranty of such Person, as the case may be; provided, however, that Senior Indebtedness shall not include:

(1): any obligation of such Person to the Company or any Subsidiary;
(2): any liability for Federal, state, local or other taxes owed or owing by such Person;
(3): any accounts payable or other liability to trade creditors arising in the ordinary course of business (including guarantees thereof or instruments evidencing such liabilities);
(4): any Indebtedness or other Obligation of such Person which is subordinate or junior in any respect to any other Indebtedness or other Obligation of such Person; or
(5): that portion of any Indebtedness which at the time of Incurrence is Incurred in violation of the Indenture.

"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.

"Specified Permitted Liens" means Permitted Liens, other than any Liens described in clause (9), (10) or (11).

"Standard & Poor's" means Standard & Poor's, a division of The McGraw-Hill Companies, Inc., and any successor to its rating agency business.

"Stated Maturity" means, with respect to any security, the date specified in such security as the fixed date on which the final payment of principal of such security is due and payable, including

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pursuant to any mandatory redemption provision (but excluding any provision providing for the repurchase of such security at the option of the holder thereof upon the happening of any contingency unless such contingency has occurred).

"Subordinated Obligation" means, with respect to a Person, any Indebtedness of such Person (whether outstanding on the Issue Date or thereafter Incurred) which is subordinate or junior in right of payment to the notes or a Subsidiary Guaranty of such Person, as the case may be, pursuant to a written agreement to that effect.

"Subsidiary" means, with respect to any Person, any corporation, association, partnership or other business entity of which more than 50% of the total voting power of shares of Voting Stock is 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
(3): one or more Subsidiaries of such Person.

"Subsidiary Guarantor" means each Subsidiary of the Company that executes the Indenture as a guarantor on the Issue Date and each other Subsidiary of the Company that thereafter guarantees the notes pursuant to the terms of the Indenture.

"Subsidiary Guaranty" means a Guarantee by a Subsidiary Guarantor of the Company's obligations with respect to the notes.

"Tax Sharing Agreement" means any tax sharing agreement between the Company and Parent or any other Person with which Parent or the Company is required to, or is permitted to, file a consolidated, combined or unitary tax return or with which Parent or the Company is or could be part of a consolidated group for tax purposes.

"Temporary Cash Investments" means any of the following:

(1): any investment in direct obligations of the United States of America or any agency thereof or obligations guaranteed by the United States of America or any agency thereof;
(2): investments in demand and time deposit accounts, certificates of deposit and money market deposits maturing within 180 days of the date of acquisition thereof issued by a bank or trust company which is organized under the laws of the United States of America, any State thereof or any foreign country recognized by the United States of America, and which bank or trust company has capital, surplus and undivided profits aggregating in excess of $50.0 million (or the foreign currency equivalent thereof) and has outstanding debt which is rated "A" (or such similar equivalent rating) or higher by at least one nationally recognized statistical rating organization (as defined in Rule 436 under the Securities Act) or any money-market fund sponsored by a registered broker dealer or mutual fund distributor;
(3): investments in deposits available for withdrawal on demand with any commercial bank that is organized under the laws of any country in which the Company or any Restricted Subsidiary maintains an office or is engaged in the Oil and Gas Business; provided, however, that (i) all such deposits have been made in such accounts in the ordinary course of business and (ii) such deposits do not at any one time exceed $10.0 million in the aggregate;
(4): repurchase obligations with a term of not more than 30 days for underlying securities of the types described in clause (1) above entered into with a bank meeting the qualifications described in clause (2) above;
(5): investments in commercial paper, maturing not more than 90 days after the date of acquisition, issued by a corporation (other than an Affiliate of Parent) organized and in

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existence under the laws of the United States of America or any foreign country recognized by the United States of America with a rating at the time as of which any investment therein is made of "P-1" (or higher) according to Moody's or "A-1" (or higher) according to Standard and Poor's;

(6): investments in securities with maturities of six months or less from the date of acquisition issued or fully guaranteed by any state, commonwealth or territory of the United States of America, or by any political subdivision or taxing authority thereof, and rated at least "A" by Standard & Poor's or "A" by Moody's; and
(7): investments in money market funds that invest substantially all their assets in securities of the types described in clauses (1) through (7) above.

"Tender Offer" means the tender offer launched on December 5, 2003 and consummated on January 26, 2004 by NCE Acquisition, Inc. for all of the common stock of North Coast Energy, Inc.

"Transactions" means, collectively, (1) consummation of the Tender Offer, including the tender of shares representing at least 90% of North Coast Energy's total outstanding shares plus shares issuable upon the exercise of outstanding options and warrants, (2) consummation of the Merger and the other transactions contemplated in the Merger Agreement, (3) the execution and delivery of an amendment and restatement of the Credit Agreement and the incremental borrowings thereunder, (4) the repayment of all amounts outstanding under the Senior Term Credit Agreement dated as of October 17, 2003, among the Company, EXCO Operating, LP, Parent, Taurus Acquisition, Inc. and the institutions named therein as lenders, (5) the amendment and restatement of certain agreements governing long-term indebtedness of North Coast Energy, Inc., (6) the payment of all fees and expenses then due and owing that are required to be paid on or prior to the Merger Date in connection with the offering of the notes and (7) consummation of the exchange offer.

"Trustee" means Wilmington Trust Company until a successor replaces it and, thereafter, means the successor.

"Trust Indenture Act" means the Trust Indenture Act of 1939 (15 U.S.C. §§ 77aaa-77bbbb) as in effect on the Issue Date.

"Trust Officer" means the Chairman of the Board, the President or any other officer or assistant officer of the Trustee assigned by the Trustee to administer its corporate trust matters.

"Unrestricted Subsidiary" means:

(1): any Subsidiary of the Company that at the time of determination shall be designated an Unrestricted Subsidiary by the Board of Directors in the manner provided below; and
(2): any Subsidiary of an Unrestricted Subsidiary.

The Board of Directors may designate any Subsidiary of the Company (including any newly acquired or newly formed Subsidiary but excluding the MLP Subsidiary and any Subsidiary of the MLP Subsidiary) to be an Unrestricted Subsidiary unless such Subsidiary or any of its Subsidiaries owns any Capital Stock or Indebtedness of, or holds any Lien on any property of, the Company or any Subsidiary of the Company that is not a Subsidiary of the Subsidiary to be so designated; provided, however, that either (A) the Subsidiary to be so designated has total assets of $1,000 or less or (B) if such Subsidiary has assets greater than $1,000, such designation would be permitted under the covenant described under "—Certain Covenants—Limitation on Restricted Payments".

The Board of Directors may designate any Unrestricted Subsidiary to be a Restricted Subsidiary; provided, however, that immediately after giving effect to such designation (A) the Company could Incur $1.00 of additional Indebtedness under paragraph (a) of the covenant described under "—Certain Covenants—Limitation on Indebtedness" and (B) no Default shall have occurred and be continuing.

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Any such designation by the Board of Directors shall be evidenced to the Trustee by promptly filing with the Trustee a copy of the resolution of the Board of Directors giving effect to such designation and an Officers' Certificate certifying that such designation complied with the foregoing provisions.

"U.S. Dollar Equivalent" means with respect to any monetary amount in a currency other than U.S. dollars, at any time for determination thereof, the amount of U.S. dollars obtained by converting such foreign currency involved in such computation into U.S. dollars at the spot rate for the purchase of U.S. dollars with the applicable foreign currency as published in The Wall Street Journal in the "Exchange Rates" column under the heading "Currency Trading" on the date two Business Days prior to such determination.

Except as described under "—Certain Covenants—Limitation on Indebtedness", whenever it is necessary to determine whether the Company or any Restricted Subsidiary has complied with any covenant in the Indenture or a Default has occurred and an amount is expressed in a currency other than U.S. dollars, such amount will be treated as the U.S. Dollar Equivalent determined as of the date such amount is initially determined in such currency.

"U.S. Government Obligations" means direct obligations (or certificates representing an ownership interest in such obligations) of the United States of America (including any agency or instrumentality thereof) for the payment of which the full faith and credit of the United States of America is pledged and which are not callable at the issuer's option.

"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 Person means all classes of Capital Stock of such Person (or, in the case of the MLP Subsidiary, the general partnership interests of such MLP Subsidiary) then outstanding and normally entitled (without regard to the occurrence of any contingency) to vote in the election of directors, managers or trustees thereof.

"Wholly Owned Subsidiary" means a Restricted Subsidiary all the Capital Stock of which (other than directors' qualifying shares) is owned by the Company or one or more other Wholly Owned Subsidiaries.

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U.S. FEDERAL INCOME TAX CONSIDERATIONS

The following is a summary of the United States Federal income tax consequences of exchanging for, holding and selling the new notes. Except where we state otherwise, this summary deals only with the new notes held as capital assets, as defined in the Internal Revenue Code of 1986, as amended, or the Code, by a United States Holder (as defined below) who is the initial beneficial owner of the new notes.

We do not address all of the tax consequences that may be relevant to a United States Holder. We also do not address, except as stated below, any of the tax consequences to holders that are Foreign Holders (as defined below) or to holders that may be subject to special tax treatment including banks, thrift institutions, real estate investment trusts, personal holding companies, insurance companies, and brokers and dealers in securities or currencies. Further, we do not address:

•: the United States Federal income tax consequences to stockholders in, or partners or beneficiaries of, an entity that is a holder of the old notes or the new notes;
•: the United States Federal estate and gift or alternative minimum tax consequences of the purchase, ownership and sale of the old notes or the new notes;
•: the United States Federal income tax consequences to persons who hold the old notes or the new notes in a "straddle" or as part of a "hedging," "conversion" or "constructive sale" transaction or whose "functional currency" is not the United States dollar; or
•: any state, local or foreign tax consequences of the purchase, ownership and sale of the old notes or the new notes.

Accordingly, you should consult your own tax advisor regarding the particular tax consequences of exchanging for, owning and selling the new notes in light of your circumstances.

A "United States Holder" is a beneficial owner of the new notes who, for United States Federal income tax purposes, is:

•: an individual who is a citizen or resident of the United States;
•: a corporation or another entity taxable as a corporation created or organized in or under the laws of the United States or any political subdivision thereof or therein;
•: an estate if its income is subject to United States Federal income taxation regardless of its source; or
•: a trust if (1) a United States court can exercise primary supervision over its administration and (2) one or more United States persons have the authority to control all of its substantial decisions; or
•: specified electing trusts that were in existence on August 20, 1996 and treated as domestic trusts on that date.

If a partnership holds the new notes, the tax treatment of a partner will generally depend upon the status of the partner and upon the activities of the partnership. If you are a partner of a partnership holding new notes, you should consult your tax advisor.

A "Foreign Holder" is a beneficial owner of the new notes other than a United States Holder.

This summary is based on the currently existing provisions of the Code, Treasury Regulations issued under the Code, and administrative judicial interpretations thereof, all as they currently exist as of the date of this prospectus and all of which are subject to change, possibly with retroactive effect, or different interpretations. Legislative, judicial, or administrative changes or interpretations may be forthcoming that could alter or modify the statements and conclusions made below and that could

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affect the tax consequences discussed below. We have not asked, and do not intend to ask, for a ruling from the Internal Revenue Service on any of the tax consequences discussed below. Accordingly, we can give you no assurance that the Internal Revenue Service will not take a contrary view.

United States Federal Income Taxation of United States Holders

Payment of Interest on the New Notes. Interest paid or payable on a new note will be taxable to a United States Holder as ordinary income, generally at the time it is received or accrued, in accordance with such holder's regular method of accounting for United States Federal income tax purposes.

Exchange Offer. The exchange of old notes for new notes in the exchange offer will not constitute a taxable event for United States Holders. Consequently, a United States Holder will not recognize gain or loss on the exchange, the holding period of the new note will include the holding period of the old note, and the basis of the new note will be the same as the basis of the old note immediately before the exchange.

If a United States Holder receives additional interest, we believe it should be treated in the same manner as regular interest on the new notes. However, the United States Holder might instead be required to report it as income when it accrues or becomes fixed, even if the United States Holder is a cash method taxpayer.

Sale, Exchange or Retirement of the New Notes. Upon the sale, exchange, redemption, retirement at maturity or other disposition of a new note, a United States Holder generally will recognize taxable gain or loss equal to the difference between the sum of cash plus the fair market value of all non-cash property received on such disposition (except to the extent such cash or property is attributable to accrued, but unpaid, interest, which will be taxable as ordinary income) and such United States Holder's adjusted tax basis in the new note. A United States Holder's adjusted tax basis in a new note generally will equal the cost of the old note to such United States Holder. Gain or loss recognized on the disposition of a new note will be long-term capital gain or loss if, at the time of such disposition, the United States Holder's holding period for the note is more than one year. Long-term capital gain realized by individual taxpayers is generally taxable at a maximum rate of 20 percent. The deductibility of capital losses is subject to limitations.

Backup Withholding and Information Reporting. Backup withholding and information reporting requirements may apply to payments made with respect to the new notes. We, or our agent or a broker, as the case may be, will be required to withhold from any payment that is subject to backup withholding United States Federal income tax a portion of such payment not to exceed 28%, if a United States Holder fails to furnish its taxpayer identification number (social security or employer identification number) or otherwise fails to comply with the applicable requirements of the backup withholding rules. Corporations and certain other entities are generally exempt from the backup withholding and information reporting requirements. Generally, income on the notes will be reported to non-exempt United States Holders on an applicable Internal Revenue Service Form 1099.

Any amounts withheld under the backup withholding rules from a payment to a United States Holder will be allowed as a credit against such United States Holder's United States federal income tax liability and may entitle the United States Holder to a refund, provided that the required information is furnished to the Internal Revenue Service by the United States Holder in a timely manner.

United States Federal Income Taxation of Foreign Holders

Payment of Interest on the New Notes. Payments of interest to a Foreign Holder that are not effectively connected to the conduct of a United States trade or business will generally not be subject to United States Federal income tax, or the withholding thereof, provided the Foreign Holder:

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•: does not own (directly or indirectly, actually or constructively) 10% or more of the total combined voting power of all classes of our capital stock entitled to vote;
•: is not a controlled foreign corporation that is related to us through stock ownership; and
•: is not a bank receiving interest described in section 881(c)(3)(A) of the Code.

A Foreign Holder that receives interest payments that are not effectively connected with a United States trade or business but that does not satisfy each of the three above mentioned conditions will be subject to withholding tax at a rate of 30%, unless a United States income tax treaty applies to reduce or eliminate withholding.

To qualify for exemption from withholding, the last United States payor in the chain of payment prior to payment to a Foreign Holder (the "withholding agent") must have received in the year in which a payment of interest or principal occurs, or in either of the two preceding calendar years, a statement that:

•: is signed by the Foreign Holder under penalties of perjury;
•: certifies that the holder of the securities is a Foreign Holder; and
•: provides the name and address of the Foreign Holder.

The statement may be made on an Internal Revenue Service Form W-8BEN or a substantially similar form, and the Foreign Holder must inform the withholding agent of any change in the information on the statement within 30 days of any change. If the notes are held through a securities clearing organization or certain other financial institutions that are not qualified intermediaries, the organization or institution may provide a signed statement to the withholding agent along with a copy of Internal Revenue Service Form W-8BEN or a substitute form provided by the Foreign Holder. If the financial institution is a qualified intermediary, it generally will not be required to furnish a copy of the Internal Revenue Service Form W-8BEN. A qualified intermediary is a financial institution that has entered into a withholding agreement with the Internal Revenue Service.

Exchange Offer. The exchange of old notes for new notes in the exchange offer will not constitute a taxable event for Foreign Holders. Consequently, for United States Federal income tax purposes, a Foreign Holder will not recognize gain or loss on the exchange, the holding period of the new note will include the holding period of the old note, and the basis of the new note will be the same as the basis of the old note immediately before the exchange. If a Foreign Holder receives additional interest on the new notes, we believe it should be treated in the same manner as regular interest on the notes.

Sale, Exchange or Retirement of the New Notes. A Foreign Holder will generally not be subject to United States federal income tax, or the withholding thereof, on any gain realized upon the sale, exchange, redemption, retirement at maturity or other disposition of the new notes. If, however, the gain is effectively connected with the conduct of a trade or business within the United States by the Foreign Holder or if the Foreign Holder is present in the United States for 183 days or more during the taxable year of sale, redemption, retirement or other disposition and certain other conditions are met, the Foreign Holder may be subject to income tax on all income and gains recognized.

U.S. Trade or Business. If a Foreign Holder holds the new notes in connection with a trade or business that the Foreign Holder is conducting in the United States:

•: Any interest on the new notes, and any gain from disposing of the new notes, generally will be subject to income tax as if the Foreign Holder were a United States Holder.
•: If the Foreign Holder is a corporation, the Foreign Holder may be subject to the "branch profits tax" on the earnings that are connected with Foreign Holder's United States trade or business,

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including earnings from the notes. This tax is 30%, but may be reduced or eliminated by an applicable United States income tax treaty.

Backup Withholding and Information Reporting. Backup withholding and information reporting requirements do not apply to payments of interest made to Foreign Holders if the certification needed to avoid withholding tax on interest, as described above, is received, provided that the payor does not have actual knowledge that the holder is a United States Holder. If any payments of principal and interest are made to the beneficial owner of a new note by or through the foreign office of a foreign custodian, foreign nominee or other foreign agent of such beneficial owner, or if the foreign office of a foreign "broker" (as defined in applicable United States Treasury Regulations) pays the proceeds of the sale of a new note effected outside the United States to the seller thereof, backup withholding and information reporting will not apply. Information reporting requirements (but not backup withholding) will apply, however, to a payment by or through a foreign office of a broker of principal and interest or the proceeds of a sale of a new note effected outside the United States if that broker has specified types of relationships with the United States, unless the broker has documentary evidence in its records that the holder is a Foreign Holder and certain other conditions are met or the Foreign Holder otherwise establishes an exemption. Payment by a United States office of a broker is subject to both backup withholding at a rate not to exceed 28% and information reporting unless the holder certifies, under penalties of perjury, in the manner required as to its Foreign Holder status or otherwise establishes an exemption.

171

PLAN OF DISTRIBUTION

Based on interpretations by the staff of the SEC set forth in no-action letters issued to third parties, we believe that new notes issued pursuant to the exchange offer in exchange for old notes may be offered for resale, resold and otherwise transferred by you without compliance with the registration and prospectus delivery provisions of the Securities Act, provided that:

•: you are acquiring the new notes in the ordinary course of your business;
•: you are not a broker-dealer who acquired the old notes directly from us without compliance with the registration and prospectus delivery provisions of the Securities Act;
•: you have not engaged in, do not intend to engage in, and have no arrangement or understanding with any person to participate in the distribution of the new notes; and
•: you are not our affiliate as defined under Rule 405 of the Securities Act.

Any holder of notes who is (i) our affiliate, (ii) does not acquire new notes in the ordinary course of its business, (iii) tenders old notes in the exchange offer with the intention of participating in any manner in a distribution of the new notes or (iv) is a broker-dealer that acquired the old notes directly from us:

•: cannot rely on those interpretations of the SEC; and
•: must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a secondary resale transaction, and the secondary resale transaction must be covered by an effective registration statement containing the selling security holder information required by Item 507 or 508, as applicable, of Regulation S-K under the Securities Act.

Each broker-dealer that receives new notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. The prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where such old notes were acquired as a result of market-making activities or other trading activities. We and the subsidiary guarantors have agreed that for a period of 180 days after the exchange offer is completed, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale. In addition, until 90 days after the date of this prospectus, all dealers effecting transactions in the new notes may be required to deliver a prospectus.

We will not receive any proceeds from any sale of new notes by broker-dealers. New notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the new notes or a combination of such methods of resale, at market prices prevailing at the time of resale, at prices related to such prevailing market prices or at negotiated prices. Any such resale may be made directly to the purchaser or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer and/or the purchasers of any such new notes. Any broker-dealer that resells new notes that were received by it for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of such new notes may be deemed to be an "underwriter" within the meaning of the Securities Act.

For a period of 180 days after the expiration date, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents in the letter of transmittal. We have agreed to pay the expenses incident to the exchange offer, other than commissions or concessions of any brokers or dealers and the fees of any

172

advisors or experts retained by the holder of the notes, and will indemnify the holders of the old notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

NOTICE TO CANADIAN RESIDENTS

Any resale of the notes in Canada must be made under applicable securities laws which will vary depending on the relevant jurisdiction, and which may require resales to be made under available statutory exemptions or under a discretionary exemption granted by the applicable Canadian securities regulatory authority. Note holders resident in Canada are advised to seek legal advice prior to any resale of the notes.

LEGAL MATTERS

Certain matters related to the exchange offer and the validity and enforceability of the new notes will be passed upon for us by Haynes and Boone, LLP.

INDEPENDENT ACCOUNTANTS

The consolidated financial statements of EXCO Resources, Inc. (Predecessor Company) for the period from January 1, 2003 to July 28, 2003, included in this Pre-effective Amendment No. 1 to the Registration Statement on Form S-4 have been so included in reliance on the report of PricewaterhouseCoopers LLP, independent auditors, given on the authority of said firm as experts in auditing and accounting.

The consolidated financial statements of EXCO Resources, Inc. (Successor Company) as of December 31, 2003 and for the period from July 28, 2003 to December 31, 2003, included in this Pre-effective Amendment No. 1 to the Registration Statement on Form S-4 have been so included in reliance on the report of PricewaterhouseCoopers LLP, independent auditors, given on the authority of said firm as experts in auditing and accounting.

The consolidated financial statements of EXCO Resources, Inc. at December 31, 2002, and for the two years ended December 31, 2002, appearing in this Pre-effective Amendment No. 1 to the Registration Statement on Form S-4 have been audited by Ernst & Young LLP, independent accountants, and the consolidated financial statements of North Coast at December 31, 2003 and 2002, and for the three years ended December 31, 2003, appearing in this Pre-effective Amendment No. 1 to the Registration Statement on Form S-4 have been audited by Hausser + Taylor LLC, independent accountants, as set forth in their respective reports thereon appearing elsewhere herein, and are included in reliance upon such reports given on the authority of such firms as experts in accounting and auditing.

CHANGE IN ACCOUNTANTS

In September 2003, following the going private transaction, the board of directors of EXCO Holdings engaged PricewaterhouseCoopers LLP as our independent auditors.

Ernst & Young LLP's reports on our consolidated financial statements for the fiscal years ended December 31, 2002 and 2001 did not contain an adverse opinion or disclaimer of opinion, nor were such reports qualified or modified as to uncertainty or audit scope. Their reports do identify that EXCO Resources, Inc. adopted Statements of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" in 2001; No. 141, "Business Combinations" in 2001, and No. 142, "Goodwill and Intangible Assets" in 2002.

During Ernst & Young LLP's engagement, there were no (1) disagreements with Ernst & Young LLP on any matters of accounting principles or practices, financial statement disclosure or audit scope or procedure which disagreements, if not resolved to Ernst & Young LLP's satisfaction, would have

173

caused it to make reference to the subject matter of the disagreement in connection with its report on our consolidated financial statements or (2) reportable events as defined in item 301(a)(1)(v) of Regulation S-K.

INDEPENDENT PETROLEUM ENGINEERS

Lee Keeling and Associates, Inc., independent petroleum engineers, Tulsa, Oklahoma, prepared the reserve estimates with respect to our historical properties, presented as of December 31, 2001, 2002 and 2003, which reserve estimates have been included in reliance upon the authority of said firm as experts in petroleum engineering. Lee Keeling and Associates, Inc., also prepared the reserve estimates with respect to North Coast presented as of December 31, 2003 included herein in the "Prospectus Summary" and "Business" sections, which reserve estimates have been included in reliance upon the authority of said firm as experts in petroleum engineering.

The oil and natural gas reserves of North Coast included in its consolidated financial statements at December 31, 2003 are estimates by North Coast, which estimates were reviewed and agreed to by Schlumberger Limited, independent consulting petroleum engineers, and have been included in this prospectus upon the authority of said firm as experts with respect to the matters covered by such reports and in giving such reports.

174

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following are abbreviations and definitions of terms commonly used in the oil and natural gas industry and this prospectus.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bcf. One billion cubic feet of natural gas.

Bcfe. One billion cubic feet equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas.

Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Completion. The installation of permanent equipment for the production of oil or natural gas, or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Infill Drilling. Drilling of a well between known producing wells to better exploit the reservoir.

Mbbl. One thousand stock tank barrels.

Mcf. One thousand cubic feet of natural gas.

Mcfe. One thousand cubic feet equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas.

Mmbbl. One million stock tank barrels.

Mmbtu. One million British thermal units.

Mmcf. One million cubic feet of natural gas.

Mmcf/d. One million cubic feet of natural gas per day.

Mmmbtu. One billion British thermal units.

NGLs. The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

NYMEX. New York Mercantile Exchange.

Overriding Royalty Interest. An interest in an oil and/or natural gas property entitling the owner to a share of oil and natural gas production free of costs of production.

Present Value of Estimated Future Net Revenues or PV-10. The present value of estimated future net revenues is an estimate of future net revenues from a property at the date indicated, after deducting production and ad valorem taxes, future capital costs and operating expenses, but before deducting federal income taxes. The future net revenues have been discounted at an annual rate of 10% to determine their "present value." The present value is shown to indicate the effect of time on the value of the net revenue stream and should not be construed as being the fair market value of the properties. Estimates have been made using constant oil, natural gas and NGL prices and operating costs at the date indicated, at its acquisition date or as otherwise indicated. We believe that the present value of estimated future net revenues before income taxes, while not in accordance with generally accepted accounting principles, is an important financial measure used by investors and independent oil and

175

natural gas producers for evaluating the relative significance of oil and natural gas properties and acquisitions.

Proved Developed Reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved Reserves. The estimated quantities of oil, natural gas and natural gas liquids which geological engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved Undeveloped Reserves. 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.

Reserve Life. The estimated productive life of a proved reservoir based upon the economic limit of such reservoir producing hydrocarbons in paying quantities assuming certain price and cost parameters. For purposes of this prospectus, reserve life is calculated by dividing the Proved Reserves (on a Mcfe basis) at the end of the period by production volumes for the previous 12 months.

Royalty Interest. An interest in an oil and/or natural gas property entitling the owner to a share of oil and natural gas production free of costs of production.

Standardized Measure of Discounted Future Net Cash Flows or the Standardized Measure. Under the Standardized Measure, future cash flows are estimated by applying year-end prices, adjusted for fixed and determinable escalations, to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pretax cash inflows. Future income taxes are computed by applying the statutory tax rate to the excess of pretax cash inflows over our tax basis in the associated properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate to arrive at the Standardized Measure.

176

INDEX TO FINANCIAL STATEMENTS

EXCO Resources, Inc.
	Report of Independent Accountants		F-2
	Reports of Independent Auditors		F-3
	Consolidated Balance Sheets at December 31, 2002 and 2003		F-5
	Consolidated Statements of Operations for the years ended December 31, 2001 and 2002, the 209 day period from January 1, 2003 to July 28, 2003 and the 156 day period from July 29, 2003 to December 31, 2003		F-7
	Consolidated Statements of Cash Flows for the years ended December 31, 2001 and 2002, the 209 day period from January 1, 2003 to July 28, 2003 and the 156 day period from July 29, 2003 to December 31, 2003		F-8
	Consolidated Statements of Changes in Shareholders' Equity for the years ended December 31, 2001 and 2002, the 209 day period from January 1, 2003 to July 28, 2003 and the 156 day period from July 29, 2003 to December 31, 2003		F-9
	Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2001 and 2002, the 209 day period from January 1, 2003 to July 28, 2003 and the 156 day period from July 29, 2003 to December 31, 2003		F-10
	Notes to Consolidated Financial Statements		F-11

		Financial information for the periods prior to July 29, 2003, the date of the going private transaction, represents predecessor basis financial statements. See Note 1 to the consolidated financial statements.
North Coast Energy, Inc.
	Report of Independent Public Accountants		F-49
	Consolidated Balance Sheets at December 31, 2003 and December 31, 2002		F-50
	Consolidated Statements of Income for the years ended December 31, 2003 and 2002 and the nine months ended December 31, 2001		F-52
	Consolidated Statements of Stockholders' Equity for the years ended December 31, 2003 and 2002 and the nine months ended December 31, 2001		F-53
	Consolidated Statements of Cash Flows for the years ended December 31, 2003 and 2002 and the nine months ended December 31, 2001		F-54
	Notes to Consolidated Financial Statements		F-55

F-1

REPORT OF INDEPENDENT ACCOUNTANTS

The Board of Directors
EXCO Resources, Inc.

We have audited the accompanying consolidated balance sheet of EXCO Resources, Inc. as of December 31, 2002, and the related consolidated statements of operations, cash flows, changes in stockholders' equity, and comprehensive income (loss) for each of the two years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States. 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, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of EXCO Resources, Inc. at December 31, 2002, and the consolidated results of its operations and its cash flows for each of the two years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States.

As discussed in Note 2 to the consolidated financial statements, in 2001 EXCO Resources, Inc. adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities".

As discussed in Note 3 to the consolidated financial statements, EXCO Resources, Inc. adopted Statements of Financial Accounting Standards No. 141 "Business Combinations" in 2001 and No. 142 "Goodwill and Intangible Assets" in 2002.

/s/ ERNST & YOUNG LLP

Dallas, Texas
February 28, 2003
except for Note 3 as to which the date is June 27, 2003

F-2

Report of Independent Auditors

To the Board of Directors of EXCO Resources, Inc.:

In our opinion, the accompanying consolidated statements of operations, of comprehensive income, of shareholders' equity and of cash flows present fairly, in all material respects, the results of operations and cash flows of EXCO Resources, Inc. and its subsidiaries (Predecessor Company) for the 209 day period from January 1, 2003 to July 28, 2003 in conformity with accounting principles generally accepted in the United States of America. 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 audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

As discussed in Note 2 to the consolidated financial statements, the Company adopted the provisions of Statement of Financial Accounting Standard No. 143, "Accounting for Asset Retirement Obligations," as of January 1, 2003 and changed the manner in which it accounts for asset retirement costs.

/s/ PricewaterhouseCoopers LLP
March 18, 2004
Dallas, Texas

F-3

Report of Independent Auditors

To the Board of Directors of EXCO Resources, Inc.:

In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, of comprehensive income, of shareholders' equity and of cash flows present fairly, in all material respects, the financial position of EXCO Resources, Inc. and its subsidiaries (Successor Company) at December 31, 2003, and the results of their operations and their cash flows for the 156 day period from July 29, 2003 to December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. 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 audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP
March 18, 2004
Dallas, Texas

F-4

EXCO RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

				December 31,
				2002			2003
				(In thousands, except share data)
				Predecessor			Successor
Assets
Current assets:
	Cash and cash equivalents			$	1,942		$	7,333
	Accounts receivable:
		Oil and natural gas sales			12,299			13,514
		Joint interest			1,889			3,857
		Interest and other			7,343			1,895
	Oil and natural gas derivatives				—			705
	Marketable securities				1,823			818
	Other				902			3,447

			Total current assets		26,198			31,569

Oil and natural gas properties (full cost accounting method):
		Unproved oil and natural gas properties			4,979			9,195
		Proved developed and undeveloped oil and natural gas properties			314,517			416,679
		Accumulated depreciation, depletion and amortization			(109,545	)		(11,931	)

		Oil and natural gas properties, net			209,951			413,943

Office and field equipment, net					1,030			1,101
Deferred financing costs, net					1,100			1,565
Oil and natural gas derivatives					140			204
Advances to affiliates					—			46
Goodwill					—			53,346
Other assets					2,755			3,256

			Total assets	$	241,174		$	505,030

See accompanying notes.

F-5

EXCO RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

				December 31,
				2002			2003
				(In thousands, except share data)
				Predecessor			Successor
Liabilities and Stockholders' Equity
Current liabilities:
	Accounts payable and accrued liabilities			$	21,597		$	24,946
	Revenues and royalties payable				3,353			3,350
	Income taxes payable				224			3,726
	Accrued interest payable				95			362
	Oil and natural gas derivatives				7,924			12,804

			Total current liabilities		33,193			45,188

Long-term debt					97,943			207,951
Asset retirement obligations and other long-term liabilities					2,176			18,343
Deferred income taxes					7,978			45,899
Oil and natural gas derivatives					—			3,780
Commitments and contingencies					—			—
Stockholders' equity:
	Preferred stock, $.01 par value: Authorized shares—10,000,000 Issued and outstanding shares—5,004,869 at December 31, 2002				101,175			—
	Common stock, $.02 par value: Authorized shares—25,000,000 Issued and outstanding shares—7,262,953 at December 31, 2002				145			—
	Common stock, $.01 par value: Authorized shares—100,000 Issued and outstanding shares—1,000 at December 31, 2003				—			1
	Additional paid-in capital				53,107			—
	Capital contributed by EXCO Holdings Inc.				—			172,045
	Deferred compensation				(705	)		—
	Notes receivable-employees				(173	)		—
	Retained earnings (deficit)				(44,399	)		4,177
	Accumulated other comprehensive income:
		Hedging activities			(5,024	)		—
		Foreign currency translation adjustments			(938	)		7,680
		Unrealized gain (loss) on equity investments			258			(34	)
	Treasury stock, at cost: 248,434 shares at December 31, 2002				(3,562	)		—

			Total stockholders' equity		99,884			183,869

			Total liabilities and stockholders' equity	$	241,174		$	505,030

See accompanying notes.

F-6

EXCO RESOURCES, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

			Predecessor									Successor
			Year ended December 31, 2001			Year ended December 31, 2002			For the 209 Day Period From January 1, 2003 to July 28, 2003			For the 156 Day Period From July 29, 2003 to December 31, 2003
Revenues and other income:
	Oil and natural gas		$	61,237		$	66,446		$	61,416		$	46,133
	Commodity price risk management activities			—			—			—			(11,160	)
	Other income (loss)			5,567			6,654			(1,033	)		239
	Gain on disposition of property, equipment and other assets			136			3			—			—

		Total revenues and other income		66,940			73,103			60,383			35,212

Cost and expenses:
	Oil and natural gas production			23,914			29,223			19,793			14,524
	Depreciation, depletion and amortization			14,244			18,558			12,022			12,012
	Accretion of discount on asset retirement obligations			—			—			737			528
	General and administrative			4,806			10,968			19,272			5,847
	Interest			3,133			3,408			2,981			3,971
	Impairment of oil and natural gas properties			49,575			17,459			—			—
	Impairment of marketable securities			—			1,136			—			—
	Uncollectible value of Enron hedges			10,669			—			—			—

		Total cost and expenses		106,341			80,752			54,805			36,882

Income (loss) before income taxes				(39,401	)		(7,649	)		5,578			(1,670	)
Income tax expense (benefit)				(54	)		(6,682	)		4,801			(5,847	)

Income (loss) before cumulative effect of change in accounting principle				(39,347	)		(967	)		777			4,177
Cumulative effect of change in accounting principle, net of income taxes of $696,000				—			—			255			—

Net income (loss)				(39,347	)		(967	)		1,032		$	4,177

Dividends on preferred stock				2,653			5,256			2,620

Earnings (loss) on common stock			$	(42,000	)	$	(6,223	)	$	(1,588	)

Basic earnings (loss) per share			$	(5.96	)	$	(0.88	)	$	(0.20	)

Diluted income (loss) per share			$	(5.96	)	$	(0.88	)	$	(0.20	)

Weighted average number of common and common equivalent shares outstanding:
	Basic			7,046			7,061			8,084

	Diluted			7,046			7,061			8,084

See accompanying notes.

F-7

EXCO RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

				Predecessor									Successor
				Year ended December 31, 2001			Year ended December 31, 2002			For the 209 Day Period From January 1, 2003 to July 28, 2003			For the 156 Day Period From July 29, 2003 to December 31, 2003
				(In thousands)
Operating Activities:
Net income (loss)				$	(39,347	)	$	(967	)	$	1,032		$	4,177
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
	Depreciation, depletion and amortization				14,638			18,558			12,022			12,012
	Impairment of oil and natural gas properties				49,575			17,459			—			—
	Impairment of marketable securities				—			1,136			—			—
	Stock option compensation expense				—			—			9,020			—
	Accretion of discount on asset retirement obligations				—			—			737			528
	Cumulative effect of change in accounting principle, net of income tax				—			—			(255	)		—
	Deferred income taxes				(1,211	)		(4,011	)		2,710			(7,141	)
	Income from derivative ineffectiveness and terminated hedges				(4,147	)		(6,291	)		(187	)		—
	Non-cash change in fair value of derivatives				—			—			—			5,783
	Allowance for uncollectible value of Enron hedges				10,669			—			—			—
	(Gains) losses from sales of marketable securities				—			—			(245	)		30
	Other, net				(136	)		444			205			(11	)
		Effect of changes in:
			Accounts receivable		(470	)		(7,562	)		(296	)		5,975
			Other current assets		(2,655	)		1,310			(1,573	)		(1,160	)
			Accounts payable and other current liabilities		(1,000	)		11,584			(2,752	)		1,527

Net cash provided by operating activities					25,916			31,660			20,418			21,720
Investing Activities:
Additions to oil and natural gas properties and equipment					(90,876	)		(81,854	)		(29,773	)		(44,216	)
Acquisition of Addison Energy Inc.					(44,864	)		—			—			—
Proceeds from disposition of property and equipment					1,399			5,089			6,020			2,303
Advances/investments with affiliates					—			—			—			1,995
Proceeds from sales of marketable securities					—			—			422			1,393
Other investing activities					570			(172	)		(189	)		(3	)

Net cash used in investing activities					(133,771	)		(76,937	)		(23,520	)		(38,528	)
Financing Activities:
Proceeds from long-term debt					165,463			70,356			46,337			73,700
Payments on long-term debt					(162,484	)		(17,910	)		(22,599	)		(57,075	)
Proceeds from issuance of preferred stock					101,175			—			—			—
Proceeds from exercise of stock options					2,506			1,027			12,737			—
Purchase of common stock from employees in connection with the merger					—			—			(17,874	)		—
Purchase of director and employee stock options in connection with the merger					—			—			(3,567	)		—
Payment of fees and expenses in connection with the merger					—			—			(563	)		—
Principal and interest on notes receivable—employees					615			944			—			—
Purchases of treasury stock					(761	)		(2,802	)		—			—
Issuance of treasury stock					—			120			—			—
Preferred stock dividends					(2,653	)		(5,256	)		(2,620	)		—
Deferred financing costs					(1,731	)		(551	)		(2,041	)		(1,662	)
Other financing activities					—			—			172			1

Net cash provided by financing activities					102,130			45,928			9,982			14,964

Net increase (decrease) in cash					(5,725	)		651			6,880			(1,844	)
Effect of exchange rates on cash and cash equivalents					(619	)		(565	)		58			297
Cash at beginning of period					8,200			1,856			1,942			8,880

Cash at end of period				$	1,856		$	1,942		$	8,880		$	7,333

Supplemental Cash Flow Information:
Interest paid				$	2,667		$	3,520		$	2,931		$	3,645

Income taxes paid				$	6,350		$	—		$	245		$	322

See accompanying notes.

F-8

EXCO RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
(In thousands)

	Predecessor													Successor
	For the year ended December 31, 2001				For the year ended December 31, 2002				For the 209 day period ended July 29, 2003					For the 156 day period ended December 31, 2003
	Number of shares	Amount			Number of shares	Amount			Number of shares		Amount			Number of shares	Amount
5% Preferred shares:
Balance at beginning of the period	—	$	—		5,005	$	101,175		5,005		$	101,175		—	$	—
Issuance of 5% preferred stock	5,005		101,175											—		—
Conversion of 5% preferred stock	—		—		—		—		(5,005	)		(101,175	)	—		—

Balance at end of period	5,005	$	101,175		5,005	$	101,175		—		$	—		—	$	—

Common stock:
Balance at beginning of the period	6,853	$	137		7,173	$	143		7,263		$	145		1	$	1
Exercise of stock options and warrants	270		5		90		2		1,133			23		—		—
Issuance of restricted stock	50		1		—		—		—			—		—		—
Conversion of 5% preferred stock	—		—		—		—		5,005			100		—		—

Balance at end of period	7,173	$	143		7,263	$	145		13,401		$	268		1	$	1

Additional paid-in capital:
Balance at beginning of the period		$	47,500			$	51,138				$	53,107			$	—
Exercise of stock options and warrants			2,682				1,025					12,716				—
Issuance of restricted stock			909									—				—
Realization of deferred tax asset			47				—					—				—
Deferred compensation			—				944					(594	)			—
Conversion of 5% preferred stock			—				—					101,074				—

Balance at end of period		$	51,138			$	53,107				$	166,303			$	—

Capital contributed by EXCO Holdings Inc.
Balance at beginning of the period		$	—			$	—				$	—			$	—
Capital contributed by parent			—				—					—				172,045

Balance at end of period		$	—			$	—				$	—			$	172,045

Deferred compensation:
Balance at beginning of the period		$	—			$	—				$	(705	)		$	—
Stock based compensation expense							239									—
Deferred compensation							(944	)				705				—

Balance at end of period		$	—			$	(705	)			$	—			$	—

Notes receivable-Officers and employees:
Balance at beginning of the period		$	(1,551	)		$	(1,117	)			$	(173	)		$	—
Principal and interest payments			615				1,007					173				—
Notes issued by officers and employees			(181	)			(63	)				—				—

Balance at end of period		$	(1,117	)		$	(173	)			$	—			$	—

Retained earnings (deficit)
Balance at beginning of the period		$	3,809			$	(38,191	)			$	(44,399	)		$	—
Net income (loss)			(39,347	)			(967	)				1,032				4,177
Dividends on preferred shares			(2,653	)			(5,256	)				(2,620	)			—
Purchase of treasury stock							15					—				—

Balance at end of period		$	(38,191	)		$	(44,399	)			$	(45,987	)		$	4,177

Treasury stock
Balance at beginning of the period		$	(104	)		$	(865	)			$	(3,562	)		$	—
Purchase of treasury stock			(761	)			(2,802	)				(17,874	)			—
Issuance of treasury stock			—				105					—				—

Balance at end of period		$	(865	)		$	(3,562	)			$	(21,436	)		$	—

Accumulated other comprehensive income (loss)
Balance at beginning of the period		$	—			$	8,096				$	(5,704	)		$	—
Foreign currency translation adjustments			(1,646	)			708					2,791				7,680
Equity investments			9,742				258					590				(34	)
Hedging activities			—				(14,766	)				(1,602	)			—

Balance at end of period		$	8,096			$	(5,704	)			$	(3,925	)		$	7,646

Total Shareholders' Equity:
Balance at beginning of the period		$	49,791			$	120,379				$	99,884			$	—

Balance at end of period		$	120,379			$	99,884				$	95,223			$	183,869

See accompanying notes.

F-9

EXCO RESOURCES, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)

			Predecessor									Successor
			Year ended December 31, 2001			Year ended December 31, 2002			For the 209 Day Period From January 1, 2003 to July 28, 2003			For the 156 Day Period From July 29, 2003 to December 31, 2003
Net income (loss)			$	(39,347	)	$	(967	)	$	1,032		$	4,177
Other comprehensive income (loss):
	Hedging activities:
		Cumulative effect of change in accounting principle—January 1, 2001		(1,068	)		—			—			—
		Effective changes in fair value		22,843			(15,987	)		14,701			—
		Reclassification adjustments for settled contracts		(10,687	)		8,197			(14,540	)		—
		Amortization of terminated contracts		(1,346	)		(6,976	)		(1,763	)		—

	Total hedging activities			9,742			(14,766	)		(1,602	)		—
	Foreign currency translation adjustment			(1,646	)		708			2,791			7,680
	Reclassification adjustment for impairment of marketable securities			—			1,136			—			—
	Unrealized gain (loss) on equity investments			—			(878	)		590			(34	)

Total comprehensive income (loss)			$	(31,251	)	$	(14,767	)	$	2,811		$	11,823

See accompanying notes.

F-10

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. The Merger

On July 29, 2003, pursuant to an Agreement and Plan of Merger, ER Acquisition, Inc., a Texas corporation, and a wholly-owned subsidiary of EXCO Holdings Inc., a Delaware corporation, was merged into EXCO Resources, Inc. (EXCO). EXCO Holdings Inc. (Holdings or our parent) was formed by our chairman and chief executive officer, Douglas H. Miller, and his buying group for the purpose of entering into the merger agreement. The holders of EXCO's common stock, other than Holdings and its subsidiaries, received cash of $18.00 per share. The buyout was funded with borrowings from EXCO's existing credit facilities of approximately $53.6 million and approximately $172.0 million of equity. The equity capital for Holdings was provided by:

•: Cerberus Capital Management, L.P., or Cerberus, an investment management firm—$106.5 million in cash;
•: Other institutional investors—$34.3 million in cash;
•: Certain members of EXCO's management—$10.5 million in cash and the contribution of EXCO shares; and
•: Other institutional and other investors—$20.7 million in cash and the contribution of EXCO shares.

Upon completion of the merger transaction, EXCO's common stock was delisted from trading on the NASDAQ National Market or any other exchange and EXCO's common registration pursuant to Section 12(g)(4) of the Securities Exchange Act of 1934 was terminated. Accordingly, earnings per share data is not shown for any of the periods subsequent to July 28, 2003.

The total purchase price for EXCO was $353.5 million representing the purchase of all outstanding common stock and stock options including the amounts contributed to Holdings by management and key employees and other investors, and liabilities assumed as detailed below and has been allocated as follows (dollars in thousands):

Purchase Price Calculations:
Payments for tendered shares including options	$	195,327
Value of EXCO shares contributed by management		8,429
Value of EXCO shares contributed by other investors		17,966
Assumption of debt		130,003
Merger related costs		1,819

Total EXCO acquisition costs	$	353,544

Allocation of purchase price:
Oil and natural gas properties—proved		358,111
Oil and natural gas properties—unproved		9,967
Goodwill		51,120
Other property and equipment and other assets		3,678
Current assets		36,705
Deferred income taxes(1)		(50,733	)
Accounts payable and accrued expenses		(37,757	)
Asset retirement obligations		(15,744	)
Fair value of oil and natural gas derivatives		(1,803	)

Total allocation	$	353,544

(1): Represents deferred income taxes recorded at the date of the merger due to differences between the book basis and the tax basis of assets. For book purposes, we had a step-up in basis related to purchase accounting while our existing tax basis carried over.

F-11

As a result of the change in control, generally accepted accounting principles (GAAP) requires the acquisition by Holdings to be accounted for as a purchase transaction in accordance with Statement of Financial Accounting Standards No. 141, "Business Combinations". GAAP requires the application of "push down accounting" in situations where the ownership of an entity has changed, meaning that the post-transaction financial statements of the acquired entity (i.e. EXCO) reflect the new basis of accounting in accordance with Staff Accounting Bulletin No. 54 ("SAB 54"). Accordingly, the financial statements as of December 31, 2003 and for the 156 day period then ended reflect Holdings' stepped up basis resulting from the acquisition that has been pushed down to us. The aggregate purchase price has been allocated to the underlying assets and liabilities based upon the respective estimated fair values at July 29, 2003 (date of acquisition). Carryover basis accounting applies for tax purposes. All financial information presented prior to July 29, 2003 represents predecessor basis of accounting.

The purchase price allocation resulted in $51.1 million of goodwill, $24.2 million in the United States geographic operating segment and $26.9 million in the Canadian geographic operating segment. None of the goodwill is deductible for income tax purposes. Furthermore, in accordance with No. 142, "Goodwill and Intangible Assets", goodwill is not amortized, but is tested for impairment on an annual basis, or more frequently as impairment indicators arise. Impairment tests, which involve the use of estimates related to the fair market value of the business operations with which goodwill is associated, are performed at the end of our fourth quarter. Losses, if any, resulting from impairment tests will be reflected in operating income in the statement of operations. Changes in the balance of goodwill from the date of acquisition to December 31, 2003 are the result of foreign currency translation adjustments for associated Canadian goodwill.

Pro Forma Results of Operations.

The following reflects the pro forma results of operations as though the merger had been consummated at the beginning of each respective period.

	Year Ended December 31, 2002			Year Ended December 31, 2003
	(In thousands) (Unaudited)
Revenues and other income	$	73,103		$	95,595
Income (loss) before cumulative effect of change in accounting principle		(9,519	)		10,169
Net income (loss)		(9,519	)		10,424
Basic loss per share	$	(1.35	)		N/A
Diluted loss per share	$	(1.35	)		N/A

2. Summary of Significant Accounting Policies

Organization

EXCO Resources, Inc., (the Company), a Texas corporation, was formed in October 1955 and became a wholly-owned subsidiary of Holdings on July 29, 2003 pursuant to the merger transaction described in Note 1 above. Our operations consist primarily of acquiring interests in producing oil and natural gas properties located in the continental United States and Canada. We also act as the operator of some of these properties and receive overhead reimbursement fees as a result.

F-12

Principles of Consolidation

The accompanying consolidated balance sheet as of December 31, 2003 and the results of operations, cash flows and comprehensive income for the 156 day period from July 29, 2003 to December 31, 2003 are for EXCO and its subsidiaries and represent the stepped up successor basis of accounting (New EXCO).

The accompanying consolidated balance sheet as of December 31, 2002 and the results of operations, cash flows and comprehensive income for the 209 day period from January 1, 2003 to July 28, 2003 and for the years ended December 31, 2001 and 2002 are for EXCO and its subsidiaries and represent the predecessor basis of accounting (Old EXCO). Old EXCO accounted for its investment in Pecos-Gomez, L.P., which ceased operations during 2001 with all remaining net assets distributed to the partners, using the proportional method of consolidation. Under this method, only its combined 55.13742% interest in the partnership is reflected in the financial statements with no recording of minority interest. All inter-company transactions have been eliminated.

Functional Currency

The assets, liabilities and operations of Addison Energy Inc. (Addison), our Canadian subsidiary, are measured using the Canadian dollar as the functional currency. These assets and liabilities are translated into U.S. dollars using end-of-period exchange rates. Revenue and expenses are translated into U.S. dollars at the average exchange rates in effect during the period. Translation adjustments are deferred and accumulated in other comprehensive income.

Management Estimates

In preparing financial statements in conformity with accounting principles generally accepted in the United States, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. The most significant estimates pertain to proved oil, natural gas and NGL reserve volumes, future development, dismantlement and abandonment costs, valuation of deferred tax assets, estimates relating to certain oil, natural gas and NGL revenues and expenses and the fair market value of derivatives and equity securities. Actual results may differ from management's estimates.

Cash Equivalents and Marketable Securities

We consider all highly liquid investments with maturities of three months or less when purchased, to be cash equivalents.

We have evaluated our investment policies in accordance with Statement of Financial Accounting Standards (SFAS) No. 115, "Accounting for Certain Investments in Debt and Equity Securities" and determined that all of our investment securities, other than cash equivalents, are to be classified as available for sale. Available for sale securities are carried at fair value, with the unrealized gains and losses reported in other comprehensive income. Realized gains and losses are included in other income on the consolidated statement of operations. Declines in value that are considered to be "other than temporary" on available for sale securities are shown separately on the consolidated statement of operations. Realized gains and losses are determined using the first-in, first-out method.

F-13

Concentration of Credit Risk and Accounts Receivable

Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash, trade receivables and our derivative financial instruments. We place our cash with high credit quality financial institutions. We sell oil and natural gas to various customers. In addition, we participate with other parties in the drilling, completion and operation of oil and natural gas wells. The majority of our accounts receivable are due from either purchasers of oil, natural gas or NGLs or participants in oil and natural gas wells for which we serve as the operator. Generally, operators of oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells. Oil, natural gas and NGL sales are generally unsecured. We have provided for credit losses in the financial statements and these losses have been within management's expectations. The allowance for doubtful accounts receivable aggregated $220,000 and $198,000 at December 31, 2002 and 2003, respectively. We place our derivative financial instruments with financial institutions and other firms that we believe have high credit ratings. For a discussion of the credit risks associated with our commodity price risk management activities, please see "Note 11. Derivative Financial Instruments."

Derivative Financial Instruments

We engage in commodity price risk management activities to protect against commodity price fluctuations and in connection with the incurrence of debt related to our acquisition activities. Our objective in entering into these commodity price risk management transactions is to manage price fluctuations and achieve a more predictable cash flow for our development and acquisition activities. These derivatives are not held for trading purposes.

Old EXCO adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" on January 1, 2001. In accordance with the transition provisions of SFAS 133, it recorded a cumulative-effect loss in other comprehensive income of $1.1 million to recognize the fair value of our derivatives designated as cash-flow hedging instruments at the date of adoption.

Prior to July 28, 2003, Old EXCO's derivative financial instruments were designated as cash flow hedges. On the date the derivative contract was entered into, it designated the derivative as a hedge. Changes in the fair value of a derivative that were highly effective as a cash flow hedge were recorded in other comprehensive income, until earnings were affected by the variability of cash flows.

Old EXCO formally documented all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedge transactions. This process included linking all derivatives that were designated as cash flow hedges to forecasted transactions. Old EXCO also formally assessed, both at the hedge's inception and on an ongoing basis, whether the derivatives that were used in hedging transactions were highly effective in offsetting changes in cash flows of hedged items. When it was determined that a derivative was not highly effective as a hedge or that it has ceased to be a highly effective hedge, Old EXCO discontinued hedge accounting prospectively, as discussed below.

Old EXCO discontinued hedge accounting prospectively when: (1) it was determined that the derivative was no longer highly effective in offsetting changes in cash flows of a hedged item; (2) the derivative expired or was sold, terminated or exercised; (3) the derivative was not designated as a hedge instrument, because it was unlikely that a forecasted transaction would occur; or (4) management determined that designation of the derivative as a hedge instrument was no longer appropriate.

F-14

Effective as of November 30, 2001, Old EXCO ceased hedge accounting for its hedge transactions then in place with Enron North America, the counterparty to its swap agreements, due to Enron North America's bankruptcy filing. See "Note 11. Derivative Financial Instruments" for a discussion of these derivative transactions.

Effective July 29, 2003, in connection with the going private transaction, New EXCO discontinued hedge accounting for all existing derivatives. Currently, New EXCO does not designate derivative transactions as hedges for accounting purposes; accordingly, all derivatives are recorded at fair value on our consolidated balance sheet and changes in the fair value of derivative financial instruments are recognized currently in our consolidated statement of operations as commodity price risk management income.

For the years ended December 31, 2001 and 2002 and for the 209 day period from January 1, 2003 to July 28, 2003, Old EXCO recorded as other income in the statement of operations, a gain of $3.5 million, a loss of $886,000 and a loss of $2.5 million, respectively, from hedge ineffectiveness. For the years ended December 31, 2001 and 2002 and for the 209 day period from January 1, 2003 to July 28, 2003, Old EXCO also recorded as other income in the statement of operations $1.3 million, $7.0 million and $1.8 million, respectively, from derivative transactions for which hedge accounting was discontinued.

Oil and Natural Gas Properties

We have recorded oil and natural gas properties at cost using the full cost method of accounting. Under the full cost method, all costs associated with the acquisition, exploration or development of oil and natural gas properties are capitalized as part of the full cost pool. Capitalized costs are limited to the aggregate of the after-tax present value of future net revenues plus the lower of cost or fair market value of unproved properties. The full cost pool is comprised of lease and well equipment and exploration and development costs incurred, plus intangible acquired proved leaseholds.

Unproved oil and natural gas properties are excluded from the calculation of depreciation, depletion and amortization until it is determined whether or not proved reserves can be assigned to such properties. At December 31, 2002 and 2003, the $5.0 million and $9.2 million, respectively, in unproved oil and natural gas properties resulted from the allocation of the estimated fair value of undeveloped acreage and possible and probable reserves. We assess our unproved oil and natural gas properties for impairment on a quarterly basis.

Depreciation, depletion and amortization of evaluated oil and natural gas properties is calculated separately for the United States and Canadian full cost pools using the unit-of-production method based on total proved reserves, as determined by independent petroleum reservoir engineers.

Sales, dispositions and other oil and natural gas property retirements are accounted for as adjustments to the full cost pool, with no recognition of gain or loss unless the disposition would significantly alter the amortization rate.

At the end of each quarterly period, the unamortized cost of proved oil and natural gas properties, net of related deferred income taxes, is limited to the sum of the estimated future net revenues from proved properties using current period-end prices discounted at 10%, adjusted for related income tax effects (ceiling test). This ceiling test calculation is done separately for the United States and Canadian full cost pools.

F-15

The calculation of the ceiling test is based upon estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

As a result of low oil and natural gas prices at September 30, 2001 and December 31, 2001, we recorded pre-tax non-cash ceiling test write-downs during the year ended December 31, 2001, totaling approximately $49.6 million (of which $28.7 million was from the United States full cost pool and $20.9 million was from the Canadian full cost pool). As a result of lower prices for Canadian natural gas at June 30, 2002, Old EXCO had a pre-tax non-cash ceiling test write-down of our oil and natural gas properties during the second quarter of 2002 of $17.5 million ($9.7 million after-tax) from the Canadian full cost pool.

Office and Field Equipment

Office and field equipment are capitalized at cost and depreciated on a straight line basis over their estimated useful lives.

Environmental Costs

Environmental costs that relate to current operations are expensed as incurred. Remediation costs that relate to an existing condition caused by past operations are accrued when it is probable that those costs will be incurred and can be reasonably estimated based upon evaluations of currently available facts related to each site.

Deferred Abandonment and Asset Retirement Obligations

Prior to 2003, Old EXCO provided for future site restoration costs on its Canadian oil and natural gas properties based upon management's estimates. The costs were being recognized over the remaining life of proved reserves by a charge to depreciation, depletion and amortization in the statement of operations with a related increase in the non-current deferred abandonment liability. Actual expenditures for site restoration were charged to the deferred abandonment liability when incurred. Old EXCO did not provide for site restoration costs on its United States properties as it estimated that salvage values would exceed the asset retirement costs.

In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, "Accounting for Asset Retirement Obligations". The statement requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. Old EXCO adopted the new rules on asset retirement obligations on January 1, 2003, for both its U.S. and Canadian operations. Application of the new rules resulted in an increase in net proved developed and undeveloped oil and natural gas properties of approximately $11.4 million, recognition of an asset retirement obligation liability of approximately $10.4 million, an increase in deferred income tax liability of approximately $690,000, and a cumulative effect of adoption that will increase net income and stockholder's equity by approximately $255,000. The increase in net income resulting from the cumulative effect of the change in accounting

F-16

principle increased basic and diluted earnings per share by $0.03 for the 209 day period from January 1 to July 28, 2003.

The following pro forma data summarizes our net income as if the provisions of SFAS 143 had been applied as of January 1, 2001, including an associated pro forma asset retirement obligation on that date of $4.3 million:

	Year Ended December 31, 2001			Year Ended December 31, 2002
	(In thousands)
Net income (loss), as reported	$	(39,347	)	$	(967	)
Pro forma adjustments to reflect retroactive adoption of SFAS 143		211			21

Pro forma net income (loss)	$	(39,136	)	$	(946	)

The following is a reconciliation of our asset retirement obligations at December 31, 2003 (in thousands of dollars):

Deferred abandonment costs at December 31, 2002	$	2,176
Cumulative effect of change in accounting principle		10,433

Asset retirement obligation as of January 1, 2003		12,609
Activity during the 209 day period from January 1, 2003 to July 28, 2003:
Liabilities incurred during period		239
Liabilities settled during period		(625	)
Accretion of discount		737
Effect of foreign currency conversions		786

Asset retirement obligation at July 28, 2003		13,746
Adjustment to liability due to purchase of EXCO by Holdings, timing and other		1,998
Activity during the 156 day period from July 29, 2003 to December 31, 2003:
Liabilities incurred during period		1,028
Liabilities settled during period		(334	)
Accretion of discount		528
Effect of foreign currency conversions		776

Asset retirement obligation at December 31, 2003	$	17,742

We have no assets that are legally restricted for purposes of settling asset retirement obligations.

Revenue Recognition and Gas Imbalances

We use the sales method of accounting for oil and natural gas revenues. Under the sales method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers. Gas imbalances at December 31, 2002 and 2003 were not significant; however, we have recorded a liability of $92,000 at December 31, 2002 and 2003 for those wells where there are insufficient reserves to retire the imbalance.

F-17

Capitalization of Internal Costs

We capitalize as part of our proved developed oil and natural gas properties a portion of salaries paid to employees who are directly involved in the acquisition and exploitation of oil and natural gas properties. During the years ended December 31, 2001 and 2002, the 209 day period from January 1, 2003 to July 28, 2003 and the 156 day period from July 29, 2003 to December 31, 2003, we have capitalized $1.1 million, $1.1 million, $760,000 and $807,000, respectively.

Overhead Reimbursement Fees

We have classified fees from overhead charges billed to working interest owners, including ourselves, of $2.9 million, $2.9 million, $1.4 million and $1.1 million for the years ended December 31, 2001 and 2002, the 209 day period from January 1, 2003 to July 28, 2003 and the 156 day period from July 29, 2003 to December 31, 2003, respectively, as a reduction of general and administrative expenses in the accompanying statements of operations. Our share of these charges was $1.8 million, $1.8 million, $1.1 million and $830,000 for the years ended December 31, 2001 and 2002, for the 209 day period from January 1, 2003 to July 28, 2003 and the 156 day period from July 29, 2003 to December 31, 2003, respectively, and are classified as oil and natural gas production costs.

Earnings Per Share

SFAS No. 128, "Earnings per Share," required Old EXCO to present two calculations of earnings per common share for the years ended December 31, 2001 and 2002 and for the 209 day period from January 1, 2003 to July 28, 2003. Basic earnings per common share equals earnings on common stock divided by weighted average common shares outstanding during the period. Diluted earnings per common share equals net income divided by the sum of weighted average common shares outstanding during the period plus any dilutive common stock equivalents assumed to be issued. Common stock equivalents are shares assumed to be issued if its 5% convertible preferred stock were converted and our outstanding stock options and warrants, if any, were exercised.

Since Old EXCO reported a net loss for the years ended December 31, 2001 and 2002, its common stock equivalents are considered to be anti-dilutive and are not considered in the earnings per share calculation. For the year ended December 31, 2001, employee and director stock options, and its 5% convertible preferred stock would have increased the weighted average number of shares outstanding by approximately 469,000 shares and 2,537,000 shares, respectively. For the year ended December 31, 2002, employee and director stock options, and its 5% convertible preferred stock would have increased the weighted average number of shares outstanding by approximately 467,000 shares and 5,004,869 shares, respectively. For the 209 day period from January 1, 2003 to July 28, 2003, the common stock equivalents of employee and director stock options and the 5% convertible preferred stock, which would have increased the weighted average number of shares outstanding by approximately 535,000 shares and 4,363,000 shares, respectively, are considered to be anti-dilutive and are not considered in the earnings per share calculation.

Earnings per share subsequent to July 28, 2003 (after the going private transaction) are not presented since New EXCO is wholly-owned by Holdings, our parent.

F-18

Stock Options and Benefit Plan

SFAS No. 123, "Accounting for Stock-Based Compensation" defines a fair value based method of accounting for employee stock compensation plans, but allows for the continuation of the intrinsic value based method of accounting to measure compensation cost prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB 25). For companies electing not to change their accounting, SFAS 123 requires pro forma disclosures of earnings and earnings per share as if the change in accounting provision of SFAS 123 has been adopted.

Old EXCO elected to continue to utilize the accounting method prescribed by APB 25, under which no compensation cost was recognized, and adopted the disclosure requirements of SFAS 123. As a result, SFAS 123 had no effect on Old EXCO's financial condition or results of operations at December 31, 2001 and 2002 and the years then ended and for the 209 day period from January 1, 2003 to July 28, 2003. Stock based compensation expense reflected in the table below for the year ended December 31, 2001 and 2002 and for the 209 day period from January 1, 2003 to July 28, 2003, is a result of options issued under Old EXCO's 1998 Stock Option Plan that were issued subject to shareholders' approval and options that were issued to the management and key employees of Addison. See "Note 7. Stock Transactions" for a further description of these stock options.

Had compensation costs for these plans been determined consistent with SFAS 123, Old EXCO's net income (loss) and earnings per share (EPS) would have been adjusted to the following pro forma amounts (New EXCO has not issued any stock options):

		December 31, 2001			December 31, 2002			For the 209 Day Period From January 1, 2003 to July 28, 2003
		(In thousands, except per share amounts)
Stock based compensation expense (net of taxes)	As Reported Pro Forma	$ $	— 1,118		$ $	991 2,487		$ $	6,969 2,578
Net income (loss)	As Reported Pro Forma	$ $	(39,347 (40,465	) )	$ $	(967 (2,463	) )	$ $	1,032 5,423
Basic EPS	As Reported Pro Forma	$ $	(5.96 (6.12	) )	$ $	(0.88 (1.09	) )	$ $	(0.20 0.35	)
Diluted EPS	As Reported Pro Forma	$ $	(5.96 (6.12	) )	$ $	(0.88 (1.09	) )	$ $	(0.20 0.33	)

We sponsor a 401(k) plan for our U.S. employees and match up to 100% of employee contributions based on years of service with us. Our matching contributions of $100,000, $151,000, $155,000 and $59,000 for the years ended December 31, 2001 and 2002 and for the period from January 1, 2003 to July 28, 2003 and for the 156 day period from July 29, 2003 to December 31, 2003, respectively, have been included as general and administrative expense.

Reclassified Prior Year Amounts

Certain prior year amounts have been reclassified to conform to current year presentation.

F-19

3. Intangible Acquired Proved Leaseholds and Lease and Well Equipment

SFAS No. 141, "Business Combinations", and SFAS No. 142, "Goodwill and Intangible Assets", were issued in June 2001 and became effective for us on July 1, 2001 and January 1, 2002, respectively. SFAS No. 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. Additionally, SFAS No. 141 requires companies to disaggregate and report goodwill separately from other intangible assets. SFAS No. 142 established new guidelines for accounting for goodwill and other intangible assets. Under SFAS No. 142, goodwill and other indefinite lived intangible assets are not amortized but rather are reviewed annually for impairment. One interpretation being considered relative to these standards is that oil and natural gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves for both undeveloped and developed leaseholds should be classified separately from oil and natural gas properties, as intangible assets on the balance sheet. In addition, the disclosures required by SFAS No. 141 and No. 142 relative to intangibles would be included in the notes to financial statements. In connection with the merger, we have adopted a policy of including these costs as part of its oil and natural gas properties on its consolidated balance sheet as of December 31, 2003. The financial statements of Old EXCO at December 31, 2002 as originally presented reflected this interpretation; however, since there are various interpretations relative to this standard, we have reclassified the December 31, 2002 amounts to reflect the presentation at December 31, 2003.

Since we account for oil and natural gas activities under the full cost method, we understand that the interpretation of SFAS No. 141 and No. 142 as described above would only affect our balance sheet classification of proved oil and natural gas leaseholds acquired after June 30, 2001 and our unproved oil and natural gas leaseholds. Our results of operations and cash flows would not be affected, since these oil and natural gas mineral rights held under lease and other contractual arrangements representing the rights to extract such reserves would continue to be amortized in accordance with full cost rules. Prior to the merger, Old EXCO made a reclassification within its balance sheet to separately identify intangible leasehold interests acquired after July 1, 2001; however, subsequent to the merger and at December 31, 2003 we have disclosed leaseholds interests within the footnotes as discussed below.

At December 31, 2002 and 2003, we had undeveloped leaseholds of approximately $5.0 million and $9.2 million, respectively, that would be classified as "intangible undeveloped leasehold" and developed leaseholds of an estimated $76.4 million and $333.4 million, respectively, that would be classified as "intangible developed leasehold" on our balance sheet if we applied the interpretation currently being considered. We will continue to classify our oil and natural gas mineral rights held under lease and other contractual rights representing the right to extract such reserves as oil and natural gas properties until further guidance is provided.

4. Marketable Securities

Marketable securities at December 31, 2002 and 2003, are common stock investments in public corporations, which are classified as available for sale securities. At December 31, 2002, Old EXCO's cost basis of marketable securities was $2.7 million while the aggregate fair value was $1.8 million. At December 31, 2003, our cost basis of marketable securities was $784,000 while the aggregate fair value was $818,000

F-20

At December 31, 2003, we had gross unrealized holding gains from available for sale securities of $53,000. We had gross unrealized holding losses from available for sale securities of $87,000 at December 31, 2003. Investment income is presented in the following table:

	December 31, 2001		December 31, 2002			For the 209 Day Period From January 1, 2003 to July 28, 2003		For the 156 Day Period From July 29, 2003 to December 31, 2003
	(In thousands)
Gross proceeds from sales of marketable securities	$	993	$	—		$	422	$	1,393
Gross realized gains from sales of marketable securities		107		—			245		—
Gross realized losses from sales of marketable securities		—		(1	)		—		(30	)
Unrealized net loss included in other comprehensive income		—		(878	)		—		34
Reclassification adjustment for impairment of marketable securities		—		1,136			—		—

5. Long-Term Debt

Long-term debt is summarized as follows:

	December 31,
	2002		2003
	(In thousands)
Notes payable	$	97,943	$	157,951
Senior term loan		—		50,000
Less current maturities		—		—

Long-term debt	$	97,943	$	207,951

Credit Agreements

On January 27, 2004, we amended and restated our U.S. credit agreement and our Canadian credit agreement. See "Note 15. Issuance of Senior Unsecured Notes and the Acquisition of North Coast Energy, Inc." for a description of the changes to the U.S. and Canadian credit agreements.

U.S. Credit Agreement. At December 31, 2003, our restated U.S. credit agreement provided for borrowings of up to $124.0 million under a revolving credit facility with a borrowing base of $95.0 million. At December 31, 2003, we had approximately $49.5 million of outstanding indebtedness and letter of credit commitments of $275,000 under our U.S. credit agreement. The borrowing base is to be redetermined as of May 1, 2004, and each November 1 and May 1 thereafter. Borrowings under the U.S. credit agreement are secured by a first lien mortgage providing a security interest in 90% of our U.S. oil and natural gas properties. At our election, interest on borrowings may be either (i) the greater of the administrative agent's prime rate or the federal funds effective rate plus an applicable

F-21

margin or (ii) LIBOR (London InterBank Offered Rate) plus an applicable margin. At December 31, 2003, the six months LIBOR rate was 1.22%, which would result in an interest rate of approximately 2.72% on any new indebtedness we may incur under the U.S. credit agreement. We are required to pay a commitment fee on the unused portion of the U.S. borrowing base each quarter. The commitment fee ranges from 0.375% to 0.5%, based upon our borrowing base usage during the applicable quarter.

Canadian Credit Agreement. At December 31, 2003, our restated Canadian credit agreement provides for borrowings of up to U.S. $186.5 million under a revolving credit facility with a borrowing base of CDN $140.7 million ($108.5 million USD using the exchange rate on December 31, 2003). At December 31, 2003, we had approximately CDN $140.7 million (approximately $108.5 million USD using the exchange rate on December 31, 2003) of outstanding indebtedness under our Canadian credit agreement. The borrowing base is to be redetermined as of May 1, 2004, and each November 1 and May 1 thereafter. Borrowings under the credit agreement are secured by a first lien mortgage providing a security interest in 90% of our Canadian oil and natural gas properties. At our election, interest on borrowings may be either (i) the Canadian prime rate plus an applicable margin or (ii) the Banker's Acceptance rate plus an applicable margin. At December 31, 2003, the six months Banker's Acceptance rate was 2.66%, which would result in an interest rate of approximately 4.66% on any new indebtedness we may incur under the Canadian credit agreement. We are required to pay a commitment fee on the unused portion of the Canadian borrowing base each quarter. The commitment fee ranges from 0.375% to 0.5%, based upon our borrowing base usage during the applicable quarter.

Financial Covenants and Ratios. The U.S. and the Canadian credit agreements contain certain financial covenants and other restrictions which require that we:

•: maintain a ratio of our consolidated current assets to consolidated current liabilities (as defined under our credit agreements) of at least 1.0 to 1.0 at the end of any fiscal quarter;
•: not permit our ratio of consolidated funded debt (other than the senior term loan) to consolidated EBITDA (as defined under our credit agreements) to be greater than 3.75 to 1.0 at the end of each fiscal quarter; and
•: not permit our ratio of consolidated EBITDA (as defined under our credit agreements) to consolidated interest expense to be less than 2.5 to 1.0 at the end of each fiscal quarter.

Additionally, the credit agreements contain a number of other covenants regarding our liquidity and capital resources, including restrictions on our ability to incur additional indebtedness, restrictions on our ability to pledge assets, and prohibit the payment of dividends on our common stock. As of December 31, 2003, we were in compliance with the covenants contained in our U.S. and Canadian credit agreements.

U.S. Senior Term Loan. On October 17, 2003, we entered into a $50.0 million senior term credit agreement. We have borrowed all $50.0 million under the senior term agreement and we used the proceeds to repay a portion of our indebtedness under our U.S. credit agreement. Borrowings under the term loan are collateralized by a second lien pledge of 65% of the stock of Addison Energy Inc. and 100% of the stock of Taurus Acquisition, Inc. Interest on borrowings are at LIBOR plus an applicable margin which is fixed for periods not to exceed six months each during the life of the term loan. At December 31, 2003, the LIBOR rate plus applicable margin on the term loan was 6.12%. The U.S. senior term loan was paid in full on January 27, 2004 from the proceeds of the $350 million 7¹/4%

F-22

senior unsecured notes. See "Note 15. Issuance of Senior Unsecured Notes and the Acquisition of North Coast Energy, Inc."

Dividend Restrictions. We have not paid any cash dividends on our common stock, and do not anticipate paying cash dividends on our common stock in the foreseeable future. In addition, our credit agreements currently prohibit us from paying dividends on our common stock. Even if our credit agreements permitted us to pay cash dividends, we can make those payments only from our surplus (the excess of the fair value of our total assets over the sum of our liabilities plus our total paid-in share capital). In addition, we can pay cash dividends only if after paying those dividends we would be able to pay our liabilities as they become due.

6. Income Taxes

The sources of income (loss) before income taxes were as follows (in thousands):

		For the years ended December 31,
		For the years ended December 31,						209 Day Period from January 1 to July 28, 2003			156 Day Period from July 29 to December 31, 2003
		2001			2002			209 Day Period from January 1 to July 28, 2003			156 Day Period from July 29 to December 31, 2003
United States		$	(18,555	)	$	3,731		$	(7,956	)	$	(7,887	)
Canada			(20,846	)		(11,380	)		13,534			6,217

	Total	$	(39,401	)	$	(7,649	)	$	5,578		$	(1,670	)

The income tax provision attributable to our income (loss) before income taxes consists of the following:

			December 31, 2001			December 31, 2002			For the 209 Day Period From January 1, 2003 to July 28, 2003			For the 156 Day Period From July 29, 2003 to December 31, 2003
			(In thousands)
Current:
	U.S.
	Federal		$	1,157		$	(2,672	)	$	—		$	—
	State			—			—			(181	)		—
	Canadian			—			—			2,272			1,294

				1,157			(2,672	)		2,091			1,294

Deferred:
	U.S.
	Federal			(1,211	)		—			—			(2,692	)
	State			—			—			—			(131	)
	Canadian			—			(4,010	)		2,710			(4,318	)

				(1,211	)		(4,010	)		2,710			(7,141	)

		Total income tax (benefit)	$	(54	)	$	(6,682	)	$	4,801		$	(5,847	)

F-23

We have net operating loss carryforwards (NOLs) for United States income tax purposes that have either been generated from our operations or were purchased in our acquisitions. Our ability to use the purchased NOLs has been restricted by Section 382 of the Internal Revenue Code due to ownership changes which occurred on December 19, 1997 and July 29, 2003, as well as the change in ownership of Rio Grande, Inc. which occurred on March 16, 1999. We estimate that approximately $7.2 million of the NOLs limited by Section 382 may expire prior to their utilization. Expiration is expected to occur from 2005 through 2019. Accordingly, a valuation allowance of $2.6 million exists to reserve the portion of NOL's in excess of the Section 382 limitation which we believe will more likely than not expire unutilized.

Old EXCO recognized a valuation allowance to offset its U.S. deferred tax assets. During the 209 day period from January 1, 2003 to July 28, 2003, we had a U.S. operating loss and we accordingly increased our valuation allowance to reflect that loss. Effective with the merger, we are now in a deferred tax liability position in the United States due to the step up in basis for book purposes related to purchase accounting and the carryover of tax basis. Except for the valuation allowance against NOLs limited by Section 382 described above, no valuation allowance was recognized in the purchase price allocation at the acquisition date or at December 31, 2003.

We have not provided any U.S. deferred income taxes on the undistributed earnings of our Canadian subsidiary based upon the determination that at this time those earnings will be indefinitely reinvested in Canada. As of December 31, 2003, there were no material cumulative undistributed earnings of this subsidiary.

In the 156 day period ended December 31, 2003, we recognized a deferred income tax benefit of approximately $4.9 million related to Canadian legislation which became effective on November 7, 2003, to phase in reduced income tax rates and allow for deductibility of crown royalties.

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of our deferred tax liabilities and assets are as follows:

		December 31,
		2002			2003
		(In thousands)
Deferred tax assets:
Net operating loss carryforwards—United States		$	2,719		$	15,916
Tax basis of oil and natural gas properties in excess of book basis—United States			771			—
Basis difference in fair value of hedges			(48	)		2,007
Credit carryforwards			5			5
Other			46			530
Valuation allowance for deferred tax assets			(3,493	)		(2,673	)

	Total deferred tax assets		—			15,785

Deferred tax liabilities:
Book basis of oil and natural gas properties in excess of tax basis—United States			—			27,924
Book basis of oil and natural gas properties in excess of tax basis—Canada			7,978			33,760

	Total deferred tax liabilities		7,978			61,684

	Net deferred tax liabilities	$	7,978		$	45,899

F-24

A reconciliation of our income tax provision (benefit) computed by applying the statutory United States federal income tax rate to our income (loss) before income taxes for the years ended December 31, 2001 and 2002, the 209 day period from January 1, 2003 to July 28, 2003 and the 156 day period from July 29, 2003 to December 31, 2003 is presented in the following table:

		2001			2002			For the 209 Day Period From January 1, 2003 to July 28, 2003			For the 156 Day Period From July 29, 2003 to December 31, 2003
		(In Thousands)
United States federal income taxes (benefit) at statutory rate of 34%		$	(13,396	)	$	(2,601	)	$	1,895		$	(567	)
Increases (reductions) resulting from:
	Adjustments to the valuation allowance		6,313			(4,126	)		2,447			—
	Rate difference on foreign taxes		—			(860	)		382			(208	)
	Adjustment due to enacted tax rate reductions in Canada		—			—			—			(4,941	)
	Non-deductible charges (non-taxable income)		7,928			675			195
	Other		(899	)		230			(118	)		(131	)

Tax provision before cumulative effect of change in accounting principles		$	(54	)	$	(6,682	)	$	4,801		$	(5,847	)

7. Stock Transactions

Issuance of Common Stock

During the year ended December 31, 2001, 17 employees, one of whom was also a director, exercised stock options covering 69,511 shares of Old EXCO's common stock at strike prices ranging from $6.00 per share to $15.125 per share. Old EXCO received aggregate proceeds of approximately $486,600 for these shares with $305,600 paid in cash and $181,000 being borrowed from the company.

During the year ended December 31, 2002, 24 employees exercised stock options covering 90,366 shares of Old EXCO's common stock at strike prices ranging from $6.00 per share to $15.50 per share. Old EXCO received aggregate proceeds of approximately $1,026,200 for these shares all of which was paid in cash.

In 1998 and 1999, Old EXCO loaned Douglas H. Miller, its Chairman and Chief Executive Officer, a total of $915,625 in order to enable him to exercise stock options granted to him under Old EXCO's 1998 stock option plan. Of the outstanding balance, $465,625 plus accrued interest was due and payable on November 29, 2002, and $450,000 plus accrued interest was due and payable on September 15, 2004. Mr. Miller paid all outstanding amounts owed under these loans on November 29, 2002. Under the terms of the Sarbanes-Oxley Act of 2002, we can no longer loan money to our executive officers or amend the terms of any agreements that were in place at the time the law was enacted. At December 31, 2002, Old EXCO had one executive officer with an outstanding loan balance of $60,000. This loan was used to exercise stock options granted under our 1998 Stock Option Plan and was paid in full at the time of the going private transaction.

F-25

The following table summarizes Old EXCO's stock option activity:

		Stock Options		Weighted Average Exercise Price Per Share
Options outstanding at December 31, 2000		1,398,599		$	8.32
	Granted	761,625		$	14.55
	Expired or canceled	(40,933	)	$	14.88
	Exercised	(69,511	)	$	7.00

Options outstanding at December 31, 2001		2,049,780		$	10.55
	Granted	172,668		$	16.10
	Expired or canceled	(82,251	)	$	13.64
	Exercised	(90,366	)	$	11.36

Options outstanding at December 31, 2002		2,049,831		$	10.85
	Granted	—			—
	Expired or canceled	(916,446	)	$	10.37
	Exercised	(1,133,385	)	$	11.24

Options outstanding at July 28, 2003		—			—

Options exercisable at July 28, 2003		—			—

The present value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model. The following assumptions were used:

Fair market value of stock at date of grant		$6.00 to $20.62
Option exercise prices		$6.00 to $20.62
Option term		10 years
Risk-free rate of return		10-year U.S. Treasury Notes
Company stock volatility		Based upon daily stock prices from January 1, 2000 through December 31, 2002
Company dividend yield		0%
Calculated Black-Scholes values		$2.60 to $8.94 per option

See "Note 2. Summary of Significant Accounting Policies—Stock Options" for a comparison of our net income/(loss) and net income/(loss) per share as reported and as adjusted for the pro forma effects of determining compensation expense in accordance with SFAS 123. All outstanding stock options were either exercised prior to or cashed out as a result of the going private transaction. New EXCO has not authorized or issued any stock options.

During the 209 day period from January 1, 2003 to July 28, 2003, Old EXCO recognized $3.6 million of stock-based compensation expense in general and administrative expense. This amount was paid to option holders at the time of the going private transaction to cancel all unexercised stock

F-26

options outstanding at that time. The amount represented the cumulative difference between the $18.00 per share proceeds and the exercise price of the outstanding stock options times the number of stock options outstanding.

As an incentive to the management and certain key employees of Addison, the board of directors of Addison established the Addison Energy Inc. Stock Option Plan effective June 30, 2002. Addison stock options were issued as of June 30, 2002, under the plan that, if fully exercised, would allow the participants to own in the aggregate 1,000 shares of Addison common stock, approximately 10% of the shares of common stock in Addison on a fully-diluted basis. The Addison stock options were exercisable for a term of five years from the date of the grant. The Addison stock options were subject to vesting. The vesting schedule is as follows:

Vesting Date		Cumulative Percent Vested
Prior to April 26, 2003		None
April 26, 2003		50%
April 26, 2004		75%
April 26, 2005		100%

The exercise price under the Addison stock option plan as of June 30, 2002 was CDN $1,031.61 per share. The price was determined by using a formula as set forth in the Addison stock option agreement. The formula was based upon:

•: The value of Addison's proved reserves;
•: The amount of any working capital surplus or deficiency;
•: Any capital contributions or distributions made after June 30, 2002;
•: Any debt owed to us, owed under the Canadian credit agreement or owed to other third parties;
•: The total exercise price of all outstanding Addison stock options under the plan;
•: The amount of deferred income tax liability incurred after June 30, 2002;
•: A calculated amount to allocate certain general and administrative costs that we incur that also benefit Addison; and
•: The ratio of the average trading price of our common stock divided by $18.25.

This formula was to be calculated as of December 31 of each year, beginning December 31, 2002, to determine the value of each share of Addison's common stock.

If an Addison stock option was exercised, we were obligated to purchase the shares of Addison common stock from the employee six months later at the then-current price as calculated using the above formula. Each employee receiving an Addison stock option entered into an agreement that restricts their ability to sell or transfer any Addison common stock acquired under the Addison stock option plan to any party other than to us.

The Addison stock options became fully vested and exercisable if any of the following occurs:

•: A person, or a group of people acting together, has the right to cast more than 50% of the votes when electing our directors;

F-27

•: Our shareholders approve a merger or other transaction that would result in our shareholders owning less than 50% of the combined entity; or
•: We sell the shares of Addison or substantially all of its assets.

The Merger (see "Note 1. The Merger") was a triggering event under the Addison stock option plan. We calculated the value of each share of Addison common stock as of the date of the event to be CND $10,014.50 per share. We paid approximately CDN $9.0 million in cash to the holders of the Addison stock options, which represented the difference between the calculated value per share and the Addison stock option exercise price times the number of shares of Addison common stock that the participant has the right to purchase under the Addison stock option plan.

The value of a share of Addison common stock was calculated to be CDN $7,013.94 per share as of December 31, 2002. The following table summarizes our Addison stock option activity:

		Stock Options	Weighted Average Exercise Price Per Share
Options outstanding at December 31, 2001		—	CDN $ —
	Granted	1,000	CDN $1,031.61
	Expired or canceled	—	—
	Exercised	—	—

Options outstanding at December 31, 2002		1,000	CDN $1,031.61
	Granted	—	—
	Expired or canceled	1,000	CDN $1,031.64
	Exercised	—	—

Options outstanding at July 29, 2003		—	—

During the year ended December 31, 2002 and for the 209 day period from January 1, 2003 to July 28, 2003, U.S. $1.4 million and U.S. $5.5 million of stock-based compensation expense for the Addison stock option plan has been recognized in general and administrative expense.

Issuance of Preferred Stock

Old EXCO was authorized to issue up to 10,000,000 shares of preferred stock, $.01 par value per share. On June 29, 2001, Old EXCO closed its rights offering to existing shareholders that resulted in the sale of 5,004,869 shares of 5% convertible preferred stock at $21.00 per share. Old EXCO raised a total of approximately $105.1 million in gross proceeds (approximately $101.2 million in net proceeds after fees and commissions), through the exercise of 4,466,869 rights and the sale of 538,000 shares of 5% convertible preferred stock by dealer managers. Old EXCO applied approximately $97.6 million of the offering proceeds to pay-off its bank loans and used the remaining proceeds for general corporate purposes. Dividends on the 5% convertible preferred stock were payable quarterly in cash and the dividend payment was approximately $1.3 million per quarter beginning September 30, 2001. Preferred stock dividends of approximately $2.7 million, $5.3 million and $2.6 million were paid during the years ended December 31, 2001 and 2002 and for the 209 day period from January 1, 2003 to July 28, 2003. Each share of 5% convertible preferred stock was converted into one share of Old EXCO's common stock on or before June 30, 2003.

F-28

8. Commitments and Contingencies

We lease our offices and certain equipment. Our rental expenses were approximately $476,000, $728,000, $544,000 and $382,000 for 2001, 2002, for the 209 day period from January 1, 2003 to July 28, 2003 and for the 156 day period from July 29, 2003 to December 31, 2003, respectively. Our future minimum rental payments under operating leases with remaining noncancellable lease terms at December 31, 2003, are as follows:

	Amount
	(In thousands)
2004	$	1,118
2005		1,229
2006		1,134
2007		833
2008		381
Thereafter		952

	$	5,646

In the ordinary course of business, we are periodically a party to lawsuits. We do not believe that any resulting liability from existing legal proceedings, individually or in the aggregate, will have a materially adverse effect on our results of operations or financial condition. There can be no assurances, however, that future costs will not be material to our operating results and liquidity.

9. Environmental Regulation

Various federal, state and local laws and regulations covering discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect our operations and the costs of our oil and natural gas exploitation, development and production operations. We do not anticipate that we will be required in the near future to expend amounts material in relation to the financial statements taken as a whole by reason of environmental laws and regulations. Because these laws and regulations are constantly being changed, we are unable to predict the conditions and other factors, over which we do not exercise control, that may give rise to environmental liabilities affecting us.

10. Geographic Operating Segment Information and Oil and Natural Gas Disclosures

We have operations in only one industry segment, that being the oil and natural gas exploration and production industry; however, we are organizationally structured along geographic operating segments. We have reportable operations in the United States and Canada. The following tables provide our geographic operating segment data. Operating segment data represents Canadian activity beginning April 26, 2001, when we acquired Addison Energy Inc.

F-29

The following table presents total capitalized costs of proved and unproved properties, accumulated depreciation, depletion and amortization related to oil and natural gas production, and total assets:

	United States			Canada			Total
	(In thousands)
As of December 31, 2001:
Oil and natural gas properties, including proved and unproved leasehold	$	135,306		$	105,230		$	240,536
Accumulated depreciation, depletion and amortization		(48,006	)		(27,695	)		(75,701	)

Oil and natural gas properties, net	$	87,300		$	77,535		$	164,835

Total assets	$	109,682		$	81,374		$	191,056

As of December 31, 2002:
Oil and natural gas properties, including proved and unproved leasehold	$	165,058		$	154,438		$	319,496
Accumulated depreciation, depletion and amortization		(56,581	)		(52,964	)		(109,545	)

Oil and natural gas properties, net	$	108,477		$	101,474		$	209,951

Total assets	$	130,829		$	110,345		$	241,174

As of December 31, 2003:
Oil and natural gas properties, including proved and unproved leasehold	$	189,969		$	235,905		$	425,874
Accumulated depreciation, depletion and amortization		(5,253	)		(6,678	)		(11,931	)

Oil and natural gas properties, net	$	184,716		$	229,227		$	413,943

Total assets	$	227,923		$	277,107		$	505,030

F-30

The results of operations from our oil and natural gas producing activities are as follows:

	United States			Canada			Corporate and Other			Total
	(In thousands)
Year ended December 31, 2001:
Oil and natural gas sales	$	53,017		$	8,220		$	—		$	61,237
Other income		4,147			—			1,556			5,703

		57,164			8,220			1,556			66,940

Production costs		21,395			2,519			—			23,914
Depreciation, depletion and amortization		9,743			4,501			—			14,244
General and administrative		—			—			4,806			4,806
Interest		—			—			3,133			3,133
Impairment of oil and natural gas properties		28,646			20,929			—			49,575
Uncollectible value of Enron hedges		10,669			—			—			10,669

		70,453			27,949			7,939			106,341

Income (loss) before income taxes		(13,289	)		(19,729	)		(6,383	)		(39,401	)
Income tax expense (benefit)		(4,518	)		(8,799	)		13,263			(54	)

Net income (loss)	$	(8,771	)	$	(10,930	)	$	(19,646	)	$	(39,347	)

	United States		Canada			Corporate and Other			Total
	(In thousands)
Year ended December 31, 2002:
Oil and natural gas sales	$	34,254	$	32,192		$	—		$	66,446
Other income		6,090		—			567			6,657

		40,344		32,192			567			73,103

Production costs		19,020		10,203			—			29,223
Depreciation, depletion and amortization		9,529		9,029			—			18,558
General and administrative		—		—			10,968			10,968
Interest		—		—			3,408			3,408
Impairment of oil and natural gas properties		—		17,459			—			17,459
Impairment of marketable securities		—		—			1,136			1,136

		28,549		36,691			15,512			80,752

Income (loss) before income taxes		11,795		(4,499	)		(14,945	)		(7,649	)
Income tax expense (benefit)		4,010		(2,007	)		(8,685	)		(6,682	)

Net income (loss)	$	7,785	$	(2,492	)	$	(6,260	)	$	(967	)

F-31

	United States			Canada		Corporate and Other			Total
	(In thousands)
For the 209 day period from January 1, 2003 to July 28, 2003:
Oil and natural gas sales, before hedge settlements	$	22,403		$	39,013	$	—		$	61,416
Other income		(781	)		—		(252	)		(1,033	)

		21,622			39,013		(252	)		60,383

Production costs		11,380			8,413		—			19,793
Depreciation, depletion and amortization		5,483			6,539		—			12,022
Accretion expense		320			417		—			737
General and administrative		—			—		19,272			19,272
Interest		—			—		2,981			2,981

		17,183			15,369		22,253			54,805

Income (loss) before income taxes		4,439			23,644		(22,505	)		5,578
Income tax expense (benefit)		1,509			9,756		(6,464	)		4,801

Net income (loss)	$	2,930		$	13,888	$	(16,041	)	$	777

	United States			Canada			Corporate and Other			Total
	(In thousands)
For the 156 Day Period From July 29, 2003 to December 31, 2003:
Oil and natural gas sales	$	21,767		$	24,366		$	—		$	46,133
Commodity price risk management activities		(10,800	)		(360	)		—			(11,160	)
Other income		—			—			239			239

		10,967			24,006			239			35,212

Production costs		7,331			7,193			—			14,524
Depreciation, depletion and amortization		5,513			6,499			—			12,012
Accretion expense		205			323			—			528
General and administrative		—			—			5,847			5,847
Interest		—			—			3,971			3,971

		13,049			14,015			9,818			36,882

Income (loss) before income taxes		(2,082	)		9,991			(9,579	)		(1,670	)
Income tax expense (benefit)		(708	)		4,122			(9,261	)		(5,847	)

Net income (loss)	$	(1,374	)	$	5,869		$	(318	)	$	4,177

Total assets	$	227,923		$	277,107		$	—		$	505,030

Goodwill	$	24,218		$	29,128		$	—		$	53,346

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11. Derivative Financial Instruments

In connection with the incurrence of debt related to our acquisition activities, our management has adopted a policy of entering into oil and natural gas derivative financial instruments to protect against commodity price fluctuations and to achieve a more predictable cash flow. SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activity," requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results from the hedged item on the income statement. Companies must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. For derivatives classified as cash flow hedges, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings. The ineffective portion of any change in the fair value of a derivative designated as a hedge is immediately recognized in earnings in our predecessor basis financial statements. Prior to July 29, 2003, all of Old EXCO's derivative financial instruments were designated as cash flow hedges. Beginning July 29, 2003, the date of the merger, we have not designated our derivative financial instruments as hedging instruments and, as a result, we recognize the change in the derivative's fair value currently in earnings (See Note 2).

Old EXCO entered into several swap transactions during 2000 and 2001 with Enron North America Corp., an affiliate of Enron Corp. (the Enron Hedges). On December 2, 2001, Enron Corp. and other Enron related entities, including Enron North America, filed for bankruptcy under Chapter 11 of the United States Code in the United States Bankruptcy Court in the Southern District of New York. We terminated all of our hedging contracts with Enron North America, effective as of December 5, 2001. We believe that we are owed approximately $15.3 million, including settlements already due but not paid, but the exact amount of the claim will be determined pursuant to the terms of the ISDA Master Agreement. We have valued the Enron derivative asset at $2.8 million, which represented our estimate of the fair market value of our bankruptcy claim against Enron North America, which is shown in the accompanying consolidated balance sheet in other assets. Our estimate of the value of our bankruptcy claim is based upon informal offers that we have received from third parties attempting to purchase those claims as well as management's best estimate of the financial condition of Enron's bankruptcy estate as determined from published reports and court filings related to the bankruptcy.

The following table sets forth our oil and natural gas derivatives as of December 31, 2003. The fair values at December 31, 2003 are estimated from quotes from the counterparties and represent the amount that we would expect to receive or pay to terminate the contracts at December 31, 2003. We

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have the right to offset amounts we expect to receive or pay among our individual counterparties. As a result, we have offset amounts for financial statement presentation purposes.

Natural Gas:		Volume mmbtu/bbls	Weighted Average Strike Price		Weighted Average Differential to NYMEX			Fair Value at December 31, 2003
								(In thousands)
Swaps:
	2004	13,054	$	4.76				$	(8,839	)
	2005	10,147		4.75					(1,942	)
	2006	5,475		4.64					(410	)
	2007	4,563		4.56					(286	)
	2008	1,830		4.51					(110	)
	2009	1,825		4.51					(89	)
	2010	1,825		4.51					(72	)
	2011	1,825		4.51					(66	)
	2012	1,830		4.51					(74	)
	2013	1,825		4.51					(92	)

		44,199

Floor Prices:
	2004	3,221		4.50					705
	2005	1,059		4.25					395

		4,280

Basis Protection Swaps:
	2004	408			$	(0.58	)		115

		408

Total Natural Gas									(10,765	)

Oil:
	Swaps:
	2004	764		24.52					(4,340	)
	2005	329		25.65					(570	)

		1,093

Total Oil									(4,910	)

Total Oil and Natural Gas								$	(15,675	)

At December 31, 2003, the average forward NYMEX oil prices per Bbl for calendar 2004 and 2005 were $26.64 and $25.29, respectively and the average forward NYMEX natural gas price per Mmbtu for calendar 2004 and 2005 were $4.81 and $4.88, respectively.

Oil and natural gas revenues for the years ended December 31, 2001 and 2002, include a net gain of $6.3 million and a net loss of $7.7 million, respectively, from the settlement of cash flow hedges. For the years ended December 31, 2001 and 2002, other income included a gain of $3.5 million and a loss of $886,000, respectively, from hedge ineffectiveness.

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12. Acquisitions and Dispositions

We have accounted for acquisitions in accordance with APB No. 16, "Business Combinations" and SFAS 141 where applicable.

Significant transactions which closed during 2001:

STB Energy Properties Acquisition.

On March 8, 2001, we acquired from STB Energy, Inc. oil and natural gas properties located in Louisiana, Oklahoma, Texas and Nebraska. As of January 1, 2001, estimated total proved reserves net to our interest included approximately 694,000 Bbls of oil and 9.5 Bcf of natural gas from 125 gross (78.3 net) wells. The purchase price consisted of $15.0 million in cash ($14.8 million after contractual adjustments).

Addison Energy Inc. Acquisition.

On April 26, 2001, we acquired all of the outstanding common stock of Addison Energy Inc. (Addison), which is headquartered in Calgary, Alberta, Canada. At the date of acquisition, Addison owned interests in 95 gross (85.03 net) wells located in Alberta and Addison operated 91 of these wells. The Addison properties included approximately 27,672 gross and 23,994 net developed acres and approximately 38,947 gross and 28,795 net undeveloped acres. As of January 1, 2001, estimated total proved reserves net to our interest acquired in this acquisition included approximately 2.1 million Bbls of oil and NGLs and 36.9 Bcf of natural gas. After adjustments for working capital and long-term debt, we paid approximately $44.4 million (CDN $68.5 million) for Addison. We paid the adjusted purchase price from the proceeds of borrowings under our new U.S. and Canadian credit agreements. The price was determined through arms-length negotiation between the parties.

Pecos County Properties Acquisitions.

On March 24, 2000, Pecos-Gomez, L.P. (previously known as Humphrey-Hill, L.P.) (the Partnership) acquired 8 gross (4.25 net) producing wells in Pecos County, Texas for $10.2 million. As of January 1, 2000, the acquired properties were estimated to contain total proved reserves of 25.1 Bcf of natural gas. At the time of the acquisition, EXCO was the general partner of the Partnership and owned a 1% interest in the Partnership as the general partner and a 50% interest as a limited partner. The acquisition price was partially funded from the proceeds of a credit facility established by the Partnership with Bank of America, N.A. On May 16, 2000, EXCO acquired an additional 4.1% limited partnership interest in the Partnership. On July 3, 2001, the Partnership conveyed all of its oil and natural gas property interests to its partners and began the process to dissolve the Partnership. Also on July 3, 2001, EXCO acquired additional interests in the properties from two of the limited partners for $8.8 million (approximately $7.5 million after contractual adjustments). In addition, EXCO received an assignment of the existing Partnership hedge contract. Borrowings under the Partnership credit facility of $3.9 million were also repaid at the time of the acquisition and the credit facility was canceled.

PrimeWest Properties Acquisition.

On December 18, 2001, Addison, our Canadian subsidiary, acquired oil and natural gas properties located in Alberta, Canada. As of December 31, 2001, total proved reserves net to our interest included approximately 3.6 million barrels of oil and NGLs, and 27.1 Bcf of natural gas. Estimated daily production, net to our interest, in December 2001, was approximately 600 barrels of oil and NGLs, and 4,100 Mcf of natural gas from the acquired properties. The effective date of this transaction was

F-35

December 18, 2001. The purchase price was approximately $33.8 million or CDN $53.6 million cash ($33.6 million or CDN $53.3 million after contractual adjustments), funded with borrowings under our Canadian credit agreement.

Significant transactions which closed during 2002:

Medicine River Properties Acquisition.

On April 29, 2002, Addison acquired oil and natural gas properties located in the Medicine River, Garrington, Gull Lake and Sylvan Lake areas in Alberta, Canada. The effective date of this transaction was January 1, 2002. As of January 1, 2002, estimated total proved reserves net to our interest included approximately 1.6 million Bbls of oil and NGLs, and 19.5 Bcf of natural gas. The purchase price was approximately $25.8 million or CDN $40.5 million ($24.7 million or CDN $36.3 million after contractual adjustments), funded with borrowings under our U.S. and Canadian credit agreements.

DJ Basin Properties Acquisition.

On November 1, 2002, we acquired oil and natural gas properties located in the DJ Basin in Colorado. As of October 1, 2002, estimated total proved reserves net to our interest included approximately 2.1 Mmbbls of oil and NGLs, and 13.5 Bcf of natural gas from 111 gross (103 net) wells. Net daily production in September 2002, was approximately 630 Bbls of oil and NGLs, and 3.7 Mmcf of natural gas. The purchase price was approximately $22.0 million cash ($21.1 million after contractual adjustments), funded with $19.7 million of bank debt from our U.S. credit agreement and $1.4 million from surplus cash.

Transactions that occurred during 2003:

During the 209 day period from January 1, 2003 to July 28, 2003, we completed several oil and natural gas property acquisitions in the United States and Canada. The total purchase price for the acquisitions was approximately $12.3 million funded primarily with borrowings under our Canadian credit agreement and from surplus cash. During this period, we sold our interest in several oil and natural gas properties in the United States for total sales proceeds of approximately $6.1 million.

During the 156 day period from July 29, 2003 to December 31, 2003, we completed several oil and natural gas property acquisitions in the United States and Canada. The total purchase price for the acquisitions was approximately $19.1 million funded with borrowings under our Canadian credit agreement and from surplus cash. The most significant purchase during this period was the acquisition of additional interests in certain natural gas properties that we operate in the United States that we closed in October 2003. As of October 1, 2003, estimated total proved reserves net to our interest from these properties included approximately 19.8 Bcf of natural gas. The total purchase price for the properties was approximately $13.9 million (after contractual adjustments).

Pro forma financial information has not been provided because these acquisitions and dispositions were less than 20% of our total assets when purchased or sold.

13. Bonus Retention Program

In connection with the merger, Holdings has established a bonus retention program to provide an incentive for the employee stockholders of Holdings to remain employed with the company and its subsidiaries. The program provides for equal quarterly payments to the employee stockholders totaling

F-36

$1.8 million on an annual basis. The first payments under the program were made on October 29, 2003. During the 156 day period from July 29, 2003 to December 31, 2003, we have included approximately $767,000 in general and administrative expense related to this program.

The payments to employee stockholders will continue for four years unless the employee stockholder voluntarily terminates employment or is dismissed for cause, at which time the payments will cease. Upon a change of control of Holdings, as defined in the agreement, any amounts not yet paid will be paid to the employee stockholder as a lump sum payment.

14. Concentration of Credit Risk

During 2003, sales of oil to Plains All American, Inc. and affiliates and sales of natural gas to Nexen Marketing U.S.A., Inc. and to Coral Canada U.S. Inc. accounted for 16.6%, 12.9% and 11.4%, respectively, of our total oil and natural gas revenues. If we were to lose any one of our oil and natural gas purchasers, the loss could temporarily cease or delay production and sale of our oil and natural gas in that particular purchaser's service area. If we were to lose a purchaser, we believe we could identify a substitute purchaser. In recent years, several large wholesale purchasers of natural gas experienced significant downgrades in their credit ratings. As a result, many of these companies have either significantly reduced their level of natural gas purchases or have discontinued their purchases of natural gas. Although, we do not believe that we have yet been significantly impacted by these changes, the loss of a large natural gas purchaser could have a detrimental effect on the natural gas market in general and on our ability to find purchasers for our natural gas.

During 2002, sales of oil to Plains All American, Inc. and affiliates and sales of natural gas to Engage Energy America, LLC accounted for 21.6% and 14.5%, respectively, of our total oil and natural gas revenues. During 2001, sales of oil to Plains All American, Inc. and affiliates, and sales of natural gas to Western Gas Resources, Inc. accounted for 14.5% and 11.8%, respectively, of our total oil and natural gas revenues.

15. Issuance of Senior Unsecured Notes and the Acquisition of North Coast Energy, Inc.

On January 27, 2004, we along with our newly formed subsidiary, NCE Acquisition, Inc., acquired North Coast Energy, Inc. (North Coast) for cash consideration of $10.75 per share pursuant to the terms of the Agreement and Plan of Merger dated November 26, 2003, as amended and restated on December 4, 2003. The acquisition of North Coast represents a new core operating area for us. The total purchase amount, including debt assumed and related fees and expenses, of North Coast is approximately $225.4 million.

We financed the purchase amount with proceeds from the January 15, 2004 issuance of our $350 million 7¹/4% senior unsecured notes in a private placement pursuant to Rule 144A under the Exchange Act (the Senior Notes). Of the remaining proceeds, $113.8 million was used to repay a portion of EXCO's and North Coast's credit facility indebtedness and accrued interest and fees, $50.1 million was used to repay in full principal and interest on our senior term loan with the remaining proceeds available for general working capital purposes.

Interest is payable on the Senior Notes semi-annually in arrears on January 15 and July 15 of each year, commencing July 15, 2004. The Senior Notes mature on January 15, 2011. Prior to January 15, 2007, we may redeem all, but not less than all, of the Senior Notes in cash at a redemption price equal to 100% of the principal amount of the notes plus a premium. We may redeem some or all of the

F-37

Senior Notes beginning on January 15, 2007 for the redemption price set forth in the notes. If a change of control occurs, subject to certain conditions, we must offer holders of the notes an opportunity to sell us their 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.

The indenture governing the Senior Notes contains covenants which limit our ability and the ability of certain of our subsidiaries to:

•: Incur or guarantee additional debt and issue certain types of preferred stock;
•: Pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated debt;
•: Make investments;
•: Create liens on our assets;
•: Enter into sale/leaseback transactions;
•: 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 of issue shares of stock of subsidiaries;
•: Transfer or sell assets; and
•: Consolidate, merger or transfer all or substantially all of our assets and the assets of our subsidiaries.

We have agreed to file an exchange offer registration statement to exchange the Senior Notes for a new issue of substantially identical notes registered under the Securities Act. We have also agreed to file a shelf registration statement to cover resales of the notes under certain circumstances. If we fail to satisfy these obligations, we have agreed to pay additional interest to holders of the Senior Notes under certain circumstances.

In the event that we were unable to issue at least $200 million of the senior unsecured notes, then we had commitments to finance up to approximately $59 million of the purchase amount with borrowings under an amended senior secured credit facility (the Senior Credit Facility) and up to approximately $125 million of the purchase amount from senior unsecured increasing rate loans under a senior credit facility from Bank One, NA, Credit Suisse First Boston and a group of lenders (the Bridge Facility). Effective November 25, 2003, we have entered into a commitment letter with Credit Suisse First Boston and Bank One for the Senior Credit Facility and the Bridge Facility. The fee for this commitment letter was paid and will be expensed in January 2004.

In conjunction with the closing of the North Coast acquisition, on January 27, 2004, we entered into amended and restated U.S. and Canadian credit agreements. The borrowing base on the U.S. credit agreement was increased from $95.0 million to $120.0 million. The borrowing base on the Canadian credit agreement remained at U.S. $105.0 million (CDN $138.6 million) which was then converted into Canadian dollars at the exchange rate on January 26, 2004. The new maturity date for both credit agreements is January 27, 2007.

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The interest rate elections and applicable margins remain unchanged for both the U.S. and Canadian credit agreements from the previous agreements. A ratio of consolidated funded debt to consolidated EBITDA (as defined under our credit agreements) was added to the financial covenants. It requires a ratio of 4.35 to 1.00 or less for the quarter ended March 31, 2004, and a ratio of 4.00 to 1.00 for each fiscal quarter ending June 30, 2004 and thereafter. The ratio of consolidated funded debt (other than the senior term notes) to consolidated EBITDA (as defined under our credit agreements) was changed from the previous agreements. It now requires a ratio of 3.25 to 1.00 or less for the quarter ended March 31, 2004, and a ratio of 3.00 to 1.00 for each fiscal quarter ending June 30, 2004 and thereafter.

Set forth below are condensed consolidating financial statements of EXCO, the guarantor subsidiaries and the non-guarantor subsidiary. The senior unsecured notes are jointly and severally guaranteed by our current and some of our future subsidiaries in the United States (referred to as Guarantor Subsidiaries). Addison is not a guarantor of the senior unsecured notes. Instead, the notes are secured, subject to specified permitted liens and except as described below, by a second-priority security interest in 65% of the capital stock of Addison. This share pledge is limited such that, at any time, the aggregate par value, book value as carried by us or market value (whichever is greatest) of such pledged capital stock is not equal to or greater than 20% of then outstanding aggregate principal amount of the notes.

The following financial information presents consolidating financial statements, which include:

•: Resources;
•: the guarantor subsidiaries on a combined basis;
•: the non-guarantor subsidiary;
•: elimination entries necessary to consolidate Resources, the guarantor subsidiaries and the non-guarantor subsidiary; and,
•: the Company on a consolidated basis.

Taurus Acquisition, Inc., EXCO Investment I, LLC and EXCO Investment II, LLC are guarantors of the senior unsecured notes. These companies have no material operations and, accordingly, these companies have been omitted from the guarantor financial information. Investments in subsidiaries are accounted for using the equity method of accounting. The financial information for the guarantor and non-guarantor subsidiaries are presented on a combined basis. The elimination entries primarily eliminate investments in subsidiaries and intercompany balances and transactions.

F-39

EXCO RESOURCES, INC.

CONSOLIDATING BALANCE SHEET (Unaudited)

December 31, 2003

	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	3,372		$	—		$	3,961		$	—		$	7,333
Other current assets		10,262			—			13,974			—			24,236

Total current assets		13,634			—			17,935			—			31,569

Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties		2,598			—			6,597			—			9,195
Proved developed and undeveloped oil and natural gas properties		102,955			84,416			229,308			—			416,679
Allowance for depreciation, depletion and amortization		(3,091	)		(2,162	)		(6,678	)		—			(11,931	)

Oil and natural gas properties, net		102,462			82,254			229,227			—			413,943

Office and field equipment, net		811			—			290			—			1,101
Goodwill		24,218			—			29,128			—			53,346
Investments in and advances to affiliates		184,519			12,895			—			(197,368	)		46
Other assets, net		4,498			—			527			—			5,025

Total assets	$	330,142		$	95,149		$	277,107		$	(197,368	)	$	505,030

Liabilities and Stockholders' Equity
Current liabilities	$	25,644		$	—		$	19,544		$	—		$	45,188
Long-term debt		99,470			—			108,481			—			207,951
Deferred income taxes		12,139			—			33,760			—			45,899
Other liabilities		9,021			1,527			11,575			—			22,123
Payable to parent		—			—			48,927			(48,927	)		—
Commitments and contingencies		—			—			—			—			—
Stockholders' equity		183,868			93,622			54,820			(148,441	)		183,869

Total liabilities and stockholders' equity	$	330,142		$	95,149		$	277,107		$	(197,368	)	$	505,030

F-40

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENT OF OPERATIONS (Unaudited)

For the 209 Day Period Ended July 28, 2003

	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Revenues and other income:
Oil and natural gas sales	$	7,502		$	14,901		$	39,013	$	—		$	61,416
Other income (loss)		(1,129	)		—			96		—			(1,033	)
Equity in earnings of subsidiaries		18,068			—			—		(18,068	)		—

Total revenues and other income		24,441			14,901			39,109		(18,068	)		60,383

Costs and expenses:
Oil and natural gas production		7,361			4,019			8,413		—			19,793
Depreciation, depletion and amortization		3,516			1,967			6,539		—			12,022
Accretion of discount on asset retirement obligations		240			80			417		—			737
General and administrative		11,347			—			7,925		—			19,272
Interest		700			—			2,281		—			2,981

Total costs and expenses		23,164			6,066			25,575		—			54,805

Income (loss) before income taxes		1,277			8,835			13,534		(18,068	)		5,578
Income tax expense (benefit)		(181	)		—			4,982		—			4,801

Income (loss) before cumulative effect of change in accounting principle		1,458			8,835			8,552		(18,068	)		777
Cumulative effect of change in accounting principle, net of income tax		(426	)		(135	)		816		—			255

Net income (loss)	$	1,032		$	8,700		$	9,368	$	(18,068	)	$	1,032

F-41

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENT OF OPERATIONS (Unaudited)

For the 156 Day Period Ended December 31, 2003

	Resources			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues and other income:
Oil and natural gas sales	$	13,939		$	7,828	$	24,366		$	—		$	46,133
Commodity price risk management activities		(10,800	)		—		(360	)		—			(11,160	)
Other income (loss)		(181	)		—		420			—			239
Equity in earnings of subsidiaries		12,746			—		—			(12,746	)		—

Total revenues and other income		15,704			7,828		24,426			(12,746	)		35,212

Costs and expenses:
Oil and natural gas production		5,219			2,112		7,193			—			14,524
Depreciation, depletion and amortization		3,351			2,162		6,499			—			12,012
Accretion of discount on asset retirement obligations		158			47		323			—			528
General and administrative		3,803			—		2,044			—			5,847
Interest		1,821			—		2,150			—			3,971

Total costs and expenses		14,352			4,321		18,209			—			36,882

Income (loss) before income taxes		1,352			3,507		6,217			(12,746	)		(1,670	)
Income tax benefits		(2,825	)		—		(3,022	)		—			(5,847	)

Net income (loss)	$	4,177		$	3,507	$	9,239		$	(12,746	)	$	4,177

F-42

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

For the 209 Day Period Ended July 28, 2003

	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
	(In thousands)
Operating Activities:
Net cash provided by operating activities	$	(9,910	)	$	10,882		$	19,446			—	$	20,418
Investing Activities:
Additions to oil and natural gas property and equipment		(3,517	)		(684	)		(25,572	)		—		(29,773	)
Proceeds from dispositions of property and equipment		2,773			3,247			—			—		6,020
Advances/investments with affiliates		19,544			(13,445	)		(6,099	)		—		—
Proceeds from sales of marketable securities		422			—			—			—		422
Other investing activities		(1	)		—			(188	)		—		(189	)

Net cash used in investing activities		19,221			(10,882	)		(31,859	)		—		(23,520	)
Financing Activities:
Proceeds from long-term debt		20,638			—			25,699			—		46,337
Payments on long-term debt		(11,750	)		—			(10,849	)		—		(22,599	)
Proceeds from exercise of stock options		12,737			—			—			—		12,737
Purchase of common stock from employees in connection with the merger		(17,874	)		—			—			—		(17,874	)
Purchase of director and employee stock options in connection with the merger		(3,567	)		—			—			—		(3,567	)
Payment of fees and expenses in connection with the merger		(563	)		—			—			—		(563	)
Preferred stock dividends		(2,620	)		—			—			—		(2,620	)
Deferred financing costs		(1,136	)		—			(905	)		—		(2,041	)
Other financing activities		140			—			32			—		172

Net cash provided by financing activities		(3,995	)		—			13,977			—		9,982
Net increase in cash		5,316			—			1,564			—		6,880
Effect of exchange rates on cash and cash equivalents		—			—			58			—		58
Cash at beginning of period		1,867			—			75			—		1,942

Cash at end of period	$	7,183		$	—		$	1,697		$	—	$	8,880

F-43

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

For the 156 Day Period Ended December 31, 2003

	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
	(In thousands)
Operating Activities:
Net cash provided by operating activities	$	4,633		$	5,716		$	11,371		$	—	$	21,720
Investing Activities:
Additions to oil and natural gas property and equipment		(6,282	)		(15,440	)		(22,494	)		—		(44,216	)
Proceeds from dispositions of property and equipment		508			1,795			—			—		2,303
Advances/investments with affiliates		(5,444	)		7,929			(490	)		—		1,995
Proceeds from sales of marketable securities		1,393			—			—			—		1,393
Other investing activities		452			—			(455	)		—		(3	)

Net cash used in investing activities		(9,373	)		(5,716	)		(23,439	)		—		(38,528	)
Financing Activities:
Proceeds from long-term debt		58,520			—			15,180			—		73,700
Payments on long-term debt		(56,000	)		—			(1,075	)		—		(57,075	)
Deferred financing costs and other		(1,591	)		—			(70	)		—		(1,661	)

Net cash provided by financing activities		929			—			14,035			—		14,964
Net increase in cash		(3,811	)		—			1,967			—		(1,844	)
Effect of exchange rates on cash and cash equivalents		—			—			297			—		297
Cash at beginning of period		7,183			—			1,697			—		8,880

Cash at end of period	$	3,372		$	—		$	3,961		$	—	$	7,333

F-44

16. Supplemental Information Relating to Oil and Natural Gas Producing Activities (Unaudited)

Presented below are costs incurred in oil and natural gas property acquisition, exploration and development activities:

	United States		Canada		Total
	(In thousands, except per unit amounts)
2001:
Property acquisition costs	$	29,471	$	84,576	$	114,047
Development costs		14,977		8,858		23,835
Depreciation, depletion and amortization per Boe	$	4.82	$	9.07	$	5.65
Depreciation, depletion and amortization per Mcfe	$	0.80	$	1.50	$	0.94
2002:
Property acquisition costs	$	23,049	$	32,783	$	55,832
Development costs		10,554		15,468		26,022
Depreciation, depletion and amortization per Boe	$	4.56	$	5.20	$	4.85
Depreciation, depletion and amortization per Mcfe	$	0.76	$	0.87	$	0.81
For the 209 day period from January 1, 2003 to July 29, 2003:
Property acquisition costs	$	1,474	$	10,837	$	12,311
Development costs		2,622		14,705		17,327
Capitalized asset retirement costs		36		203		239
Depreciation, depletion and amortization per Boe	$	4.44	$	5.25	$	4.85
Depreciation, depletion and amortization per Mcfe	$	0.74	$	0.88	$	0.88
For the 156 day period from July 29, 2003 to December 31, 2003:
Property acquisition costs	$	14,183	$	4,954	$	19,137
Development costs		6,326		17,486		23,812
Capitalized asset retirement costs		48		980		1,028
Depreciation, depletion and amortization per Boe	$	6.57	$	7.00	$	6.80
Depreciation, depletion and amortization per Mcfe	$	1.09	$	1.17	$	1.13

We retain independent engineering firms to provide annual year-end estimates of our future net recoverable oil, natural gas and NGL reserves. The estimated proved net recoverable reserves we show below include only those quantities that we expect to be commercially recoverable at prices and costs in effect at the balance sheet dates under existing regulatory practices and with conventional equipment and operating methods. Proved developed reserves represent only those reserves that we may recover through existing wells. Proved undeveloped reserves include those reserves that we may recover from new wells on undrilled acreage or from existing wells on which we must make a relatively major expenditure for recompletion or secondary recovery operations.

Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of our oil and natural gas properties. Estimates of fair value should also consider probable reserves, anticipated future oil and natural gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is subjective and imprecise.

F-45

Estimated Quantities of Proved Reserves

		United States						Canada						Total
		Oil (Bbls)		Natural Gas (Mcf)		NGLs (Bbls)		Oil (Bbls)		Natural Gas (Mcf)		NGLs (Bbls)		Oil (Bbls)		Natural Gas (Mcf)		NGLs (Bbls)		Mcfe(1)
		(In thousands)
December 31, 2000		12,378		94,444		465		—		—		—		12,378		94,444		465		171,502
	Purchase of reserves in place	809		23,463		329		3,137		63,901		2,539		3,946		87,364		2,868		128,248
	New discoveries and extensions	79		72		—		318		4,611		198		397		4,683		198		8,253
	Revisions of previous estimates	(1,200	)	(956	)	98		425		6,978		160		(775	)	6,022		258		2,920
	Production	(887	)	(6,243	)	(96	)	(80	)	(2,086	)	(68	)	(967	)	(8,329	)	(164	)	(15,115	)
	Sales of reserves in place	(126	)	(524	)	(9	)	—		—		—		(126	)	(524	)	(9	)	(1,334	)

December 31, 2001		11,053		110,256		787		3,800		73,404		2,829		14,853		183,660		3,616		294,474
	Purchase of reserves in place	1,781		18,844		—		1,201		25,839		1,002		2,982		44,683		1,002		68,587
	New discoveries and extensions	339		7,774		105		323		17,867		643		662		25,641		748		34,101
	Revisions of previous estimates	502		12,777		299		829		(2,850	)	(238	)	1,331		9,927		61		18,279
	Production	(869	)	(6,878	)	(74	)	(399	)	(6,565	)	(242	)	(1,268	)	(13,443	)	(316	)	(22,947	)
	Sales of reserves in place	(525	)	(1,175	)	(20	)	—		—		—		(525	)	(1,175	)	(20	)	(4,445	)

December 31, 2002		12,281		141,598		1,097		5,754		107,695		3,994		18,035		249,293		5,091		388,049
	Purchase of reserves in place	153		22,133		45		115		9,563		354		268		31,696		399		35,698
	New discoveries and extensions	528		5,810		—		724		21,459		973		1,252		27,269		973		40,619
	Revisions of previous estimates	(93	)	(2,164	)	(205	)	641		(3,965	)	1,985		548		(6,129	)	1,780		7,839
	Production	(755	)	(7,551	)	(59	)	(448	)	(8,360	)	(332	)	(1,203	)	(15,911	)	(391	)	(25,475	)
	Sales of reserves in place	(1,624	)	(3,764	)	(51	)	—		—		—		(1,624	)	(3,764	)	(51	)	(13,814	)

December 31, 2003		10,490		156,062		827		6,786		126,392		6,974		17,276		282,454		7,801		432,916

Estimated Quantities of Proved Developed Reserves

	United States			Canada			Total
	Oil (Bbls)	Natural Gas (Mcf)	NGLs (Bbls)	Oil (Bbls)	Natural Gas (Mcf)	NGLs (Bbls)	Oil (Bbls)	Natural Gas (Mcf)	NGLs (Bbls)	Mcfe(1)
	(In thousands)
December 31, 2001	7,555	87,868	774	3,414	65,230	2,470	10,969	153,098	3,244	238,376
December 31, 2002	9,067	115,222	985	5,425	92,512	3,432	14,492	207,734	4,417	321,188
December 31, 2003	7,750	123,897	724	6,529	117,030	6,377	14,279	240,927	7,101	369,207

(1): Mcfe—Thousand cubic feet equivalent by converting 1 Bbl of oil to 6 Mcf of natural gas.

Standardized Measure of Discounted Future Net Cash Flows

We have summarized the standardized measure of discounted net cash flows related to our proved oil, natural gas, and NGL reserves. We have based the following summary on a valuation of proved reserves using discounted cash flows based on year-end prices, costs and economic conditions and a 10% discount rate. The additions to proved reserves from the purchase of reserves in place, and new discoveries and extensions could vary significantly from year to year; additionally, the impact of changes to reflect current prices and costs of reserves proved in prior years could also be significant.

F-46

Accordingly, you should not view the information presented below as an estimate of the fair value of our oil and natural gas properties, nor should you consider the information indicative of any trends.

	United States		Canada		Total
	(In thousands)
Year ended December 31, 2001:
Future cash inflows	$	453,313	$	280,001	$	733,314
Future production and development costs		225,167		122,212		347,379
Future income taxes		41,855		47,345		89,200

Future net cash flows		186,291		110,444		296,735
Discount of future net cash flows at 10% per annum		103,206		50,000		153,206

Standardized measure of discounted future net cash flows	$	83,085	$	60,444	$	143,529

Year ended December 31, 2002:
Future cash inflows	$	997,524	$	683,969	$	1,681,493
Future production and development costs		375,879		223,372		599,251
Future income taxes		294,387		175,700		470,087

Future net cash flows		327,258		284,897		612,155
Discount of future net cash flows at 10% per annum		174,335		127,480		301,815

Standardized measure of discounted future net cash flows	$	152,923	$	157,417	$	310,340

Year ended December 31, 2003:
Future cash inflows	$	1,214,803	$	953,165	$	2,167,968
Future production and development costs		413,968		364,305		778,273
Future income taxes		254,719		165,069		419,788

Future net cash flows		546,116		423,791		969,907
Discount of future net cash flows at 10% per annum		312,031		204,772		516,803

Standardized measure of discounted future net cash flows	$	234,085	$	219,019	$	453,104

During recent years, prices paid for oil and natural gas have fluctuated significantly. The prices of oil, natural gas and NGLs at December 31, 2001, 2002 and 2003 used in the above table, were $17.76, $29.56 and $32.52 per Bbl of oil, respectively, $2.23, $4.12 and $6.19 per Mcf of natural gas, respectively, and $15.09, $21.96 and $24.41 per Bbl of NGLs, respectively.

F-47

Changes in Standardized Measure

The following are the principal sources of change in the standardized measure of discounted future net cash flows:

	United States			Canada			Total
	(In thousands)
Year ended December 31, 2001:
Sales and transfers of oil and natural gas produced, net of production costs	$	(25,348	)	$	(5,701	)	$	(31,049	)
Net changes in prices and production costs		(344,892	)		(54,809	)		(399,701	)
Extensions and discoveries, net of future development and production costs		607			6,112			6,719
Development costs during the period		8,340			8,858			17,198
Changes in estimated future development costs		4,356			—			4,356
Revisions of previous quantity estimates		(6,499	)		6,836			337
Sales of reserves in place		(1,062	)		—			(1,062	)
Purchases of reserves in place		41,547			114,120			155,667
Accretion of discount before income taxes		10,147			8,380			18,527
Net change in income taxes		113,453			(23,352	)		90,101

Net change	$	(199,351	)	$	60,444		$	(138,907	)

Year ended December 31, 2002:
Sales and transfers of oil and natural gas produced, net of production costs	$	(22,971	)	$	(21,954	)	$	(44,925	)
Net changes in prices and production costs		90,164			31,336			121,500
Extensions and discoveries, net of future development and production costs		23,415			35,888			59,303
Development costs during the period		7,063			16,121			23,184
Changes in estimated future development costs		2,979			24,281			27,260
Revisions of previous quantity estimates		25,806			981			26,787
Sales of reserves in place		(1,705	)		—			(1,705	)
Purchases of reserves in place		29,228			50,908			80,136
Accretion of discount before income taxes		28,384			24,595			52,979
Net change in income taxes		(112,525	)		(65,183	)		(177,708	)

Net change	$	69,838		$	96,973		$	166,811

Year ended December 31, 2003:
Sales and transfers of oil and natural gas produced, net of production costs	$	(39,032	)	$	(47,773	)	$	(86,805	)
Net changes in prices and production costs		77,635			(7,053	)		70,582
Extensions and discoveries, net of future development and production costs		11,126			47,518			58,644
Development costs during the period		8,669			25,478			34,147
Changes in estimated future development costs		(6,025	)		(16,614	)		(22,639	)
Revisions of previous quantity estimates		(8,673	)		18,054			9,381
Sales of reserves in place		(19,806	)		—			(19,806	)
Purchases of reserves in place		25,619			21,509			47,128
Accretion of discount before income taxes		28,384			24,595			52,979
Changes in timing, foreign currency translation and other		(16,982	)		(28,329	)		(45,311	)
Net change in income taxes		20,247			24,217			44,464

Net change	$	81,162		$	61,602		$	142,764

F-48

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Board of Directors and Stockholders
North Coast Energy, Inc.
Cleveland, Ohio

We have audited the accompanying consolidated balance sheets of North Coast Energy, Inc. (a Delaware corporation) and subsidiaries as of December 31, 2003 and 2002 and the related consolidated statements of income, stockholders' equity and cash flows for the years ended December 31, 2003 and 2002 and the nine month period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes 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, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of North Coast Energy, Inc. and subsidiaries as of December 31, 2003 and 2002 and the consolidated results of their operations and their cash flows for the years ended December 31, 2003 and 2002 and the nine month period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America.

HAUSSER + TAYLOR LLC

Cleveland, Ohio
January 30, 2004

F-49

NORTH COAST ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

			December 31, 2003		December 31, 2002
ASSETS
CURRENT ASSETS
	Cash and equivalents		$	20,247,671	$	14,711,205
	Notes and accounts receivable—trade			10,441,719		5,796,537
	Inventories			209,858		353,722
	Prepaid expenses			493,688		404,726

		Total current assets		31,392,936		21,266,190
PROPERTY AND EQUIPMENT, at cost
	Land			222,822		222,822
	Oil and gas properties (successful efforts)			163,201,304		143,952,276
	Gathering systems			18,012,014		17,137,184
	Vehicles			3,022,546		2,288,388
	Furniture and fixtures			1,129,232		991,438
	Buildings and improvements			2,164,649		1,877,667

				187,752,567		166,469,775
	Less accumulated depreciation, depletion and amortization			46,098,399		37,213,430

				141,654,168		129,256,345
OTHER ASSETS, net				414,569		1,328,595

TOTAL ASSETS			$	173,461,673	$	151,851,130

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

F-50

			December 31, 2003			December 31, 2002
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
	Accounts payable		$	3,570,927		$	3,369,632
	Accrued expenses			12,892,941			7,077,717

		Total current liabilities		16,463,868			10,447,349
LONG-TERM DEBT
	Affiliates			—			10,000,000
	Non-affiliates			57,000,000			57,000,000

				57,000,000			67,000,000
ASSET RETIREMENT AND OTHER LIABILITIES				963,246			208,456
DEFERRED INCOME TAXES				17,240,612			9,458,421
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
	Series A, 6% Noncumulative Convertible Preferred stock, par value $.01 per share; 563,270 shares authorized; 0 and 72,336 shares issued and outstanding (aggregate liquidation value of $0 and $723,360)			—			723
	Series B, Cumulative Convertible Preferred stock, par value $.01 per share; 625,000 shares authorized; none issued and outstanding.			—			—
Undesignated Serial Preferred stock, par value $.01 per share; 811,730 shares authorized; none issued and outstanding				—			—
Common stock, par value $.01 per share; 60,000,000 shares authorized; 15,392,101 and 15,208,634 shares issued and outstanding				153,921			152,086
Additional paid-in capital				47,913,456			47,889,111
Retained earnings				36,132,166			18,125,209
Accumulated other comprehensive loss				(2,405,596	)		(1,430,225	)

	Total stockholders' equity			81,793,947			64,736,904

TOTAL LIABILITIES & STOCKHOLDERS' EQUITY			$	173,461,673		$	151,851,130

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

F-51

NORTH COAST ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

		Year Ended December 31, 2003		Year Ended December 31, 2002		Nine-Month Period Ended December 31, 2001
REVENUE
	Oil and gas production	$	58,415,289	$	37,414,188	$	22,851,489
	Drilling revenues		—		2,082,351		1,795,047
	Well operating, gathering and other		6,880,974		6,766,608		7,474,679

			65,296,263		46,263,147		32,121,215
COSTS AND EXPENSES
	Oil and gas production expenses		10,219,886		8,583,185		6,399,658
	Drilling costs		—		1,752,456		1,990,415
	Well operating, gathering and other		5,210,591		3,488,709		3,213,867
	Exploration expense		3,270,867		1,572,638		847,303
	General and administrative expenses		7,301,940		4,168,323		2,725,611
	Depreciation, depletion and amortization		9,215,534		9,022,370		6,330,099

			35,218,818		28,587,681		21,506,953

INCOME FROM OPERATIONS			30,077,445		17,675,466		10,614,262
INTEREST EXPENSE, NET
	Interest income		477,637		371,807		420,226
	Interest expense		2,756,865		3,146,609		3,190,118

			2,279,228		2,774,802		2,769,892

INCOME BEFORE PROVISION FOR INCOME TAXES			27,798,217		14,900,664		7,844,370
	PROVISION FOR INCOME TAXES		9,791,260		5,148,332		2,496,376

NET INCOME		$	18,006,957	$	9,752,332	$	5,347,994

NET INCOME APPLICABLE TO COMMON STOCK (after dividends on cumulative Preferred Stock of $0, $58,165 and $174,647, respectively)		$	18,006,957	$	9,694,167	$	5,173,347

NET INCOME PER SHARE (basic and diluted)
Basic		$	1.18	$	0.64	$	0.34

Diluted		$	1.16	$	0.64	$	0.34

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

F-52

NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

		Series A Preferred Stock					Series B Preferred Stock
												Common Stock									Accumulated Other Comprehensive Income (Loss)
												Common Stock			Additional Paid-In Capital			Retained Earnings (Deficit)						Total Stockholders' Equity
		Shares		Amount			Shares		Amount			Shares	Amount		Additional Paid-In Capital			Retained Earnings (Deficit)						Total Stockholders' Equity
BALANCE, MARCH 31, 2001		73,096		$	731		232,864		$	2,329		15,208,031	$	152,080	$	50,213,422		$	3,583,705		$	—		$	53,952,267
	Net Income	—			—		—			—		—		—		—			5,347,994			—			5,347,994
	Derivative mark-to-market, net of taxes	—			—		—			—		—		—		—			—			579,630			579,630

	Comprehensive income																								5,927,624
	Dividends on Series B Preferred stock ($.75 per share plus dividends in arrears of $1.40 per share)	—			—		—			—		—		—		—			(500,657	)		—			(500,657	)

BALANCE, DECEMBER 31, 2001		73,096			731		232,864			2,329		15,208,031		152,080		50,213,422			8,431,042			579,630			59,379,234
	Net Income	—			—		—			—		—		—		—			9,752,332			—			9,752,332
	Derivative mark-to-market, net of taxes	—			—		—			—		—		—		—			—			(2,009,855	)		(2,009,855	)

	Comprehensive income																								7,742,477
	Shares converted and other transactions	(760	)		(8	)	(200	)		(2	)	603		6		4			—			—			—
	Dividends on Series B Preferred stock ($.25 per share)	—			—		—			—		—		—		—			(58,165	)		—			(58,165	)
	Redemption of Series B Preferred stock	—			—		(232,664	)		(2,327	)	—		—		(2,324,315	)		—			—			(2,326,642	)

BALANCE, DECEMBER 31, 2002		72,336			723		—			—		15,208,634		152,086		47,889,111			18,125,209			(1,430,225	)		64,736,904
	Net Income	—			—		—			—		—		—		—			18,006,957			—			18,006,957
	Derivative mark-to-market, net of taxes	—			—		—			—		—		—		—			—			(975,371	)		(975,371	)

	Comprehensive income																								17,031,586
	Shares converted and other transactions	(275	)		(3	)	—			—		127		1		2			—			—			—
	Exercise of stock options and warrants	—			—		—			—		183,340		1,834		478,338			—			—			480,172
	Tax benefit from exercise of stock options	—			—		—			—		—		—		265,895			—			—			265,895
	Redemption of Series A Preferred stock	(72,061	)		(720	)	—			—		—		—		(719,890	)		—			—			(720,610	)

BALANCE, DECEMBER 31, 2003		—		$	—		—		$	—		15,392,101	$	153,921	$	47,913,456		$	36,132,166		$	(2,405,596	)	$	81,793,947

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

F-53

NORTH COAST ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

							Year Ended December 31, 2003			Year Ended December 31, 2002			Nine-Month Period Ended December 31, 2001
CASH FLOWS FROM OPERATING ACTIVITIES
	Net income						$	18,006,957		$	9,752,332		$	5,347,994
		Adjustments to reconcile net income to net cash provided by operating activities:
			Depreciation, depletion and amortization					9,215,534			9,022,370			6,330,099
			Gain on sale of property and equipment					(4,297	)		(398	)		(28,541	)
			Deferred income taxes					8,561,260			5,090,000			2,496,376
			Change in:
				Notes and accounts receivable—trade				(4,645,182	)		(597,365	)		2,647,297
				Inventories and other current assets				54,902			6,444			(158,034	)
				Other assets, net				725,874			292,575			16,138
				Accounts payable and accrued expenses				4,527,972			(2,414,741	)		712,644
				Other liabilities				(85,285	)		—			—
				Billings in excess of costs on uncompleted contracts				—			(2,062,094	)		1,184,813

					Total adjustments			18,350,778			9,336,791			13,200,792

						Net cash provided by operating activities		36,357,735			19,089,123			18,548,786
CASH FLOWS FROM INVESTING ACTIVITIES
	Purchases of property and equipment							(20,968,525	)		(24,083,729	)		(13,801,713	)
	Proceeds on sale of property and equipment							387,694			54,694			224,720

						Net cash used by investing activities		(20,580,831	)		(24,029,035	)		(13,576,993	)
CASH FLOWS FROM FINANCING ACTIVITIES
	Exercise of stock options and warrants							480,172			—			—
	Repayment of long-term debt							(10,000,000	)		—			(724,026	)
	Redemption of Preferred A shares							(720,610	)
	Redemption of Preferred B shares							—			(2,326,642	)		—
	Dividends							—			(58,165	)		(500,657	)

						Net cash used by financing activities		(10,240,438	)		(2,384,807	)		(1,224,683	)

INCREASE (DECREASE) IN CASH AND EQUIVALENTS								5,536,466			(7,324,719	)		3,747,110
CASH AND EQUIVALENTS AT BEGINNING OF PERIOD								14,711,205			22,035,924			18,288,814

CASH AND EQUIVALENTS AT END OF PERIOD							$	20,247,671		$	14,711,205		$	22,035,924

Supplemental disclosures of cash flow information:
	Cash paid during the period for:
		Interest					$	2,871,131		$	3,218,081		$	3,556,283
		Income taxes						—			—			222,969

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

F-54

NORTH COAST ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Organization and Summary of Significant Accounting Policies

A.: Organization—North Coast Energy, Inc. ("NCE"), a Delaware corporation, was formed in August 1988 to engage in the exploration, development and production of oil and gas and the acquisition of producing oil and gas properties.
B.: Change in Year-End—The Company changed its year-end from March 31 to December 31 effective December 31, 2001. The nine-month period ended December 31, 2001 is not indicative of a full year of operations (See Note 13).
C.: Principles of Consolidation—The consolidated financial statements include the accounts of North Coast Energy, Inc. and its wholly owned subsidiaries (collectively, "the Company"), North Coast Energy Eastern, Inc. ("NCEE," formerly Peake Energy, Inc.), North Coast Operating Company ("NCOC") and NCE Securities, Inc. ("NCE Securities"). In 2003, both NCOC and NCE Securities were dissolved. In addition, the Company's investments in oil and gas drilling partnerships, which are accounted for under the proportional consolidation method, are reflected in the accompanying financial statements. All significant inter-company accounts and transactions have been eliminated.
D.: Inventories—Inventories consist of material, pipe and supplies and are valued at the lower of cost or market.
E.: Cash Equivalents—Investments having an original maturity of 90 days or less that are readily convertible into cash have been included in the cash and equivalents balances. Included in cash and cash equivalents are $12,483,343 and $9,224,145 of investments in a short-term bond fund for the years ended December 31, 2003 and 2002, respectively.
F.: Property and Equipment—Property and equipment are stated at cost and are depreciated or depleted principally on methods and at rates designed to amortize their costs over their estimated useful lives (proved oil and gas properties using the unit-of-production method based upon estimated proved developed oil and gas reserves, gathering systems using the straight-line method over 10 to 25 years, vehicles, furniture and fixtures using various methods over 3 to 15 years and building and improvements using various methods over 14 to 30 years).
G.: Oil and Gas Investments and Properties—The Company uses the successful efforts method of accounting for its oil and gas producing activities. Under successful efforts, costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells that find proved reserves, and to drill and equip developmental wells are capitalized.

Costs to drill exploratory wells that do not find proved reserves, costs of developmental wells on properties the Company has no further interest in, geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed.

Unproved oil and gas properties that are significant are periodically assessed for impairment of value and a loss is recognized at the time of impairment by providing an impairment allowance. Historically, impairment losses on unproved properties have not been material. Other unproved properties are expensed when surrendered or expired.

When a property is determined to contain proved reserves, the capitalized costs of such properties are transferred from unproved properties to proved properties and are amortized on a group (pool) basis by the unit-of-production method based upon estimated proved developed reserves having similar characteristics. To the extent that capitalized costs of each pool of proved properties exceed the estimated future net cash flow from such pool, the excess capitalized costs are written

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down to the present value of such amount. Estimated future net cash flows are determined based primarily upon the estimated future proved developed reserves related to the Company's current proved properties.

The Company has adopted Statement of Financial Accounting Standards ("SFAS") No. 143. It requires that the fair value of the liability for asset retirement obligations be recognized in the period in which it is incurred and capitalized as part of the properties. For the Company, these obligations include plugging and abandonment of oil and gas wells and associated pipelines and equipment (See Note 14).

The Company follows SFAS 144 which requires a review for impairment whenever circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment is recorded as impaired properties are identified.

On sale or abandonment of an entire interest in an unproved property, gain or loss is recognized, taking into consideration the amount of any recorded impairment. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained. The net carrying cost of unproved properties is approximately $3,473,000 and $3,310,000 at December 31, 2003 and 2002, respectively.

H.: Revenue Recognition—The Company recognizes revenue on drilling contracts using the completed contract method of accounting for both financial reporting purposes and income tax purposes. This method is used because the typical contract is completed in three months or less. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. Billings in excess of costs on uncompleted contracts are classified as current liabilities.

Oil and gas production revenue is recognized as income as it is extracted from the properties and sold. Well operating, gathering and other revenues include operating fees charged to outside working interest owners in NCE operated wells, gathering fees (including transportation allowances and compression fees), third party gas sales associated with purchased natural gas and other miscellaneous revenues. Such revenue is recognized at the time it is earned and the Company has a contractual right to receive payment. Administrative fees received from NCE organized and managed oil and gas partnerships are treated as a reduction of the Company's general and administrative expenses.

I.: Per Share Amounts—The average number of outstanding shares used in computing basic and diluted net income per share was 15,286,874 and 15,495,530, 15,208,216 and 15,241,948 and 15,208,031 and 15,245,360 for the years ended December 31, 2003 and 2002 and the nine-month period ended December 31, 2001, respectively.

For diluted income per share, the assumed conversion of Series A preferred stock had the effect of increasing average outstanding shares by 8,293, 33,251 and 33,624 shares, for the years ended December 31, 2003 and 2002 and the nine month period ended December 31, 2001, respectively. Assumed exercise of dilutive stock options had the effect of adding 149,881, 108 and 3,705 shares to the average outstanding shares for the years ended December 31, 2003 and 2002 and the nine months ended December 31, 2001, respectively. The assumed exercise of dilutive warrants had the effect of adding 50,486 shares to the average outstanding shares for the year ended December 31, 2003. The effect of warrants were anti-dilutive for the year ended December 31, 2002 and the nine-month period ended December 31, 2001.

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J.: Risk Factors—The Company operates in an environment with many financial risks including, but not limited to, the ability to acquire additional economically recoverable oil and gas reserves, the inherent risks of the search for, development of and production of oil and gas, the ability to sell oil and gas at prices which will provide attractive rates of return, the volatility and seasonality of oil and gas production and prices and the highly competitive nature of the industry as well as worldwide economic conditions.
K.: Accounting Estimates—The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates used in calculating the Company's depletion, depreciation and amortization which could be subject to significant near term revision include estimated oil and gas reserves. The Company's reserve estimates could vary significantly depending on various factors, including Company and industry volatility of oil and natural gas prices.
L.: Financial Instruments—The Company's financial instruments include cash and equivalents, notes and accounts receivable, accounts payable, debt obligations and derivatives. The book value of cash and equivalents, notes and accounts receivable and accounts payable are considered to be representative of fair value because of the short maturity of these instruments. The Company believes that the carrying value of its borrowings under its bank credit facility and other debt obligations approximates their fair value as they bear interest at adjustable interest rates which change periodically to reflect market conditions. The Company's accounts receivable are concentrated in the oil and gas industry. The Company does not view such a concentration as an unusual credit risk and credit losses have historically been within management's estimate. Derivatives are used as cash flow hedges and are marked to market through other comprehensive income.
M.: Stock Based Compensation—At the Annual Meeting of Stockholders' held June 12, 2003, the security holders adopted a proposal to amend the Company's 1999 Employee Stock Option Plan to add 400,000 shares of common stock for issuance under such plan.

The Company accounts for stock based compensation issued to its employees and directors in accordance with Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees." Accordingly, no compensation cost has been recognized for the stock option plans, as all options granted under the plans have an exercise price equal to the average of the closing price for each of the twenty trading days prior to the date of the grant. The fair value of options granted during 2003 and 2002 was approximately $810,800 and $205,900, respectively. Options granted prior to 2002 were not material enough to significantly impact the Company's previous years' income per share. The fair value of options granted was determined using the Black-Scholes option pricing model, assuming no dividend yield, and weighted average risk-free interest rates of 2.5% and 4.6% for 2003 and 2002, respectively; volatility of 67% and 52% for 2003 and 2002, respectively; and expected life of 5 years.

The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of Financial Accounting Standards Board ("FASB")

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Statement No. 123, "Accounting for Stock-Based Compensation," to stock-based employee compensation:

		Years Ended December 31
		2003			2002
Net Income as reported		$	18,006,957		$	9,694,167
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects			(504,200	)		(103,300	)

Pro forma net income		$	17,502,757		$	9,590,867

Earnings per share:
	Basic—as reported	$	1.18		$	0.64

	Diluted—as reported	$	1.16		$	0.64

	Basic—pro forma	$	1.14		$	0.63

	Diluted—pro forma	$	1.13		$	0.63

Note 2. Acquisitions

During 2003 and 2002 the Company acquired interests in proved oil and gas properties and related equipment for approximately $1,330,000 and $3,710,000, respectively. These acquisitions related to the purchase of interests in existing oil and gas properties. The pro forma effect of the acquisitions is not material and therefore has not been presented.

Note 3. Details of Current Liabilities

Accrued expenses consist of the following:

	December 31, 2003		December 31, 2002
Production Taxes	$	2,039,671	$	1,689,351
Drilling Costs		2,380,922		826,185
Compensation		1,851,066		1,268,716
Other Expenses		1,632,539		1,023,267
Federal Income Tax		1,230,000		—
Mark-to-Market		3,758,743		2,270,198

	$	12,892,941	$	7,077,717

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Note 4. Long-Term Debt

Long-term debt consists of the following:

	December 31, 2003		December 31, 2002
NUON Non-Negotiable Subordinated Promissory Note due February 28, 2015	$	0	$	10,000,000
Notes payable—bank		57,000,000		57,000,000

	$	57,000,000	$	67,000,000

The Non-Negotiable Subordinated Promissory Note was repaid in August 2003. This note bore interest at the six-month LIBOR plus 2.3%. The weighted average interest rate was 3.8%, 4.5% and 4.9% for the years ended December 31, 2003 and 2002 and the nine-month period ended December 31, 2001, respectively.

The Company has a five-year, $125,000,000 credit agreement with a group of four banks with Union Bank of California acting as agent bank. The credit agreement provides for a borrowing base (presently $80,000,000 of which $57,000,000 is drawn upon) that is determined semiannually by the lenders based on the Company's financial position, oil and gas reserves and certain other factors. The credit agreement expires on September 26, 2005. The agreement provides for a³/8% commitment fee on amounts not borrowed up to the borrowing base and allows for a sub-limit of $15,000,000 for the issuance of letters of credit. At December 31, 2003 and 2002, amounts outstanding under bank credit agreements bear interest at LIBOR plus 1.625% and 1.875%, respectively, or approximately 2.8% and 3.3%, respectively. The weighted average interest rate on bank borrowings was 4.4%, 4.7% and 4.7% for the years ended December 31, 2003 and 2002 and the nine-month period ended December 31, 2001, respectively. Amounts borrowed are secured by the Company's receivables, inventory, equipment and a first mortgage on certain of the Company's interests in oil and gas wells and reserves. The Company's credit agreement restricts the Company from incurring additional debt or liens, prohibits certain dividends and distributions, and requires the Company to maintain positive working capital and minimum interest and fixed charge coverage. The Company was in compliance with all covenants and restrictions at December 31, 2003.

Note 5. Stockholders' Equity

A.: Preferred Stock

The Board of Directors of NCE has designated 563,270 shares of the 2,000,000 shares of preferred stock authorized as Series A, 6% Noncumulative Convertible Preferred stock (Series A Preferred stock) and 625,000 shares of Preferred stock as Series B, Cumulative Convertible Preferred stock (Series B Preferred stock).

Stockholders of Series A Preferred stock were entitled to vote such shares on any and all matters submitted to a vote of the stockholders of the Company based upon the number of votes such stockholders would have if the Series A Preferred stock had been converted into shares of common stock of the Company. Holders of shares of Series A Preferred stock were entitled to receive, when and if declared by the Board of Directors, noncumulative cash dividends at an annual rate of $.60 per share. Shares of Series A Preferred stock were senior to shares of common

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stock with respect to such cash dividends. The Series A Preferred stock was redeemable at the option of NCE at a price of $10 per share. In June 2003, the Company redeemed all of its outstanding Series A Preferred stock for $720,610.

Holders of shares of Series B Preferred stock were entitled to receive, when and if declared by the Board of Directors, cash dividends at an annual rate of $1.00 per share, payable quarterly. The holders of Series B Preferred stock had the right, exercisable at their option, to convert any and all of such shares into 1.15 shares of common stock. The Series B Preferred stock was redeemable at the option of the Company, at $10 per share plus any accrued and unpaid dividends, as defined. In March 2002, the Series B Preferred stock was redeemed at $10 per share plus the accrued and unpaid dividends of $0.25 per share, as defined.

B.: Common Stock Warrants

In each fiscal year 2000, 1999 and 1998, the Company issued warrants to purchase 26,800 shares of common stock for $4.375 per share. These warrants (half of which were issued to a former director and officer) expire between September 2002 and September 2004.

Effective April 1999, in connection with the signing of a separation agreement, the Company's then Chief Executive Officer received a ten-year warrant to purchase 60,000 shares of the Company's common stock at $5.00 per share. In December 2003, the warrants were exercised in a cashless transaction and 35,353 shares of common stock were issued.

C.: Stock Options and Stock Appreciation Rights

On December 13, 1999, the stockholders of the Company approved the adoption of the North Coast Energy, Inc. 1999 Employee Stock Option Plan ("the Option Plan"). The Option Plan, as amended in 2003, provides 800,000 shares of common stock reserved for the exercise of options granted under the plan. The Option Plan provides for the granting of stock options to purchase common stock at an option price determined by North Coast's Stock Option and Compensation Committee ("the Committee"). Options granted under the plan have been at or above the fair market value of the stock at the date of grant. The Committee determines the expiration date but no option shall be exercisable for a period of more than 10 years. The aggregate fair market value of the common stock exercisable for the first time during any calendar year cannot exceed $100,000. Options granted under the Option Plan terminate upon, or within 90 days of the employee leaving the Company. The Company, from time to time, may issue additional options outside the plan.

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Stock option transactions during for the years ended December 31, 2003 and 2002 and the nine-month period ending December 31, 2001 are summarized as follows:

	Options Outstanding	Price Range
March 31, 2001	122,135	$3.47-$6.88
Options granted	60,000	$3.70-$4.38
Options cancelled	23,384	$3.90-$6.88

December 31, 2001	158,751	$3.47-$6.88
Options granted	117,650	$3.36-$3.51
Options cancelled	—

December 31, 2002	276,401	$3.36-$6.88
Options granted	249,380	$5.71
Options cancelled	50,058	$3.99-$6.88
Options exercised	178,626	$3.47-$5.71

December 31, 2003	297,097	$3.36-$5.71

In the year ended December 31, 2003, the Company granted options for 27,600 shares to a Director of the Company at $5.71 per share, which vest one-third on each March 21, 2003, 2004 and 2005, granted options for 109,510 shares at $5.71 per share to two officers which vested upon grant, and granted options for 112,270 shares to key employees at $5.71 per share, which vested upon grant. During the year ended December 31, 2003, 97,548 of these options were exercised.

In January 2002, the Company granted 30,000 options to an independent Director at $3.36 per share. Those options vested 10,000 upon grant and 10,000 each on January 31, 2003 and 2004. In March 2002, the Company granted 34,050 options to an officer at $3.51 per share. All 34,050 options were vested upon grant. During the year ended December 31, 2003, 8,045 of these options were exercised. In addition, the Company granted 53,600 options to two officers and two key employees at $3.51 per share. One-third of those shares were vested upon grant and one-third will vest on each of March 28, 2003 and 2004. During the year ended December 31, 2003, 13,033 of these options were exercised.

In the nine months ended December 31, 2001, the Company granted options for 35,000 shares to an officer of the Company at $3.70 per share, all of which vested upon grant. During the year ended December 31, 2003, 20,000 of these options were exercised. In the nine months ended December 31, 2001, the Company granted 25,000 options to a key employee at $4.38, which vested one-half on each of May 7, 2001 and 2002. During the year ended December 31, 2003, all of these options were exercised.

In the year ended March 31, 2001, the Company granted 30,000 options to a Director of the Company at $3.99 per share with one-third of those options vesting on April 1, 2001 and one-third vesting each year thereafter. During the year ended December 31, 2003, 15,000 options were exercised. The Company also granted 30,000 options to an executive officer at $3.47 per option all

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of which vested upon grant. During the year ended December 31, 2003, the Company repurchased the options at an agreed upon value of $58,300.

Exercisable at December 31, 2003 through	Options Outstanding	Option Price
April 1, 2005	6,667	$4.38
April 1, 2006	6,666	$4.38
September 4, 2006	360	$3.91
January 31, 2007	10,000	$3.36
March 28, 2007	11,350	$3.51
January 31, 2008	10,000	$3.36
March 21, 2008	36,040	$5.71
March 28, 2008	11,350	$3.51
June 12, 2008	63,202	$5.71
October 1, 2009	5,000	$4.38
October 5, 2010	15,000	$3.47
October 5, 2011	15,000	$3.69
March 28, 2012	26,005	$3.51
March 21, 2013	34,190	$5.71

	250,830	$3.36-5.71
Non-vested Options	46,267	$3.36-5.71

Total Options	297,097	$3.36-5.71

Stock appreciation rights may be awarded by the Committee at the time, or subsequent to the time, of the granting of options. Stock appreciation rights awarded shall provide that the option holder shall have the right to receive an amount equal to 100% of the excess, if any, of the fair market value of the shares of common stock covered by the option over the option price payable, as defined. No stock appreciation rights have been awarded under the plan.

D.: Stock Bonus Plan

The Company has a Key Employees Stock Bonus Plan (the "Bonus Plan") to provide key employees, as defined, with greater incentive to serve and promote the interests of the Company and its stockholders. The aggregate number of shares of common stock, which may be issued as bonuses, shall be 400,000. The expenses of administering the Bonus Plan are borne by the Company. The Bonus Plan, as amended, terminates on February 1, 2011. The Company has issued 25,120 shares of common stock under the Bonus Plan since inception.

Note 6. Income Taxes

The Company accounts for income taxes under SFAS No. 109, "Accounting for Income Taxes." SFAS 109 is an asset and liability approach that requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been recognized in the

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Company's consolidated financial statements or tax returns. The provision for income taxes consisted of the following:

		Year Ended December 31, 2003		Year Ended December 31, 2002		Nine-Months Ended December 31, 2001
Current provision		$	1,230,000	$	58,332	$	96,376
Deferred provision			8,561,260		5,090,000		2,400,000

	Total	$	9,791,260	$	5,148,332	$	2,496,376

Income taxes differed from the amount computed by applying the federal statutory rates to pretax book income as follows:

			Year Ended December 31, 2003					Year Ended December 31, 2002					Nine-Months Ended December 31, 2001
			Amount			%		Amount			%		Amount			%
Provision based on
	The statutory rate		$	9,729,000		35.0		$	5,066,000		34.0		$	2,667,000		34.0
Tax effect of:
	Statutory
	Depletion			(90,000	)	(0.3	)		(210,000	)	(1.4	)		(335,000	)	(4.2	)
	State income tax and Other			152,260		0.5			292,332		2.0			164,376		2.0

		Total	$	9,791,260		35.2		$	5,148,332		34.6		$	2,496,376		31.8

The components of the net deferred tax liability as of December 31, 2003 and 2002 were as follows:

			December 31, 2003			December 31, 2002
DEFERRED TAX LIABILITIES
	Property and equipment		$	(24,360,212	)	$	(17,478,000	)

		Total deferred tax liabilities		(24,360,212	)		(17,478,000	)
DEFERRED TAX ASSET
	Alternative minimum tax credit carryforward			1,599,000			399,000
	Net operating loss carryforward			1,300,000			5,200,000
	Statutory depletion carryforward			1,200,000			1,200,000
	Mark-to-market liability			1,353,000			820,000
	Other temporary differences			1,667,600			400,579

		Total deferred tax asset		7,119,600			8,019,579

		Net deferred tax liability	$	(17,240,612	)	$	(9,458,421	)

As of December 31, 2003, the Company had operating loss, statutory depletion and alternative minimum tax credit carryforwards of approximately $3,600,000, $3,400,000 and $1,599,000, respectively. The operating loss carryforwards expire in 2022. The percentage depletion and alternative minimum tax carryforwards can be carried forward indefinitely. Realization of these

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items is subject to certain limitations and is contingent upon future earnings. Additionally, a portion of the carryforwards may be subject to limitations imposed by Internal Revenue Code Section 382, which could further restrict the Company's utilization and realization of such carryforwards.

Note 7. Retirement Savings Trust and Plan

The Company has a Retirement Savings Trust and Plan ("the Plan") that covers all employees that meet the eligibility requirements of the Plan. During 2002, the Plan provided that the Company could make (i) profit sharing contributions and (ii) contributions to match fifty percent (50%) of employee pre-tax contributions with matching contributions on the first five percent (5%) of an employee's compensation contributed to the plan. The Plan was restated as of April 1, 2002 to comply with certain changes in law and to adopt a plan year ending December 31 of each year. The Plan was also restated as of January 1, 2003 to make certain changes in the Plan and to comply with certain changes in law. The Plan now provides for immediate vesting of all profit sharing contributions and all matching contributions. Also, effective January 1, 2003, the Plan provides that instead of making profit sharing contributions, the Company may make a non-elective contribution equal to three percent (3%) of each eligible employee's compensation. The Company must determine annually whether or not to make this contribution, which is designated under the Plan as an "ADP Test Safe Harbor Contribution," which satisfies the requirements of Internal Revenue Code Section 401(k)(12) and regulations issued thereunder. During 2003, the Company made $183,670 in non-elective contributions which represented three percent (3%) of each eligible employee's compensation.

For the plan year ended March 31, 2002, the profit sharing contribution was $75,000. Effective April 1, 2002, the Plan was amended to adopt a plan year ending December 31 of each year. Matching contributions were $109,594 and $90,906 for the twelve months ended December 31, 2003 and 2002, respectively.

Note 8. Commitments and Contingencies

The Company has unlimited liability to third parties with respect to the operations of the remaining partnerships and may be liable to limited partners for losses attributable to breach of fiduciary obligations. In certain partnerships, certain investors have participated as co-general partners in such partnerships. To make such investments more acceptable to potential investors (from the standpoint of risks to such investors), NCE has agreed to indemnify these investor-general partners from any partnership liability, which they may incur in excess of their contributions.

Note 9. Industry Segments and Major Customers

NCE and its subsidiaries operate in a single industry segment, the acquisition, exploration and development of oil and gas properties primarily in the Appalachian Basin. NCE and its subsidiaries both originate and acquire prospects and drill, or cause to be drilled, such prospects through joint drilling arrangements with other independent oil and gas companies.

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The Company's revenue is derived from oil and gas related activities in the Appalachian Basin. Gas production revenues represented 95%, 94% and 93% of total oil and gas production revenues for the years ended December 31, 2003 and 2002 and the nine-month period ended December 31, 2001, respectively. During the year ended December 31, 2003, two customers purchased 18% and 11% of the gas produced by the Company. During the year ended December 31, 2002, one customer purchased 20% of the gas produced. During the nine-month period ended December 31, 2001, two customers purchased 21% and 13% of the gas produced by the Company. A significant portion of trade accounts receivable are attributable to these purchasers.

Note 10. Financial Instruments

Derivative Financial Instruments: The Company only uses derivatives for hedging purposes. The following is a summary of the Company's risk management strategies and the effect of these strategies on the Company's consolidated financial statements.

Cash Flow Hedging Strategy: The Company is exposed to commodity price risks related to natural gas and oil. As a result, the Company's financial results can be significantly impacted by changes in commodity prices. "Costless collars" are financial derivatives that consist of a sold call option and a purchased put option such that the combined revenue and cost of these individual transactions is equal to or near zero. Gains or losses on the hedges relative to the market are recognized monthly as additions to or subtractions from oil and gas sales. To lessen its exposure to commodity price risk, NCE expects to continue to sell natural gas under fixed price contracts, on the spot market and to use financial hedging instruments to realize a fixed-price on a portion of its production. As a result of the costless collars, oil and gas sales were decreased by approximately $5,632,000 for the year ended December 31, 2003 and increased by approximately $539,000 and $840,000 for the year ended December 31, 2002 and the nine months ended December 31, 2001, respectively. The following table reflects the natural gas volumes and the weighted average prices under costless collars and fixed-price contracts at December 31, 2003:

	Financial Hedges (Collars) Estimated Realizable Price
				Fixed Price Contracts
Quarter Ending				Fixed Price Contracts			NYMEX at 12/31/2003 Per MMBtu
Quarter Ending	MMBtu	Floor	Cap	MMBtu	Est. Price		NYMEX at 12/31/2003 Per MMBtu
March 31, 2004	1,815,000	3.84	6.01	1,221,830	$	5.42	$	6.11
June 30, 2004	1,820,000	3.84	6.01	718,500		5.32		5.17
September 30, 2004	1,840,000	3.84	6.01	508,728		5.41		5.14
December 31, 2004	1,840,000	3.84	6.01	379,317		5.35		5.32
March 31, 2005				121,120		5.35		5.50
June 30, 2005				78,251		5.18		4.69
September 30, 2005				62,002		5.07		4.68
December 31, 2005				47,816		5.02		4.90

Interest Rate Swap: During 2001, the Company entered into interest rate swap agreements that effectively convert a portion of its variable-rate-long-term-debt to fixed rate debt, thus reducing the impact of interest rate changes on future income. As a result of the swap agreements interest

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expense was increased by approximately $830,000 and $500,000 in 2003 and 2002, respectively. The amount was immaterial in 2001. At December 31, 2003, the following contracts were outstanding:

		Term		Notional Amount			LIBOR Rate Fixed		NCE Effective Fixed Rate
1.		January 1, 2003 to December 31, 2004		$	20,000,000		3.2	%	4.9	%
2.		January 1, 2001 to December 31, 2004		$	20,000,000		3.0	%	5.1	%

The pre-tax mark-to-market liability and related deferred tax asset associated with the two interest rate swap contracts as calculated by counter parties was $704,253 and $974,318 and $253,531 and $360,498 at December 31, 2003 and 2002, respectively.

The Company qualifies for special hedge accounting treatment under SFAS 133, whereby the fair value of the hedge is recorded in the balance sheet as either an asset or liability and changes in fair value are recognized in other comprehensive income until settled, when the resulting gains and losses are recorded in earnings. Hedge ineffectiveness is charged to earnings. To date, ineffectiveness in the Company's hedges is not material. The effect on earnings and other comprehensive income as a result of SFAS 133 will vary from period to period and will be dependent upon prevailing oil and gas prices, the volatility of forward prices for such commodities, the volumes of production the Company hedges and the time periods covered by such hedges.

As a result of the adoption of SFAS 133, the Company recorded a liability associated with its natural gas hedges based on gas prices in effect at April 1, 2001 of $3,200,000, with offsetting charges to deferred taxes of $1,100,000 and other comprehensive income of $2,100,000. The change was accounted for as a cumulative effect of a change in accounting principle. During the nine months ended December 31, 2001, natural gas prices decreased and one hedge instrument expired. Consequently, the liability at December 31, 2001 was eliminated along with the related deferred tax asset and a mark-to-market asset of $920,050 and a deferred tax liability of $340,420 were recorded. Accumulated other comprehensive income at December 31, 2001 was $579,630 and total comprehensive income for the nine months ended December 31, 2001 was $5,927,624. During 2002 natural gas prices increased resulting in a mark-to-market liability and a deferred tax asset of $1,295,880 and $479,476 respectively, at December 31, 2002. As a result, accumulated other comprehensive loss was $1,430,225 (interest rate swap $613,821 and costless collar $816,404) and total comprehensive income was $7,742,477 for the year ended December 31, 2002. During 2003, the changes in natural gas prices resulted in a mark-to-market liability and a deferred tax asset of $3,054,490 and $1,099,616, respectively, at December 31, 2003. As a result, accumulated other comprehensive loss was $2,405,596 ($1,954,874 costless collars and $450,722 interest rate swap) and total comprehensive income was $17,031,586 for the year ended December 31, 2003.

Concentrations of Credit Risk: Financial instruments that potentially subject the Company to significant concentrations of credit risk consist principally of cash and cash equivalents, trade accounts receivable, and derivatives.

The Company maintains cash and cash equivalents with a large financial institution, which has an investment grade rating on its debt. This financial institution operates throughout the country and the Company's policy is to review the institution's credit worthiness periodically.

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Concentrations of credit risk with respect to trade accounts receivable are limited due to the large number of diverse entities comprising the Company's customer base. The Company does not require collateral for trade accounts receivable, and, therefore, the Company could record losses if these customers fail to pay. The Company believes that established reserves, for nonpayment of $1,000,000 and $620,000 at December 31, 2003 and 2002, respectively, based on a review of delinquent receivables and assessment of historical collections, are adequate.

The Company is exposed to credit risk in the event of non-performance by counterparties to derivative instruments. The Company limits this exposure by using counterparties with high credit ratings and monitors those ratings periodically.

The carrying amounts and fair values of the Company's financial instruments are as follows:

	December 31, 2003				December 31, 2002
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents	$	20,247,671	$	20,247,671	$	14,711,205	$	14,711,205
Accounts receivable		10,441,719		10,441,719		5,796,537		5,796,537
Accounts payable		3,570,927		3,570,927		3,369,632		3,369,632
Long-term debt		57,000,000		57,000,000		67,000,000		67,000,000
Natural gas collars liability		3,054,490		3,054,490		1,295,880		1,295,880
Interest rate swap liability		704,253		704,253		974,318		974,318

Note 11. Related Party Transactions

Accounts receivable from affiliates amounted to $120,727 and $72,385 at December 31, 2003 and 2002, respectively, consist primarily of receivables from the partnerships managed by the Company and are for administrative fees charged to the partnerships and to reimburse the Company for amounts paid on behalf of the partnerships. In the years ended December 31, 2003 and 2002 and the nine months ended December 31, 2001, the Company acquired limited partnership interests in oil and gas drilling programs that it had sponsored at a cost of approximately $34,800, $1,517,000 and $1,250,000, respectively.

Note 12. Accounting Standards

In June 2001, FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations," which was effective the first quarter of fiscal year 2003. SFAS 143 addresses financial accounting and reporting for obligations associated with the retirement of long-lived assets and the associated asset retirement cost. The adoption of this standard has not had a material effect on the Company's financial position, results of operations or cash flows.

In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS 146 is effective for the Company for disposal activities initiated after December 31, 2002. The adoption of this standard has not had a material effect on the Company's financial position, results of operations or cash flows.

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In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation—Transition and Disclosure" that amends SFAS No. 123, "Accounting for Stock-Based Compensation," to provide alternative methods of transition to Statement 123's fair value method of accounting for stock-based employee compensation. SFAS 148 also amends the disclosure provisions of SFAS 123 and APB Opinion No. 28, Interim Financial Reporting, to require disclosure of the effects of an entity's accounting policy with respect to stock-based employee compensation on reported net income and earnings per share in annual and interim financial statements. The Statement does not amend SFAS 123 to require companies to account for employee stock options using the fair value method. The Statement is effective for fiscal years beginning after December 15, 2002. The adoption of SFAS 148 has not had a material effect on the Company's results of operations.

In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." This statement amends and clarifies financial reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." This statement is effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. The adoption of SFAS 149 has not had a material effect on the Company's results of operations.

In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity." This statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. SFAS 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The effective date for certain portions of SFAS 150 has been deferred indefinitely. The Company does not expect the application of the provisions of SFAS 150 to have a material impact on its financial position, results of operations or cash flows.

In January 2003, the FASB issued Interpretation No. 46 ("FIN 46"),Consolidation of Variable Interest Entities, an interpretation of Accounting Research Bulletin No. 51. FIN 46 requires certain variable interest entities, or VIEs, to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN 46 is effective for all VIEs created or acquired after January 31, 2003. For VIEs created or acquired prior to February 1, 2003, the provisions of FIN 46 must be applied for the first interim or annual period beginning after June 15, 2003. The Company currently has no contractual relationship or other business relationship with a variable interest entity and therefore the adoption of FIN 46 had no effect on our consolidated financial position, results of operations or cash flows.

Note 13. Transition Reporting

In August 2001, the Company elected to change its year end from March 31 to December 31. As a result, the Company's transition period was the nine months ended December 31, 2001.

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The following table of consolidated financial data provides a year-to-year comparison of the results of operations for the years ended December 31, 2002 and 2001. The 2001 amounts are unaudited and reflect all adjustments, which are, in the opinion of management, necessary to a fair statement of the results for the period. All adjustments made were of a normal recurring nature.

		Year Ended December 31,
		2002		2001
				(Unaudited)
REVENUE
	Oil and gas production	$	37,414,188	$	30,919,439
	Drilling revenues		2,082,351		6,833,847
	Well operating, gathering, and other		6,766,608		11,419,760

			46,263,147		49,173,046
COSTS AND EXPENSES
	Oil and gas production expenses		8,583,185		9,108,606
	Drilling costs		1,752,456		5,434,471
	Well operating, gathering, and other		3,488,709		4,818,960
	Exploration expense		1,572,638		1,156,126
	General and administrative expenses		4,168,323		3,870,021
	Depreciation, depletion and amortization		9,022,370		7,743,227

			28,587,681		32,131,411

INCOME FROM OPERATIONS			17,675,466		17,041,635
INTEREST EXPENSE, NET
	Interest income		371,807		739,609
	Interest expense		3,146,609		4,755,612

			2,774,802		4,016,003

INCOME BEFORE PROVISION FOR INCOME TAXES			14,900,664		13,025,632
PROVISION FOR INCOME TAXES			5,148,332		4,246,376

NET INCOME		$	9,752,332	$	8,779,256

NET INCOME APPLICABLE TO COMMON STOCK (after dividends on cumulative Preferred Stock of $58,165, and $232,861, respectively)		$	9,694,167	$	8,546,395

NET INCOME PER SHARE (basic and diluted)		$	0.64	$	0.56

Note 14. Asset Retirement Obligation

In 2003, the Company adopted SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS 143 requires the fair value of a liability for an asset retirement obligation to be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. For the Company, these obligations include plugging and abandonment of oil and gas wells and associated pipelines and equipment. Consistent with industry practice, historically the Company has

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determined the cost of plugging and abandonment on its oil and gas properties would be offset by salvage values received. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Company recorded a non-current liability and an increase to oil and gas properties of approximately $763,000 in connection with the adoption of this statement.

The estimated liability is based on historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserves estimates, external estimates as to the cost to plug and abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements.

The Company has no significant assets legally restricted for purposes of settling asset retirement obligations. Except for the item previously referenced, the Company has determined that there are no other material retirement obligations associated with tangible long-lived assets.

The schedule below is a reconciliation of the Company's liability for the year ended December 31, 2003:

	Asset Retirement Obligation
Beginning balance	$	208,000
Upon adoption		763,000
Liabilities incurred		8,000
Liabilities settled		(185,000	)
Accretion		69,000
Other		25,000

	$	888,000

The above accretion expense is included in depreciation, depletion and amortization in the Company's consolidated statements of operations and the asset retirement obligation is included in asset retirement and other liabilities in the Company's consolidated balance sheets.

Note 15. Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited)

CAPITALIZED COSTS RELATING TO OIL AND GAS
PRODUCING ACTIVITIES

	December 31, 2003			December 31, 2002			December 31, 2001
Proved oil and gas properties	$	159,393,488		$	140,098,372		$	121,195,745
Accumulated depreciation, depletion and amortization		(38,013,039	)		(30,626,693	)		(24,069,473	)

Net capitalized costs	$	121,380,449		$	109,471,679		$	97,126,272

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COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES

	Year Ended December 31, 2003		Year Ended December 31, 2002		Nine-Months Ended December 31, 2001
Property acquisition costs	$	2,700,000	$	3,454,000	$	1,259,000
Exploration costs		3,998,000		2,725,000		1,351,000
Development costs		17,377,000		20,696,000		7,800,000

Property acquisition costs include purchases of proved and unproved oil and gas properties acquired in business acquisitions. Additions to asset retirement costs are not material.

RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES

	Year Ended December 31, 2003			Year Ended December 31, 2002			Nine-Months Ended December 31, 2001
Oil and gas production	$	58,415,289		$	37,414,188		$	22,851,489
Production costs		(10,219,886	)		(8,583,185	)		(6,399,658	)
Exploration expenses		(3,270,867	)		(1,572,638	)		(847,303	)
Depreciation, depletion and amortization		(7,355,055	)		(6,486,110	)		(4,387,845	)

		37,569,481			20,772,255			11,216,683
Provision for income taxes		13,381,016			7,154,012			3,508,000

Results of operations for oil and gas producing activities (excluding corporate overhead and financing costs)	$	24,188,465		$	13,618,243		$	7,708,683

Provision for income taxes was computed using the statutory tax rates and reflects permanent differences, including statutory depletion and the Partnership's results of operations for oil and gas producing activities that are reflected in the Company's consolidated income tax provision for the periods.

The tables on the following pages set forth pertinent data with respect to the Company's oil and gas properties, all of which are located within the continental United States.

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ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES

		Oil (BBLS)		Gas (MCF)
Balance, March 31, 2001		1,206,600		143,396,000
	Extensions and discoveries	100,900		12,730,000
	Purchase of reserves in place	8,800		1,857,000
	Production	(82,000	)	(6,404,000	)
	Revisions of previous estimates	8,000		(4,801,000	)
	Sales of reserves in place	(300	)	(18,000	)

Balance, December 31, 2001		1,242,000		146,760,000
	Extensions and discoveries	88,000		18,709,000
	Purchase of reserves in place	30,000		7,561,000
	Production	(104,000	)	(9,629,000	)
	Revisions of previous estimates	65,000		10,395,000
	Sales of reserves in place	(2,000	)	(124,000	)

Balance, December 31, 2002		1,319,000		173,672,000
	Extensions and discoveries	91,000		18,773,000
	Purchase of reserves in place	2,000		4,893,000
	Production	(114,000	)	(10,867,000	)
	Revisions of previous estimates	280,000		13,045,000
	Sale of reserves in place	(22,000	)	(982,000	)

Balance, December 31, 2003		1,556,000		198,534,000

PROVED DEVELOPED RESERVES
	March 31, 2001	1,119,000		124,444,000
	December 31, 2001	1,132,000		126,385,000
	December 31, 2002	1,204,000		150,979,000
	December 31, 2003	1,426,000		169,732,000

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STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

	December 31, 2003			December 31, 2002			December 31, 2001
Future cash inflows from sales of oil and gas (including transportation allowances)	$	1,321,530,000		$	907,537,000		$	481,414,000
Future production costs		(273,281,000	)		(220,342,000	)		(159,398,000	)
Future development costs		(27,831,000	)		(23,389,000	)		(19,755,000	)
Future retirement costs		(15,833,000	)		—			—
Future income tax expense		(306,125,000	)		(199,142,000	)		(90,319,000	)

Future net cash flows		698,460,000			464,664,000			211,942,000
Effect of discounting future net cash flows at 10% per annum		(428,634,000	)		(294,738,000	)		(133,520,000	)

Standardized measure of discounted future net cash flows	$	269,826,000		$	169,926,000		$	78,422,000

CHANGES IN THE STANDARDIZED MEASURE OF
DISCOUNTED FUTURE NET CASH FLOWS

	Year Ended December 31, 2003			Year Ended December 31, 2002			Nine-Months Ended December 31, 2001
Balance, beginning of period	$	169,926,000		$	78,422,000		$	128,331,000
Extensions and discoveries		52,750,000			43,911,000			6,207,000
Purchase of reserves in place		2,286,000			8,033,000			1,145,000
Sales of oil and gas, net of production costs		(48,195,000	)		(28,831,000	)		(16,452,000	)
Net changes in prices and production costs		78,315,000			80,239,000			(77,911,000	)
Net changes in development costs		(4,441,000	)		(3,635,000	)		(263,000	)
Revisions of previous quantity estimates		25,836,000			13,977,000			(3,876,000	)
Sales of reserves in place		(1,568,000	)		(75,000	)		(16,000	)
Net change in income taxes		(43,175,000	)		(39,711,000	)		21,400,000
Accretion of discount		24,275,000			11,154,000			18,284,000
Other		13,817,000			6,442,000			1,573,000

Balance, end of period	$	269,826,000		$	169,926,000		$	78,422,000

Under the guidelines of SFAS 69, estimated future cash flows are determined based on period-end prices for crude oil, current allowable prices applicable to expected natural gas production (including transportation allowances), estimated production of proved crude oil and natural gas reserves, estimated future production and development costs of reserves based on current economic conditions, future plugging costs and the estimated future income tax expenses, based on

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year-end statutory tax rates (with consideration of true tax rates already legislated) to be incurred on pretax net cash flows less the tax basis of the properties involved. At December 31, 2003, such cash flows were discounted to present value using a 10% monthly discount rate and in 2002, they were discounted using a 10% year-end discount rate. The change in discount rates added approximately $9 million of discounted future net cash flow and is included in the "Other" category of changes in the standardized measure of discounted future net cash flows for the year ended December 31, 2003.

The estimated quantities of proved oil and gas reserves and standardized measure of discounted future net cash flows include reserves from proved undeveloped acreage. The proved undeveloped acreage includes only the acreage directly offsetting locations to wells that have indicated commercial production in the objective formation and which NCE expects to drill in the near future using prices, operating costs and development costs expected in the area of interest. The reserve quantities were reviewed by an independent petroleum engineering firm.

The methodology and assumptions used in calculating the standardized measure are those required by SFAS 69. It is not intended to be representative of the fair market value of the Company's proved reserves. The valuation of revenues and costs does not necessarily reflect the amounts to be received or expended by the Company. In addition to the valuations used, numerous other factors are considered in evaluating known and prospective oil and gas reserves.

Note 16. Subsequent Event

In April 2003, the Company announced that it had retained an investment banking firm to assist it in examining and evaluating its strategic alternatives. Subsequently, in connection with its evaluation, the Company received several third party proposals for the acquisition of the Company.

On November 26, 2003, North Coast Energy, Inc., NUON Energy & Water Investments, Inc., NCE Acquisition, Inc. and EXCO Resources, Inc. signed an agreement and plan of merger, which was amended and restated as of December 4, 2003, whereby EXCO Resources, Inc. agreed to commence a tender offer for all outstanding shares of common stock of North Coast Energy, Inc. On December 10, 2003, the Company announced that NUON Energy and Water Investments, which held approximately 86% of the outstanding common stock of the Company, entered into a Stock Tender Agreement with NCE Acquisition, Inc. a wholly owned subsidiary of EXCO Resources, Inc, under the terms of which it would tender all of its shares of North Coast Energy common stock to NCE Acquisition, Inc. for $10.75 per common share. The tender offer expired on January 23, 2004, and all tendered shares (96.8%) were accepted by EXCO Resources, Inc. All tendered and untendered shares will be redeemed for $10.75. Subsequently on January 27, 2004, EXCO Resources, Inc. caused the merger of NCE Acquisition, Inc. into North Coast Energy, Inc. and thereby became the sole stockholder of North Coast Energy, Inc.

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$450,000,000

OFFER TO EXCHANGE

EXCO RESOURCES, INC.

7¹/4% SENIOR NOTES DUE 2011

PROSPECTUS

April 22, 2004

Dealer Prospectus Delivery Obligation

Until July 21, 2004, all dealers that effect transactions in
these securities, whether or not participating in this offering, may be
required to deliver a prospectus. This is in addition to the dealers'
obligation to deliver a prospectus when acting as underwriters and with
respect to their unsold allotments or subscriptions.

North Coast Energy (NCEB) Inactive 424B3Prospectus supplement