Exhibit 99.18

ANNUAL INFORMATION FORM

For the year ended December 31, 2004

March 24, 2005

TABLE OF CONTENTS

	Page
ACCLAIM ENERGY TRUST	1
BUSINESS AND PROPERTIES	2
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION	8
ADDITIONAL INFORMATION RESPECTING ACCLAIM ENERGY TRUST	22
ADDITIONAL INFORMATION RESPECTING ACCLAIM ENERGY INC	31
MARKET FOR SECURITIES	35
DISTRIBUTIONS	37
RISK FACTORS	39
INTEREST OF EXPERTS	45
LEGAL PROCEEDINGS	45
TRANSFER AGENT AND REGISTRAR	45
INTEREST OF INSIDERS IN MATERIAL TRANSACTIONS	46
MATERIAL CONTRACTS	46
ADDITIONAL INFORMATION	46
GLOSSARY OF TERMS	47
ABBREVIATIONS	52
CONVERSION	53
REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION	54
REPORT ON RESERVES DATA	55

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements contained in this annual information form, and in certain documents incorporated by reference into this annual information form, constitute forward-looking statements.  The use of any of the words “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “should”, “believe” and similar expressions are intended to identify forward-looking statements.  These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements.  The Trust and Acclaim Energy believe the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in, or incorporated by reference into, this annual information form should not be unduly relied upon.  These statements speak only as of the date of this annual information form or as of the date specified in the documents incorporated by reference into this annual information form, as the case may be.

In particular, this annual information form, and the documents incorporated by reference, contain forward-looking statements pertaining to the following:

•oil and natural gas production levels;

•capital expenditure programs;

•the quantity of the oil and natural gas reserves;

•projections of commodity prices and costs;

•supply and demand for oil and natural gas;

•expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development; and

•treatment under governmental regulatory regimes.

The actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in this annual information form:

•volatility in market prices for oil and natural gas;

•liabilities inherent in oil and natural gas operations;

•uncertainties associated with estimating oil and natural gas reserves;

•competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel;

•incorrect assessments of the value of acquisitions;

•geological, technical, drilling and processing problems; 

•fluctuations in foreign exchange or interest rates and stock market volatility;

•failure to realize the anticipated benefits of acquisitions; and 

•the other factors discussed under “Risk Factors”.

These factors should not be construed as exhaustive.  Neither the Trust nor Acclaim Energy undertakes any obligation to publicly update or revise any forward-looking statements.

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NON-GAAP MEASURES

In this Annual Information Form, the Trust uses the term “cash flow” to refer to the amount of cash available for distribution to Unitholders and as an indicator of financial performance. “Cash flow” is not a measure recognized by Canadian generally accepted accounting principles (“GAAP”) and does not have a standardized meaning prescribed by GAAP. Therefore, “cash flow” of the Trust may not be comparable to similar measures presented by other issuers, and investors are cautioned that “cash flow” should not be construed as an alternative to net earnings, cash flow from operating activities or other measures of financial performance calculated in accordance with GAAP.  Cash flow cannot be assured and future distributions of the Trust may vary.

NOTES TO READER

Ketch Energy Arrangement

On October 1, 2002, the Trust completed the Ketch Energy Arrangement pursuant to which it indirectly acquired all of the issued and outstanding common shares of Ketch Energy.  As the former shareholders of Ketch Energy held a majority of the Units of the Trust after the business combination, the Ketch Energy Arrangement has been accounted for using the reverse take-over form of the purchase method of accounting for business combinations.

Accordingly, unless otherwise noted, all historical financial, operational and oil and natural gas reserve information contained in this annual information form, include the results of Ketch Energy for the full year 2002 and those of the Trust from the date of the Ketch Energy Arrangement on October 1, 2002.  Similarly, unless otherwise noted, comparative figures from and references to prior years are those of Ketch Energy.

Consolidation

Effective May 31, 2003, the issued and outstanding Units were consolidated on a 1 for 2.5 basis.  All Unit information in this Annual Information Form is presented on a post-consolidation basis.

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ACCLAIM ENERGY TRUST

General

The Trust is an open-end unincorporated trust established under the laws of the Province of Alberta pursuant to the Trust Indenture.  The principal office of the Trust is located at 1900, 255 - 5th Avenue S.W., Calgary, Alberta, T2P 3G6.

The Trust owns, directly or indirectly, all of the outstanding Acclaim Common Shares, all of the outstanding ACT Trust Units, the Acclaim Notes, the ACT Note and securities of the other Operating Entities.  Acclaim Energy is the corporation resulting from the amalgamation on April 20, 2001 of Danoil and Nevis, the amalgamation on January 1, 2002 of Acclaim Energy, Carrack Energy Inc. and Vintage Resource Corp., the amalgamation on January 1, 2003 of Acclaim Energy and Ketch Energy and the amalgamation on January 1, 2005 of Acclaim Energy, Acclaim Energy West Inc. and Exodus Energy Ltd.  Acclaim Energy’s head and principal office is located at 1900, 255 - 5th Avenue S.W., Calgary, Alberta, T2P 3G6.

Acclaim Energy ACT and the other Operating Entities are actively involved in the acquisition, production, processing, transporting and marketing of crude oil, natural gas liquids and natural gas in Alberta, British Columbia, Saskatchewan and Manitoba.  The Trust participates in the cash flow from such business through its direct and indirect ownership of the Operating Entity Securities.

Organizational Structure of the Trust

The following diagram sets forth the simplified organizational structure of the Trust:

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Notes:

(1)Unitholders own 100% of the equity of the Trust.

(2)Cash distributions are made to Unitholders monthly based upon the Trust’s cash flow.

(3)Cash flow represents payments made on or in respect of the Operating Entity Securities.

(4)Acclaim Energy also has Acclaim Exchangeable Shares outstanding.  See “Additional Information Respecting Acclaim Energy Inc. – Share Capital of Acclaim Energy”.

(5)The other Operating Entities are all direct or indirect wholly owned subsidiaries of the Trust.

Summary Description of Business

Acclaim Energy Trust

The principal undertaking of the Trust is to indirectly acquire and hold, through Acclaim Energy and the other Operating Entities, interests in petroleum and natural gas properties and assets related thereto.  The Trust’s primary assets are currently the Acclaim Common Shares, the NPI, the Acclaim Notes and securities of the other Operating Entities.

Through the Trust, Unitholders participate in distributions from Acclaim Energy and the other Operating Entities to the extent authorized by the Board of Directors of Acclaim Energy.  Acclaim Energy’s current policy is to endeavor to retain approximately 25 to 30%of its cash flow over time to fund capital expenditures and to distribute the balance to the Trust.  The actual percentage retained is subject to the discretion of the Board of Directors of Acclaim Energy and will vary from month to month depending on, among other things, the current and anticipated commodity price environment.  See “Additional Information Respecting Acclaim Energy Trust”.

Operating Entities

Acclaim Energy and ACT, directly and through the other Operating Entities, are actively involved in the acquisition, exploitation, development, production, processing and marketing of crude oil, natural gas liquids and natural gas in Alberta, British Columbia, Saskatchewan and Manitoba.  See “Business and Properties”, “Statement of Reserves Data and Other Oil and Gas Information” and “Additional Information Respecting Acclaim Energy Inc.”.

BUSINESS AND PROPERTIES

Acclaim Energy, ACT and the other Operating Entities are, directly and indirectly, actively involved in the acquisition, exploitation, production, processing and marketing of crude oil, natural gas liquids and natural gas in Alberta, British Columbia, Saskatchewan and Manitoba.  References in this section to Acclaim Energy include ACT and the other Operating Entities unless the context otherwise requires.

General Development of the Business

Over the past five years, Acclaim Energy evolved from a company that purchased oil and gas assets, optimized and developed those assets and subsequently sold the assets, to a full-cycle exploration and production company and, effective April 20, 2001, to the operating entity of an energy income trust.  Acclaim Energy focuses its efforts primarily on acquisition opportunities, especially those that offer a stable production base with the potential of upside through development drilling and production optimization.  As a consolidated oil and gas trust, Acclaim Energy has since 2001 grown considerably through acquisitions.

Acclaim Energy endeavors to maintain a high working interest in its core areas, and as at December 31, 2004 operated 75 percent of its production.  This enables it to maximize operational flexibility and to better control the nature and timing of its expenditures.  Production rates for the year ended December 31, 2004 were approximately 33,421 BOE/d, comprised of 53% crude oil and natural gas liquids with the balance being natural gas (10,315 Bbls/d of light and medium crude oil, 3,416 Bbls/d of heavy crude oil and 94.2 MMcf/d of natural gas).

During 2004, Acclaim Energy spent approximately $526.1 million (net of incentives, certain proceeds and including capitalized general and administrative expenses) on capital expenditures, including $433.7 million on the ChevronTexaco Acquisition for $433.7 and on development expenditures.  The year prior, Acclaim Energy incurred approximately $454.6 million in capital expenditures, which included three property acquisitions and one corporate transaction and Acclaim Energy’s development program.

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Significant Transactions and Recent Developments

Danoil Merger

On April 20, 2001, Danoil, Nevis and the Trust completed the Danoil Merger pursuant to which, among other things: the Trust changed its name to “Acclaim Energy Trust”; Danoil and Nevis amalgamated to form Acclaim Energy, which became a wholly-owned subsidiary of the Trust; holders of Units on the effective date of the Danoil Merger received a distribution of $23.5 million principal amount of subordinated debentures of Acclaim Energy (subsequently repaid in full); and shareholders of Danoil received Units in exchange for their Danoil common shares.

Ketch Energy Arrangement

On October 1, 2002, the Trust completed the Ketch Energy Arrangement pursuant to which it indirectly acquired all of the issued and outstanding common shares of Ketch Energy in exchange for approximately 22.4 million Units.  Ketch Energy was a natural resource company focusing its efforts on exploring for, developing, acquiring and producing petroleum and natural gas in the Western Canadian Sedimentary Basin.  As part of the Ketch Energy Arrangement, the ExploreCo Assets were sold to Ketch Resources Ltd. and the common shares of Ketch Resources Ltd. were distributed to the former holders of Ketch Energy common shares.  At the time of completion, the Ketch Energy Arrangement added production of approximately 9,700 BOE/d, 36,634 MBOE of Established Reservesand approximately 247,000 net acres of undeveloped lands to the Trust.

The completion of the Ketch Energy Arrangement also resulted in the reconstitution of the management and a number of the directors of Acclaim Energy.

As a condition of the Ketch Energy Arrangement, Acclaim Energy acquired all of the issued and outstanding shares of Acclaim Energy Management Inc., the former manager of Acclaim Energy, in exchange for the issuance of 705,083 Acclaim Preferred Shares (subsequently exchanged for an equivalent number of Acclaim Exchangeable Shares) with the result that the management agreement with Acclaim Energy Management Inc. was terminated.  See “Additional Information Respecting Acclaim Energy Inc. – Share Capital of Acclaim Energy” for a description of the Acclaim Exchangeable Shares.

Elk Point Arrangement

On January 28, 2003, the Trust completed the Elk Point Arrangement pursuant to which it acquired all of the issued and outstanding common shares of Elk Point in exchange for approximately 10.52 million Units and $10.9 million in cash.  The Trust also assumed Elk Point’s net total debt in the approximate amount of $56 million.  Elk Point was a natural resource company focusing its efforts on exploring for, developing, acquiring and producing petroleum and natural gas in the Western Canadian Sedimentary Basin and in the Powder River Basin of the United States.  As part of the Elk Point Arrangement, the Burmis Assets were sold to Burmis Energy Inc. and the common shares of Burmis Energy Inc. were distributed to the former holders of Elk Point common shares.  The Burmis Assets were comprised of oil and gas properties in the Powder River Basin of Wyoming and the San Joaquin Basin of California and certain minor Alberta properties.  Completion of the Elk Point Arrangement added producing oil and gas properties located principally in the west central and Peace River Arch areas of Alberta producing approximately 6,200 BOE/d and 135,000 net acres of undeveloped lands.  At the time of the transaction, the Established Reserves associated with these properties were estimated to be approximately 18,500 MBOE.

Gilby/Willesden Green Acquisition

On June 26, 2003, Acclaim Energy completed the acquisition of the Gilby/Willesden Green Properties from an arm’s length vendor for a cash purchase price of approximately $135 million.  The effective date of the Gilby/Willesden Green Acquisition was April 1, 2003.

The Gilby/Willesden Green Properties include unit and non-unit interests in the Willesden Green and Gilby areas of west central Alberta.  The properties are highly concentrated, 90% operated and adjacent to Acclaim Energy’s existing properties in its western region.  The Gilby/Willesden Green Acquisition also includes working interests in the Willesden Green and Gilby West natural gas plants and 100% ownership and operatorship of several oil batteries in the area.

Production from the Gilby/Willesden Green Properties at the time of acquisition was approximately 3,550 BOE/d, comprised of 9.9 MMcf/d of natural gas and 1,900 Bbls/d of light crude oil and NGL.  The Established Reserves attributable to the Gilby/Willesden

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Green Properties as at April 1, 2003 were estimated to be approximately 8,422 MBbls of crude oil, 31,728 MMcf of natural gas and 785 MBbls of NGL, for a total of 14,495 MBOE, before deduction of royalties.

Natural Gas Properties (NG) Acquisition

On August 14, 2003, Acclaim Energy completed the acquisition of the NG Properties for a cash purchase price of approximately $68.4 million.  The effective date of the NG Acquisition was July 1, 2003.

Production from the NG Properties at the time of acquisition was approximately 3,000 BOE/d, comprised of 13.5 MMcf/d of natural gas and 750 Bbls/d of light crude oil and NGL.  Approximately 80% of the production associated with the NG Properties is located in Acclaim Energy’s core operating areas.  At July 31, 2003, the Established Reserves attributable to the NG Properties were estimated to be approximately 2,507 MBbls of crude oil, 35,665 MMcf of natural gas and 671 MBbls of NGL, for a total of 9,122 MBOE before deduction of royalties.

Exodus Acquisition

On December 19, 2003, Acclaim Energy completed the Exodus Acquisition pursuant to which it acquired all of the issued and outstanding shares in the capital of Exodus, a private oil and natural gas company, for an aggregate purchase price of approximately $37.6 million including assumed net debt of approximately $7.9 million.  The Trust issued approximately 1,341,905 Units and paid $14.4 million in cash to satisfy the purchase price for the Exodus shares.

At the time of acquisition, Exodus’s production was approximately 2,000 BOE/d and 90% operated.  Approximately 85% of the production was heavy oil and approximately 15% was comprised of natural gas and light crude oil.  Exodus’s significant properties included Greater Furness, located between Acclaim’s existing western Saskatchewan heavy oil properties of Tangleflags and Baldwinton and properties at Joarcam, Beaverhill Lake and Killam in eastern Alberta.  Exodus’s Established Reserves at the time of acquisition were estimated to be approximately 5.1 million BOE, comprised of 4.2 million Bbls of heavy oil, 470,000 Bbls of light crude oil and NGL and 2.9 Bcf of natural gas.

ChevronTexaco Acquisition

On June 30, 2004, Acclaim Energy completed the acquisition of the ChevronTexaco Properties from Chevron Canada for total consideration of $433.7 million. The effective date of the transaction was June 1, 2004.

Production from the ChevronTexaco Properties at the time of acquisition was approximately 17,000 BOE/d including 34.0 MMcf/d of natural gas and 11,400 Bbls/d of light crude oil and NGL. The ChevronTexaco Properties are complementary to Acclaim’s properties in central, western and northern Alberta, and also provided it with a position in long-life, high-quality production in western Manitoba.  The major operated properties in the ChevronTexaco Acquisition were Acheson (100% working interest) and Mitsue (28.1% working interest).  Non-operated properties included Kaybob (50% working interest) and Manitoba (40% working interest).  Proved and Probable Reserves attributable to the ChevronTexaco Properties at the time of acquisition, based on a third party independent appraisal, were estimated at approximately 35.4 million BOE, comprised of 18.9 million Bbls of light crude oil, 5.6 million Bbls of NGL and 65.3 Bcf of natural gas.

Public Financings

On February 21, 2002, the Trust completed a public offering of 1.75 million Units at $8.625 per Unit to raise gross proceeds of $15.1 million.

On September 12, 2002, the Trust completed a public offering of 3.82 million subscription receipts at $10.50 per subscription receipt to raise gross proceeds of $40.1 million.  A total of 3.82 million Units were issued on October 1, 2002 pursuant to the subscription receipts upon the closing of the Ketch Energy Arrangement.

On December 17, 2002, the Trust completed a public offering of $45 million principal amount of 11% Debentures.  See “Additional Information Respecting Acclaim Energy Trust – Convertible Debentures of the Trust”.

On May 23, 2003, the Trust completed a public offering of 9,740,500 Units at a price of $9.75 for gross proceeds of $95 million.

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On July 22, 2003, the Trust completed a public offering of 6,590,000 Units at a price of $10.95 per Unit for gross proceeds of $72.2 million.

On October 27, 2003, the Trust completed a public offering of 4,255,000 Units at a price of $11.00 per Unit for gross proceeds of $46.8 million.

On April 19, 2004, the Trust completed a public offering of 5,175,000 Units at $12.00 per Unit for gross proceeds of $62.1 million.

On June 15, 2004, the Trust completed a public offering of 16,350,000 subscription receipts at $12.25 per subscription receipt for gross proceeds of $200.3 million and $75 million principal amount of 8% Debentures.  See “Additional Information Respecting Acclaim Energy Trust – Convertible Debentures of the Trust”.  A total of 16,350,000 Units were issued on June 30, 2004 pursuant to the subscription receipts upon the closing of the ChevronTexaco Acquisition.

On October 4, 2004, the Trust completed a public offering of 5,300,000 Units at $14.25 for gross proceeds of $75.5 million.

Consolidation of Units

The issued and outstanding Units were consolidated on a one for 2.5 basis on May 31, 2003 and began trading on a post-Consolidation basis on the TSX on June 5, 2003.  All Unit and per Unit figures in this Annual Information Form have been adjusted to give effect to the Consolidation.

Oil and Gas Properties

The following is a description of Acclaim Energy’s principal oil and natural gas properties as at December 31, 2004.  Unless otherwise specified, production estimates, gross and net acres and well count information are as at December 31, 2004.  Reserve amounts are stated, before deduction of royalties as at December 31, 2004, based on escalating cost and price assumptions as evaluated in the GLJ Report.  The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties due to the effects of aggregation.

Acclaim Energy’s operations are entirely land-based and are exclusively focused in western Canada, concentrated in four geographic operating districts.  Acclaim Energy operates 75 percent of its production and has accumulated a large opportunity profile for continued growth through its detailed technical analysis and operational expertise.

Central District

Acheson

The Acheson area is west of the city of Edmonton and was purchased pursuant to the ChevronTexaco Acquisition. Acheson includes interests in the Acheson D-3A Unit, the Acheson Lower Cretaceous Unit No. 1, the Acheson North D-2 Pool Unit and non-unit production.  Acclaim Energy’s overall working interest in the area is 99.7% with a 100% working interest in the operated Acheson gas plant, capable of processing of 25 MMcf/d of gas.

Acheson is a multi-zone area with production coming from the Leduc, Nisku, Detrital, and Basal Quartz zones. The Leduc Formation is characterized by the development of numerous isolated reef complexes and a broad carbonate shelf, all of which developed on the Cooking Lake platform and is responsible for the majority of Acheson’s current production. The D-3A Pool started blow down in June 2003, by the controlled production of reservoir and injected hydrocarbons following the termination of an enhanced recovery scheme to increase the recovery of original oil reserves.  Average daily production in 2004 from this area was 1,765 Bbls/d of crude oil and liquids and 8,312 Mcf/d of natural gas for total production of 3,150 BOE/d. As a large component of this property was acquired June 30, 2004, year-end production rates are more reflective of this area with December average daily production at 2,984 Bbls/d of oil and liquids and 16,004 Mcf/d of natural gas for exit rate production of 5,651 BOE/d. Acclaim Energy’s total proved plus probable reserves in the property as of December 31, 2004, amounted to 6,232 MBOE, consisting of 2,362 MBbl of crude oil, 1,364 MBbl of NGL and 15,041 MMcf of natural gas.

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Mitsue (Gilwood Sand Unit No. 1)

The Mitsue oil field is located near Slave Lake in north central Alberta approximately 125 miles north of the city of Edmonton.  Acclaim Energy purchased a 28.1% working interest in the Mitsue Gilwood Sand Unit No. 1, which encompasses the majority of the field, and a 14.4% working interest in the Calpine operated Mitsue Gilwood Sand Unit No. 2. Acclaim assumed operatorship of the Unit following the acquisition of assets from ChevronTexaco on June 30, 2004.  Acclaim operates the Mitsue gas plant, which has a current capacity of 7 MMcf/d of natural gas.  The Trust also has various interests in non-unit production in this area.  Average daily production 2004 from this area was 693 Bbls/d of crude oil and liquids and 582 Mcf/d of natural gas for total production of 790 BOE/d. As this property was acquired June 30, 2004, year-end production rates are more reflective of this area with December average daily production at 1,653 Bbls/d of oil and liquids and 1,315 Mcf/d of natural gas for exit rate production of 1,872 BOE/d. Acclaim Energy’s total proved plus probable reserves in the property as of December 31, 2004, amounted to 7,500 MBOE, consisting of 5,770 MBbl of crude oil, 798 MBbl of NGL and 5,588 MMcf of natural gas.

Golden Spike

The Golden Spike area, located approximately five miles west of Edmonton, Alberta was acquired pursuant to the Ketch Energy Arrangement.  Working interests in the area vary, with the majority of working interests ranging from 95 to 100%.  A vast majority of the wells and related facilities are Acclaim operated.  Gas reserves in the area occur largely in the Lower Cretaceous Mannville, with oil reserves being identified in the Mannville, Wabamun and Leduc Formations.  Average daily production in 2004 was 871 Bbls/d of crude oil and liquids and 7,121 Mcf/d of natural gas for total production of 2,058 BOE/d.  Acclaim Energy’s proved plus probable reserves in this property as of December 31, 2004, amounted to 5,529 MBOE, consisting of 776 MBbl of crude oil, 1,665 of NGL and 18,530 MMcf of natural gas.

Western District

Brazeau & Bigoray

There are 10 Nisku Pools in the Bigoray, Brazeau, and West Pembina areas. Acclaim Energy is operator of all these pools, which were acquired in the Chevron Texaco Acquisition.  Eight of the pools were on miscible flood, and seven of which are now on blow down.  The Bigoray group includes the Bigoray Nisku D Unit No. 1 (“BND”) at 75.0% working interest, the Bigoray Nisku F Pool (“BNF”) at 50.0% working interest and the West Pembina Nisku D Pool (“WPND”) at 50.0% working interest. All three of these Pools were under miscible flood, but are now currently on blow down.  Average daily production in 2004 from this area was 1,391 Bbls/d of crude oil and liquids and 9,315 Mcf/d of natural gas for total production of 2,945 BOE/d. As a large component of the properties in this area were acquired June 30, 2004, year-end production rates are more reflective of production in this area with December average daily production at 2,332 Bbls/d of oil and liquids and 13,595 Mcf/d of natural gas for exit rate production of 4,597 BOE/d. Acclaim Energy’s total proved plus probable reserves in these properties as of December 31, 2004, amounted to 11,628 MBOE, consisting of 4,194 MBbl of crude oil, 1,243 MBbl of NGL and 37,145 MMcf of natural gas.

Kaybob

The Kaybob district covers a very large area of approximately 150 miles northwest of Edmonton.  Acclaim Energy acquired 50% of ChevronTexaco’s interests in this area operated by Paramount Resources.  Average daily production in 2004 was 434 Bbls/d of crude oil and liquids and 2,797 Mcf/d of natural gas for total production of 900 BOE/d.  As this property was acquired June 30, 2004, year-end production rates are more reflective of this area with December average daily production at 654 Bbls/d of oil and liquids and 8,129 Mcf/d of natural gas for exit rate production of 2,009 BOE/d. Acclaim Energy’s total proved plus probable reserves in the property as of December 31, 2004, amounted to 3,989 MBOE, consisting of 852 MBbl of crude oil, 1,191 MBbl of NGL and 11,679 MMcf of natural gas.

Kaybob Gas – Kaybob South BHL Units 1, 2, and 3

The Kaybob natural gas production comes from the Kaybob South BHL Units 1, 2 and 3. The units are located south of the town of Fox Creek. BP Canada operates Units 1 and 2 and Paramount Resources operates Unit 3.  Acclaim Energy purchased a 9.8% working interest in Unit 1, an 11% working interest in Unit 2 and a 25.6% working interest in Unit 3. Production is from the Swan Hills Formation of the Middle Devonian BHL Group. The reservoir was a retrograde gas condensate reservoir, and as a result, all three units

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were initially produced on a gas recycle scheme to maintain the reservoir pressure above the hydrocarbon dew point. All three Units are now on blow down.

Kaybob Oil

Acclaim Energy’s purchase of the ChevronTexaco Properties included oil production from Kaybob South Triassic Unit 2, the Simonette Beaverhill Lake A and B Pools and Karr.

Kaybob South Triassic Unit No. 2

Acclaim Energy owns a 23.3% working interest in the Kaybob South Triassic Unit No. 2, which is operated by PrimeWest Energy Inc. The Kaybob South Triassic Unit 2 produces 42° API oil and associated natural gas from the Triassic Montney Formation.

Simonette BHL A and B Pools

The Simonette Beaverhill Lake A and B Pools are located approximately 150 kilometres southeast of Grande Prairie.  Acclaim Energy owns a 35.5% working interest in the A Pool and a 26.3% working interest in B Pool. These pools produce from the Beaverhill Lake Group

Willesden Green

The Willesden Green area is located approximately 80 miles southwest of Edmonton, in the second largest Cardium oil-producing trend in Alberta.  The properties, which were acquired in the Willesden Green Acquisition, include unit and non-unit interests, with the majority of the production operated and with high working interests. The unit interests consist of four producing oil units, with two large operated units and one wholly owned project area producing light oil (41° API) from the Cardium formation.  Two other units (one operated) produce long life light crude oil and natural gas from the Viking formation.  The properties have opportunities for infill drilling on 160 acres, opportunities to enhance water flood performance, and several stimulation candidates.  The non-unit interests produce light gravity crude oil from the Cardium formation and Mannville groups, and natural gas from the Belly River, Cardium, Ellerslie, Ostracod and Nordegg formations.  This is a multi-target area with shallow to moderate drill depths, a large concentrated land position and with the majority of the lands operated.  There are also deeper Mannville drilling targets defined by seismic data, as well as many prospects in the shallower Belly River, Edmonton, Paskapoo and Scollard formations. Acclaim owns the facilities associated with the production, as well as a 21.7% interest in the Imperial Oil Ltd. Willesden Green natural gas plant. Average daily production for 2004 from the Willesden Green properties was approximately 1,372 Bbls/d of crude oil and liquids and 5,244 MMcf/d of natural gas and for total production of 2,246 BOE/d. Acclaim Energy’s total proved plus probable reserves in this property as of December 31, 2004, amounted to 11,998 MBOE, consisting of 7,842 MBbl of oil, 830 MBbl of NGL and 19,954 MMcf of natural gas.

Gilby & Medicine River

The Gilby area is situated approximately 20 miles south east of the Willesden Green properties, and produces light crude oil and sweet natural gas from a number of zones in this multi-target area.  The property, acquired pursuant to the Gilby/Willesden Green Acquisition and consists of six units (three operated) and non-unit holdings producing from early Cretaceaous and Jurassic sands.  Opportunities exist for infill drilling and production optimization. The property includes a 24.8% working interest in the Gilby West natural gas plant, of which Acclaim was elected operator, and working interests in a number of operated facilities.  Average daily production from the area is approximately 662 Bbls/d of crude oil and liquids and 5,809 MMcf/d of natural gas and for total production of approximately 1,630 BOE/d. Acclaim Energy’s total proved plus probable reserves in this property as of December 31, 2004, amounted to 3,783 MBOE, consisting of 1,260 MBbl of oil, 354 MBbl of NGL and 13,006 MMcf of natural gas.

Eastern District

Furness

The greater Furness area is located in western Saskatchewan in Townships 48 and 49, Ranges 26 through 28 W3M.  Furness was acquired late in 2003 pursuant to the acquisition of Exodus Energy Ltd. and is primarily a heavy oil field.  The primary producing zone of interest is the Sparky Sand, with additional production provided from the Mclaren and General Petroleum Formations.

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Average daily production in 2004, net from this area was 1,380 Bbl/s/d of crude oil.  Acclaim’s proved plus probable reserves in this property as of December 31, 2004 are 5,032 MBOE.

Dodsland/Kiyiu Lake

The Dodsland property is located 120 miles southwest of Saskatoon, Saskatchewan, and is produces high quality light oil from the Viking formation. Acclaim Energy holds various working and royalty interest in five Unit and non-Unit wells within the property.  Average daily production in 2004 was approximately 394 Bbl/d of crude oil and liquids and 154 Mcf/d of natural gas. Acclaim Energy’s total proved plus probable reserves in this property as of December 31, 2004, amounted to 1,860 MBOE, consisting of 1,841 MBbl of oil, 3 MBbl of NGL and 95 MMcf of natural gas.

Northern District

Pouce Coupe

The Pouce Coupe properties, acquired pursuant to the Elk Point Arrangement, are located approximately 50 miles northwest of Grand Prairie, Alberta. Acclaim Energy operates the Pouce Coupe South Boundary ‘B’ Unit No. 2 with a 62.8% working interest. This high netback, light oil unit includes an oil battery and water injection facility, as well as amine, refrigeration and gas compression facilities.   Production within the unit is obtained from the Boundary Lake member of the Charlie Lake formation.  Acclaim Energy also holds a 20.793% working interest in the Pouce Coupe South Boundary B Unit operated by Enerplus Resources Corporation.  Non-unit production consists of wells with interests ranging from a gross overriding royalty to 78.75%.  Producing formations primarily include the Bluesky, Gething, Baldonnel, Halfway and Boundary Lake. Average daily production in 2004 was 1,283 Mcf/d of natural gas and 425 Bbls/d of crude oil and liquids for total production of 639 BOE/d.  Acclaim Energy’s total proved plus probable reserves in this property as of December 31, 2004, amounted to 3,552 MBOE, consisting of 2,313 MBbl of oil, 141 MBbl of NGL and 6,590 MMcf of natural gas.

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

The statement of reserves data and other oil and gas information set forth below (the “Statement”) is dated February 23, 2005. The effective date of the Statement is December 31, 2004 and the preparation date of the Statement is January 21, 2005.

Disclosure of Reserves Data

The reserves data of Acclaim Energy set forth below (the “Reserves Data”) is based upon an evaluation by Gilbert Laustsen Jung Associates Ltd (“GLJ”) with an effective date of December 31, 2004 contained in the GLJ Report dated February 23, 2005.  The Reserves Data summarizes the crude oil, liquids and natural gas reserves of Acclaim Energy and the net present values of future net revenue for these reserves using constant prices and costs and forecast prices and costs.  The Reserves Data conforms to the requirements of National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”).  Additional information not required by NI 51-101 has been presented to provide continuity and additional information that Acclaim Energy believes is important to the readers of this information. Acclaim Energy engaged GLJ to provide an evaluation of proved and proved plus probable reserves and no attempt was made to evaluate possible reserves.

All of Acclaim Energy’s reserves are located in Canada and, specifically, in the provinces of Alberta, British Columbia, Saskatchewan and Manitoba.

It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves.  There is no assurance that the constant or forecast prices and costs or other assumptions will be attained and variances could be material.

8

Reserves Data (Forecast Prices and Costs)

The following tables provide reserves data and future net revenues of Acclaim Energy using forecast prices and costs.

Summary of Oil and Gas Reserves and Net Present Values of Future Net Revenue as of December 31, 2004

Forecast Prices and Costs

	Reserves
	Light and Medium Oil		Heavy Oil		Natural Gas		Natural Gas Liquids		BOE
Reserves Category	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
	(MBbl)	(MBbl)	(MBbl)	(MBbl)	(MMcf)	(MMcf)	(MBbl)	(MBbl)	(MBOE)	(MBOE)
Proved
Developed Producing	32,242	28,432	7,199	6,372	174,198	131,719	7,407	5,158	75,881	61,915
Developed Non-Producing	1,274	1,165	801	694	14,056	10,888	241	176	4,658	3,850
Undeveloped	4,214	3,831	1,150	1,076	8,755	6,218	297	205	7,120	6,149
Total Proved	37,730	33,427	9,150	8,142	197,008	148,825	7,945	5,540	87,660	71,913
Probable	10,027	8,761	2,703	2,433	58,509	44,798	2,459	1,766	24,940	20,426
Total Proved Plus Probable	47,757	42,188	11,853	10,574	255,518	193,623	10,404	7,306	112,601	92,339
	Net Present Values of Future Net Revenue
	Before Income Taxes Discounted at (%/year)					After Income Taxes Discounted at (%/year)
Reserves Category	0	5	10	15	20	0	5	10	15	20
	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
Proved
Developed Producing	1,396,622	1,131,813	967,553	853,813	769,368	1,396,622	1,131,813	967,553	853,813	769,368
Developed Non-Producing	82,987	60,775	48,170	39,941	34,104	82,987	60,775	48,170	39,941	34,104
Undeveloped	94,566	64,901	45,945	32,950	23,601	94,566	64,901	45,945	32,950	23,601
Total Proved	1,574,175	1,257,489	1,061,669	926,703	827,073	1,574,175	1,257,489	1,061,669	926,703	827,073
Probable	433,369	273,506	195,330	149,539	119,578	433,369	273,506	195,330	149,539	119,578
Total Proved Plus Probable	2,007,544	1,530,996	1,256,998	1,076,242	946,651	2,007,544	1,530,996	1,256,998	1,076,242	946,651

Total Future Net Revenue (Undiscounted) as of December 31, 2004

Forecast Prices and Costs

Reserves Category	Revenue	Royalties	Operating Costs	Development Costs	Well Abandonment Costs	Future Net Revenue Before Income Taxes	Income Taxes	Future Net Revenue After Income Taxes
	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
Proved	3,405,622	565,209	1,120,611	91,233	54,394	1,574,175	—	1,574,175
Reserves
Proved Plus	4,399,719	730,474	1,457,700	143,876	60,124	2,007,544	—	2,007,544
Probable
Reserves

Future Net Revenue by Production Group as of December 31, 2004

Forecast Prices and Costs

Reserves Category	Production Group	Future Net Revenue Before Income Taxes (discounted at 10%/year)
		($M)
Proved Reserves	Light and Medium Crude Oil (including solution gas and other by-products)	619,666
	Heavy Oil (including solution gas and other by-products)	78,170
	Natural Gas (including by-products but excluding solution gas from oil wells)	358,787
	Other Company Revenue/Costs	5,045
Proved Plus Probable Reserves	Light and Medium Crude Oil (including solution gas and other by-products)	738,998
	Heavy Oil (including solution gas and other by-products)	92,948
	Natural Gas (including by-products but excluding solution gas from oil wells)	419,679
	Other Company Revenue/Costs	5,373

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Reserves Data (Constant Prices and Costs)

The following tables provide reserves data and future net revenue of Acclaim Energy using constant prices and costs.

Summary of Oil and Gas Reserves and Net Present Values of Future Net Revenue as of December 31, 2004

Constant Prices and Costs

	Reserves
	Light and Medium Oil		Heavy Oil		Natural Gas		Natural Gas Liquids		BOE
Reserves Category	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
	(MBbl)	(MBbl)	(MBbl)	(MBbl)	(MMcf)	(MMcf)	(MBbl)	(MBbl)	(MBOE)	(MBOE)
Proved
Developed Producing	33,472	29,508	6,438	5,740	176,877	133,831	7,529	5,232	76,918	62,785
Developed Non-Producing	1,341	1,225	747	670	14,173	10,988	246	180	4,697	3,907
Undeveloped	4,262	3,871	1,094	1,029	8,813	6,265	302	209	7,127	6,153
Total Proved	39,075	34,604	8,279	7,439	199,864	151,085	8,078	5,621	88,742	72,845
Probable	10,349	9,024	2,558	2,337	59,689	45,741	2,483	1,778	25,339	20,763
Total Proved Plus Probable	49,424	43,628	10,837	9,776	259,552	196,826	10,561	7,400	114,081	93,608

	Net Present Values of Future Net Revenue
	Before Income Taxes Discounted at (%/year)					After Income Taxes Discounted at (%/year)
	0	5	10	15	20	0	5	10	15	20
Reserves Category	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
Proved
Developed Producing	1,556,734	1,222,252	1,020,916	885,043	786,406	1,556,734	1,222,252	1,020,916	885,043	786,406
Developed Non-Producing	92,086	66,846	52,363	42,910	36,249	92,086	66,846	52,363	42,910	36,249
Undeveloped	107,561	71,720	49,538	34,698	24,232	107,561	71,720	49,538	34,698	24,232
Total Proved	1,756,381	1,360,819	1,122,818	962,652	846,887	1,756,381	1,360,819	1,122,818	962,652	846,887
Probable	492,054	308,302	218,363	165,659	131,279	492,054	308,302	218,363	165,659	131,279
Total Proved Plus Probable	2,248,436	1,669,121	1,341,181	1,128,310	978,166	2,248,436	1,669,121	1,341,181	1,128,310	978,166

Total Future Net Revenue (Undiscounted) as of December 31, 2004

Constant Prices and Costs

Reserves Category	Revenue	Royalties	Operating Costs	Development Costs	Well Abandonment Costs	Future Net Revenue Before Income Taxes	Income Taxes	Future Net Revenue After Income Taxes
	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
Proved	3,473,661	589,347	997,701	87,954	42,278	1,756,382	—	1,756,382
Reserves
Proved Plus	4,454,313	760,858	1,262,457	137,793	44,769	2,248,436	—	2,248,436
Probable
Reserves

Future Net Revenue by Production Group as of December 31, 2004

Constant Prices and Costs

Reserves Category	Production Group	Future Net Revenue Before Income Taxes (discounted at 10%/year)
		(M$)
Proved Reserves	Light and Medium Crude Oil (including solution gas and other by-products)	674,458
	Heavy Oil (including solution gas and other by-products)	38,258
	Natural Gas (including by-products but excluding solution gas from oil wells)	405,066
	Other Company Revenue/Costs	5,036
Proved Plus Probable Reserves	Light and Medium Crude Oil (including solution gas and other by-products)	812,083
	Heavy Oil (including solution gas and other by-products)	45,236
	Natural Gas (including by-products but excluding solution gas from oil wells)	478,513
	Other Company Revenue/Costs	5,349

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Pricing Assumptions

The following tables set forth the benchmark reference prices and pricing assumptions used in preparing the reserves data and, in the

case of forecast prices and costs, the inflation rate assumptions.

Summary of Pricing Assumptions as of December 31, 2004

Constant Prices and Costs

	Oil
	WTI Cushing Oklahoma	Edmonton Par Price  40° API	LLB Crude at Hardisty	Cromer Medium 29.3° API	Natural Gas AECO Gas Price	Edmonton Propane	Edmonton Butane	Edmonton Pentanes	Exchange Rate
	($US/Bbl)	($Cdn/Bbl)	($Cdn/Bbl)	($Cdn/Bbl)	($Cdn/mmbtu)	($Cdn/Bbl)	($Cdn/Bbl)	($Cdn/Bbl)	($US/$Cdn)
2004	43.45	46.54	24.33	32.12	6.79	29.79	34.44	48.97	0.8308
(Year End)

Summary of Pricing and Inflation Rate Assumptions as of December 31, 2004

Forecast Prices and Costs

	Oil
Year	WTI Cushing Oklahoma	Edmonton Par Price 40° API	Hardisty Heavy 12° API	Cromer Medium 29.3° API	Natural Gas AECO Gas Price	Edmonton Propane	Edmonton Butane	Edmonton Pentanes	Inflation Rates	Exchange Rate
	($US/Bbl)	($Cdn/Bbl)	($Cdn/Bbl)	($Cdn/Bbl)	($Cdn/mmbtu)	($Cdn/Bbl)	($Cdn/Bbl)	($Cdn/Bbl)	%/Year	($US/$Cdn)
Forecast
2005	42.00	50.25	27.50	43.75	6.60	32.25	37.25	50.75	2.0	0.820
2006	40.00	47.75	28.50	41.50	6.35	30.50	35.25	48.25	2.0	0.820
2007	38.00	45.50	28.75	39.50	6.15	29.00	33.75	46.00	2.0	0.820
2008	36.00	43.25	27.25	37.75	6.00	27.75	32.00	43.75	2.0	0.820
2009	34.00	40.75	25.50	35.50	6.00	26.00	30.25	41.25	2.0	0.820
2010	33.00	39.50	24.75	34.25	6.00	25.25	29.25	40.00	2.0	0.820
2011	33.00	39.50	24.75	34.25	6.00	25.25	29.25	40.00	2.0	0.820
2012	33.00	39.50	24.75	34.25	6.00	25.25	29.25	40.00	2.0	0.820
2013	33.50	40.00	24.75	34.75	6.10	25.50	29.50	40.50	2.0	0.820
2014	34.00	40.75	25.50	35.50	6.20	26.00	30.25	41.25	2.0	0.820
2015	34.50	41.25	25.75	36.00	6.30	26.50	30.50	41.75	2.0	0.820
2016+	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	2.0	0.820

Weighted average historical prices realized by Acclaim Energy for the year ended December 31, 2004, were $6.91/Mcf for naturalgas, $51.46/Bbl for crude oil, $34.18/Bbl for natural gas liquids and $31.31/Bbl for heavy oil.

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Reconciliations of Changes in Reserves and Future Net Revenue

The following table sets forth the reconciliation in Acclaim Energy’s net reserves for the year ended December 31, 2004 using forecast price and cost estimates derived from the GLJ Report, reconciled to Acclaim Energy’s net reserves at December 31, 2003.

Reconciliation of Company Net Reserves by Principal product Type
Forecast Prices and Costs (1)

	Light and Medium Oil						Heavy Oil
Factors	Net Proved		Net Probable		Net Proved Plus Probable		Net Proved		Net Probable		Net Proved Plus Probable
	(MBbl)		(MBbl)		(MBbl)		(MBbl)		(MBbl)		(MBbl)
December 31 2003	24,039		5,249		29,288		6,844		1,846		8,690
Acquisitions	12,603		3,229		15,832		208		21		229
Dispositions	(527	)	(160	)	(687	)	—		—		—
Discoveries	13		2		15		—		—		—
Extensions	829		586		1,415		1,239		530		1,769
Infill Drilling	162		27		189		426		177		603
Improved Recovery	116		26		142		—		—		—
Economic Factors	—		—		—		—		—		—
Technical Revisions	(493	)	(198	)	(691	)	546		(142	)	404
Production	(3,315	)	—		(3,315	)	(1,121	)	—		(1,121	)
December 31,2004	33,427		8,761		42,188		8,142		2,433		10,574

	Gas						NGL						Total
Factors	Net Proved		Net Probable		Net Proved Plus Probable		Net Proved		Net Probable		Net Proved Plus Probable		Net Proved		Net Probable		Net Proved Plus Probable
	(MMcf)		(MMcf)		(MMcf)		(MBbl)		(MBbl)		(MBbl)		(MBOE)		(MBOE)		(MBOE)
December 31 2003	135,555		36,306		171,861		3,596		1,035		4,631		57,072		14,181		71,252
Acquisitions	37,054		8,756		45,809		2,933		756		3,689		21,920		5,466		27,385
Dispositions	(2,706	)	(1,054	)	(3,760	)	(13	)	(1	)	(14	)	(991	)	(337	)	(1,328	)
Discoveries	707		212		919		13		4		17		144		41		185
Extensions	5,781		3,226		9,007		119		82		201		3,151		1,736		4,886
Infill Drilling	540		300		840		9		4		13		687		258		945
Improved Recovery	116		16		132		—		—		—		135		29		164
Economic Factors	—		—		—		—		—		—		—		—		—
Technical Revisions	(2,149	)	(2,964	)	(5,112	)	(100	)	(114	)	(215	)	(406	)	(948	)	(1,354	)
Production	(26,073	)	—		(26,073	)	(1,016	)	—		(1,016	)	(9,798	)	—		(9,798	)
December 31, 2004	148,825		44,798		193,623		5,540		1,766		7,306		71,913		20,426		92,339

12

The following table sets forth the reconciliation of Acclaim Energy’s net present value of future net revenue for the year ended December 31, 2004 using constant price and cost estimates derived from the GLJ Report.

Reconciliation of Changes in Net Present Values of Future Net Revenue
Discounted at 10% Per Year
Proved Reserves
Constant Prices and Costs

Period and Factor	2004
	(M$)
Estimated Future Net Revenue at Beginning of Year	790,636
Sales and Transfers of Oil and Gas Produced, Net of Production Costs and Royalties	(271,398	)
Net Change in Prices, Production Costs and Royalties Related to Future Production	114,615
Changes in Previously Estimated Development Costs Incurred During the Period	—
Changes in Estimated Future Development Costs	(20,740	)
Extensions, Infill Drilling and Improved Recovery	53,206
Discoveries	3,246
Acquisitions of Reserves	394,168
Dispositions of Reserves	(14,357	)
Net Change Resulting from Revisions in Quantity Estimates	(5,621	)
Accretion of Discount	79,064
Net Change in Income Taxes	—
Estimated Future Net Revenue at End of Year	1,122,818

Additional Information Relating to Reserves Data

Undeveloped Reserves

The following tables set forth the proved undeveloped reserves and the probable undeveloped reserves, each by-product type, attributed to Acclaim Energy for the periods indicated, based on company interest reserves.

	Proved Undeveloped (1)				Probable Undeveloped (1)
Year	Light / Medium Crude Oil	Heavy Oil	Natural Gas	NGL	Light / Medium Crude Oil	Heavy Oil	Natural Gas	NGL
	(MBbl)	(MBbl)	(MMcf)	(MBbl)	(MBbl)	(MBbl)	(MMcf)	(MBbl)
2004	4,214	1,150	8,755	297	3,397	948	11,997	641
2003	4,272	1,153	10,976	507	2,836	825	13,530	688
2002	4,114	1,366	16,090	720	2,950	964	24,182	752
2001(2)	3,795	—	34,215	1,216	3,067	—	31,885	984

Notes:

(1)Based on company interest reserves.

(2)Ketch Energy did not have a breakdown on proved non-producing and proved undeveloped; therefore proved undeveloped equals total proved non-producing.

(3)Ketch Energy did not have a breakdown of probable developed non-producing and probable undeveloped reserves, therefore probable undeveloped equals total probable non-producing.

Acclaim Energy invests capital into development work, which moves its proved undeveloped reserves and probable reserves into the proved developed producing category.  In 2004, $92.5 million was spent on capital development, and between $95 and $105 million has been budgeted for development capital in 2005.  A portion of the development capital will be used to convert proved undeveloped reserves and probable reserves into proved developed producing reserves.  Allocating capital to properties and timing of development is based on economics and performance of the respective properties.  Acclaim Energy’s focus for 2005 development is in the areas of Pouce Coupe in the Northern District, Mitsue in the Central District, Willesden Green in the Western District, as well the Southern District, the Dodsland properties and Greater Furness.

13

Acclaim Energy plans to continue pursuing development opportunities such as drilling, completions, and facilities upgrades in order to move proved undeveloped and probable reserves into proved developed producing reserves.  In instances where land rights are expected to expire within one year, Acclaim Energy may engage in farmout arrangements which would eliminate the potential expiry and possibly result in some proved undeveloped and probable reserves becoming proved developed producing reserves.

Future Development Costs

The following table sets forth development costs deducted in the estimation of Acclaim Energy’s future net revenue attributable to the reserve categories noted below.

	Forecast Prices and Costs (M$)				Constant Prices and Costs (M$)
	Proved Reserves		Proved Plus Probable Reserves		Proved Reserves
Year	0%	10%	0%	10%	0%	10%
2005	43,652	41,621	60,290	57,484	43,652	41,621
2006	21,430	18,575	45,635	39,556	21,009	18,210
2007	7,836	6,175	11,443	9,017	7,532	5,935
2008	4,078	2,921	5,445	3,901	3,843	2,753
2009	2,029	1,321	2,607	1,698	1,875	1,221
Thereafter	12,208	3,622	18,456	5,018	10,043	3,200
Total	91,233	74,235	143,876	116,674	87,954	72,940

The future development costs are capital expenditures required in the future for Acclaim Energy to convert proved non producing reserves and probable reserves into proved developed producing reserves.   Acclaim Energy anticipates using a combination of internally generated cash flow, debt and equity financing to fund these future development costs. Based on the commodity price and cost assumptions adopted for both the constant prices and costs case and the forecast prices and costs case, all the expenditures included in the future development costs are economic as they enhance the net present values of the proved developed producing reserves.

Other Oil and Gas Information

Oil And Gas Wells

The following table sets forth the number and status of wells in which Acclaim Energy has a working interest as at December 31, 2004.

	Oil Wells				Natural Gas Wells
	Producing		Non-Producing(1)		Producing		Non-Producing(1)
	Gross(2)	Net	Gross	Net	Gross(2)	Net	Gross	Net
Alberta	1,489	530	42	25	1,537	284	38	22
British Columbia	17	4	—	—	39	14	2	1
Saskatchewan	718	440	25	25	13	2	—	—
Manitoba	486	170	—	—	—	—	—	—
Total	2,710	1,144	67	50	1,589	300	40	23

Notes:

(1)Non-Producing wells means wells which have encountered and are capable of producing crude oil or natural gas but which are not producing due to lack of available transportation facilities, available markets or other reasons.

(2)Gross wells include unit wells

14

Properties with no Attributed Reserves

The following table sets out the Corporation’s total land holdings of proved and unproved properties as at December 31, 2004.

	Developed (Acres)		Unproved Properties (Acres)		Total (Acres)
	Gross	Net	Gross	Net	Gross	Net
Alberta	763,205	384,573	488,168	294,778	1,251,373	679,351
British Columbia	49,444	20,222	56,523	27,161	105,967	47,383
Saskatchewan	56,910	40,652	43,716	34,521	100,626	75,173
Manitoba	42,101	15,862	4,760	1,868	46,861	17,730
Total	911,660	461,309	593,167	358,382	1,504,827	819,637

Acclaim Energy expects that rights to explore, develop and exploit 79,569 net acres of its undeveloped land holdings will expire by December 31, 2005.

Forward Contracts

Acclaim Energy has an active price risk management program that undertakes to reduce risk exposure to budgeted annual cash flow projections resulting from uncertainty or changes in commodity prices. By reducing risk, the price risk management program is designed to provide a degree of stability and certainty to distributions to Unitholders. A primary objective of Acclaim Energy’s price risk management program is to choose the appropriate type of financial product at the time of execution which is expected to give the optimal level of protection against downward price movements while maintaining as much exposure as possible to potential price increases. The objective of Acclaim Energy’s risk management team is to hedge up to 50% of Acclaim Energy’s budgeted forward production for the current and following year in accordance with the guidelines established by the board of directors of Acclaim Energy.

Acclaim markets its production through independent marketers, currently directing all of its crude oil and 90% of its natural gas production to the spot markets.

For details of material commitments to sell natural gas and crude oil that were outstanding at December 31, 2004 see Note 13 to the Trust’s audited consolidated financial statements for the year ended December 31, 2004, which note is incorporate herein by reference.

Additional Information Concerning Abandonment and Reclamation Costs

Future abandonment and reclamation costs have been estimated based on actual costs incurred to date by Acclaim Energy for abandonment. Costs to abandon approximately 1,444 net producing wells totaling $48.7 million ($19.7 million discounted at 10%) are included in the estimate of future net revenue. Facility abandonment costs of $67.2 million ($20.3 million discounted at 10%) are not included in the estimate of future net revenue.

Tax Horizon

As a result of the structure of the Trust and its affiliated entities, any taxable income that would otherwise arise in Acclaim Energy or the other affiliated entities will accrue in the Trust and will be allocated by the Trust to its Unitholders.   This is primarily accomplished through the payment and deduction of interest on debt or royalties on underlying oil and gas properties held by the Trust.  Therefore, no tax is anticipated to be incurred or paid by Acclaim Energy.

15

Costs Incurred

The following table summarizes expenditures (net of incentives and net of certain proceeds and including capitalized general and administrative expenses) related to Acclaim Energy’s activities for the year ended December 31, 2004:

Property acquisition costs	$
Proved properties	434,327
Unproved properties	—
Exploration costs	4,858
Development costs	86,912
Total	$	526,097

Exploration and Development Activities

The following table sets forth the gross and net exploratory and development wells in which Acclaim Energy participated during the year ended December 31, 2004:

	Gross	Net
Oil	91.0	71.80
Natural Gas	53.0	9.40
Service	4.0	0.90
Dry	8.0	2.50
Total	156.0	84.60

Acclaim Energy spent $91.8 million in 2004 to drill 156 (84.6 net) development wells across the western Canadian sedimentary basin, and $3.8 million for crown land purchases.   The 2004 program was weighted to oil development, with spending across Acclaim Energy’s four operating districts. In the Eastern district 89 wells were drilled, the Northern district 19 wells were drilled, in the Central district 19 wells were drilled, and in the Western district 34 wells were drilled.   In terms of capital expenditures, the majority of Acclaim development program was directed primarily to its assets in the Eastern, Western and Central districts.   The 2005 drilling program is expected to be approximately $100 million, targeting the drilling of approximately 80 operated wells, with an expected shift of capital expenditures primarily to the Western district, followed by the Eastern and Central districts. As well, the 2005 program will provide an increased focus on remediation and work over activities in existing wells, as well as other optimization activities including acidizing, fracturing and water flooding in order to economically increase production and reserves.

Production Estimates

The following table sets out the volume of Acclaim Energy’s production estimated for the year ended December 31, 2005, which is reflected in the estimate of future net revenue disclosed in the tables contained under “- Disclosure of Reserves Data”.

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	Light and Medium Oil	Heavy Oil	Natural Gas	Liquids	BOE
	(Bbls/d)	(Bbls/d)	(Mcf/d)	(Bbls/d)	(BOE/d)
2005	14,925	3,800	97,000	4,600	39,500

Production History

The following tables summarize certain information in respect of production, product prices received, royalties paid, operating expenses and resulting netback for the periods indicated below:

(6:1)

	Quarter Ended
	2004
	Dec. 31	Sept. 30	June 30	Mar. 31
Average Daily Production
Light and Medium Crude Oil (Bbls/d)	14,643	13,570	6,458	6,505
Heavy Oil (Bbls/d)	4,095	3,434	3,017	3,111
Gas (Mcf/d)	108,219	108,898	77,773	81,641
NGL (Bbls/d)	6,005	5,796	2,170	1,939
Combined (BOE/d)	42,780	40,949	24,607	25,162
Average Price Received
Light and Medium Crude Oil ($/Bbl)	53.9	55.57	45.56	43.78
Heavy Oil (Bbls/d)	28.85	37.76	29.38	29.26
Gas ($/Mcf)	6.91	6.86	7.23	6.68
NGL (Bbls/d)	33.81	33.60	38.46	32.28
Combined ($/BOE)	43.32	44.58	41.79	39.09
Royalties
Light and Medium Crude Oil (Bbls/d)	9.48	9.34	6.58	6.56
Heavy Oil (Bbls/d)	3.38	5.28	4.39	4.44
Gas (Mcf/d)	1.65	1.48	1.43	1.45
NGL (Bbls/d)	10.76	9.68	10.22	6.18
Combined (BOE/d)	9.24	8.85	7.70	7.43
Operating expenses ($/BOE)
Light and Medium Crude Oil (Bbls/d)	7.30	7.08	9.78	9.37
Heavy Oil (Bbls/d)	11.98	14.58	7.83	9.48
Gas (Mcf/d)	1.77	1.89	1.24	1.17
NGL (Bbls/d)	—	—	—	—
Combined (BOE/d)	8.12	8.59	7.46	7.40

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(6:1)

	Quarter Ended
	2004
	Dec. 31	Sept. 30	June 30	Mar. 31
Netback Received ($/BOE)
Light and Medium Crude Oil (Bbls/d)	36.27	38.87	28.77	27.58
Heavy Oil (Bbls/d)	13.20	17.79	17.02	15.26
Gas (Mcf/d)	19.68	20.23	25.72	22.72
NGL (Bbls/d)	23.05	23.92	28.24	26.10
Combined (BOE/d)	25.22	26.76	25.64	23.29

The following table indicates Acclaim Energy’s average daily production from its important fields for the year ended December 31, 2004:

	Light and Medium Crude Oil	Heavy Oil	Gas	NGL	BOE
	(Bbl/d)	(Bbl/d)	(MMcf/d)	(Bbls/d)	(BOE/d)
Total Alberta	8,189	545	84,598	3,911	26,745
Acheson	572	0	8,312	1,193	3,150
Bigoray/Brazeau	1,053	0	9,315	338	2,945
Willesden Green	1,178	0	5,244	194	2,246
Golden Spike	200	0	7,121	671	2,058
Gilby/Medicine River	468	0	5,809	194	1,630
Kaybob South	138	0	2,797	296	900
Simonette	620	0	1,043	55	849
Mitsue	607	0	582	86	790
Pouce Coupe	393	0	1,283	32	639
Other Properties	2,960	545	43,092	852	11,538
Total Saskatchewan	1,453	2,871	760	5	4,455
Furness	0	1,380	9	0	1,379
Dodsland	366	23	154	5	420
Other Properties	1,087	1,474	597	0	2,656
Total British Columbia	66	0	8,854	72	1,614
Buick Creek	59	0	2,443	48	514
BC Minor	0	0	2,818	0	470
Other Properties	7	0	3,593	24	630
Total Manitoba	607	0	0	0	607
Virden	378	0	0	0	378
Other Properties	229	0	0	0	229
Total	10,315	3,416	94,212	3,988	33,421

Note:

(1)Production numbers reflect total production averaged over the course of the year. Total production numbers were averaged for the time during which Acclaim owned the properties, which in several key properties acquired from ChevronTexaco was effective from June 30, 2004.

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Employees

At December 31, 2004, Acclaim Energy had a total of 232 full time employees and 56 persons on a contract or consulting basis. During 2004, Acclaim’s head office staff increased from 83 at December 31, 2003 to 136 at December 31, 2004.  Field staff increased from 62 at December 31, 2003 to 96 at December 31, 2004.  The increase in employment levels was necessary to effectively manage the increased property base.

Industry Conditions

Introduction

The oil and gas industry is subject to extensive controls and regulations imposed by various levels of government.  Outlined below are some of the more significant aspects of the legislation, regulations and agreements governing the oil and gas industry.  Although it is not expected that these controls and regulations will affect the operations of the Operating Entities in a manner materially different than it would affect other oil and gas companies of a similar size, the controls and regulations should be considered carefully by investors.  All current legislation is a matter of public record and Acclaim Energy is unable to predict what additional legislation or amendments may be enacted.

Pricing and Marketing – Natural Gas

In Canada, natural gas is sold throughout the country at various market hubs that are connected to several pipelines within Canada and the United States.   The transaction price is determined by negotiation between buyers and sellers and includes the utilization of electronic trading platforms and various publications and reference indexes.  Prices depend on many variables including but not limited to supply and demand fundamentals, the price of NYMEX natural gas contracts, distance to alternate markets, pipeline costs, natural gas storage, competing fuels, contract term, weather conditions and foreign exchange rates.  Natural gas exported from Canada is subject to regulation by the National Energy Board (the “NEB”) and the Government of Canada.  The price received for natural gas that is exported depends largely on the same variables noted above including the market hub prices at the delivery end of the export pipelines.  As in the case with oil, 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 and the issue of such license requires the approval of the Governor in Council.

The governments of Alberta, British Columbia and Saskatchewan also regulate the removal of natural gas from those provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements and market considerations.

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.  Such price depends in part on oil type and quality, price of competing fuels, distance to market, the value of refined products, supply/demand balance and other contractual terms.  Oil exporters are also entitled to enter into export contracts and export oil provided that, for contracts that do not exceed one year in the case of light crude oil and two years in the case of heavy crude oil, an export order is obtained from the NEB prior to the export.  Any export pursuant to a contract of longer duration (to a maximum of 25 years) must be made pursuant to an NEB export license and Governor in Council approval.

The North American Free Trade Agreement

On January 1, 1994, the North American Free Trade Agreement (“NAFTA”) among the governments of Canada, the U.S. and Mexico became effective.  The 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 are justified under certain provisions of the General Agreement on Tariffs and Trade, and further provided that any export restrictions do not: (i) reduce the proportion of energy resources exported relative to the total supply of the energy resource (based upon the proportion prevailing in the most recent 36 month period or in such other representative period as the parties may agree), (ii) impose an export price higher than the domestic price subject to an exception with respect to certain measures which only restrict the volume of exports, and (iii) disrupt normal channels of supply.  All three countries are prohibited from imposing minimum or maximum export or import price requirements, provided, in the case of export-price

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requirements, prohibition in any circumstances in which any other form of quantitative restriction is prohibited, and in the case of import-price requirements, such requirements do not apply with respect to enforcement of countervailing and anti-dumping orders and undertakings.

The NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector and prohibits discriminatory border restrictions and export taxes.  The agreement also contemplates clearer disciplines on regulators to ensure fair implementation of any regulatory changes and to minimize disruption of contractual arrangements, which is important for Canadian natural gas exports.

Royalties and Incentives

In addition to federal regulation, each province has legislation and regulations that govern land tenure, royalties, production rates, environmental protection and other matters.  The royalty regime is a significant factor in the profitability of oil, natural gas and natural gas liquids 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.  Operations of the Operating Entities that are not on Crown lands and are subject to the provisions of specific agreements are also usually subject to royalties negotiated between the mineral owner and the lessee.  These royalties are not eligible for incentive programs sponsored by various governments as discussed below.  Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production, and the rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date, method of recovery and the type or quality of the petroleum product produced.

From time to time the governments of Canada, Alberta and Saskatchewan have established incentive programs that have included royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced recovery projects.  The trend in recent years has been for provincial governments to allow such incentive programs to expire without renewal, and consequently few such incentive programs are currently operative.

Oil royalty rates vary from province to province.  In Alberta, oil royalty rates vary between 10% and 35% for oil and 10% and 30% for new oil.  The new oil rate is applicable to oil pools discovered after March 31, 1974 and prior to October 1, 1992.  The Alberta government introduced the Third Tier Royalty with a base rate of 10% and a rate cap of 25% for oil pools discovered after September 30, 1992.

Effective January 1, 1994, the calculation and payment of natural gas royalties became subject to a simplified process.  The royalty reserved to the Crown, 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.  Natural gas produced from qualifying exploratory natural gas wells spudded or deepened after July 31, 1985 and before June 1, 1988 continues to be eligible for a royalty exemption for a period of 12 months, or such later time that the value of the exempted royalty quantity equals a prescribed maximum amount.  Natural gas produced from qualifying intervals in eligible natural gas wells spudded or deepened to a depth below 2,500 metres is also subject to a royalty exemption, the amount of which depends on the depth of the well.

Oil sands projects are subject to a specific regulation made effective July 1, 1997 and expiring June 30, 2007, which, among other things, determines the Crown’s share of crude and processed oil sands products.

In Alberta, a producer of oil or natural gas from Crown lands is entitled to a credit against the royalties payable to the Crown by virtue of the ARTC program.  The ARTC program is based on a price-sensitive formula, and the ARTC rate currently varies between 75% for prices for oil at or below $100 per cubic metre and 25% for prices above $210 per cubic metre.  In general, the ARTC rate is currently applied to a maximum of $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 corporations claiming maximum entitlement to ARTC will generally not be eligible for ARTC.  The rate is established quarterly based on the average “par price”, as determined by the applicable government department for the previous quarterly period.  On December 22, 1997, the Alberta government announced that it would conduct a review of the ARTC program with the objective of setting out better targeted objectives for a smaller program and to deal with administrative difficulties.  On August 30, 1999, the Alberta government announced that it would not be reducing the size of the program, but that it would introduce new rules to reduce the number of persons who qualify for the program.  The new rules will preclude companies that pay less than $10,000 in royalties per year and non-corporate entities from qualifying from the program.

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Effective January 1, 1994, the Government of Saskatchewan revised its fiscal regime for the oil and gas industry.  Some royalties on wells existing as of that date will remain unchanged and therefore subject to various periods of royalty/tax reduction.  While a number of incentives were eliminated or reduced (such as incentives for vertical infill wells and lower cost horizontal wells), new incentive programs were initiated to encourage greater exploration and development activity in the province.

The new fiscal regime in Saskatchewan provides an incentive to encourage the drilling of new vertical oil wells through a revised royalty/tax structure for new vertical oil wells and incremental production from new or expanded water flood projects, but not horizontal wells.  The “Third Tier” Crown royalty rate and freehold production tax structure, which does not apply to horizontal wells, is price sensitive and varies between heavy and non-heavy oil (from a minimum of 10% for heavy oil at a base price to a maximum of 35% for non-heavy oil at a price above the base price).  Previous time-based royalty/tax holidays applicable to new vertically drilled oil wells have been replaced with volume-based royalty/tax reduction incentives in which a maximum royalty of 5% (before application of the 1% Saskatchewan Resource Credit) will apply to various volumes depending on the depth and nature of the well (up to 25,000 cubic metres of oil in the case of deep exploratory wells).  The maximum royalty applicable to the first 12,000 cubic metres of oil has been increased from 5% to 10% for production from certain re-entry horizontal wells.  In addition, royalty/tax holidays for deep horizontal oil wells have been replaced with a 25,000 cubic metres volume incentive (5% maximum royalty).  Oil production from qualifying reactivated oil wells are subject to a maximum new royalty rate of 5% (before the application of the 1% Saskatchewan Resource Credit) for the first five years following re-activation in the case of wells reactivated after 1993 and shut-in or suspended prior to January 1, 1993.  With respect to qualifying exploratory natural gas wells, the first 25 million cubic metres of natural gas produced will be subject to an incentive maximum royalty rate of 5% (0% freehold production tax).

Producers of oil and natural gas in British Columbia are required to pay annual rental payments in respect of Crown leases and royalties and freehold production taxes in respect of oil and gas produced from Crown and freehold lands, respectively.  The amount payable as a royalty in respect of oil depends on the vintage of the oil (whether it was produced from a pool discovered before or after October 31, 1975), whether the oil is considered incremental or produced from a well shut-in for at least 36 months immediately preceding January 1, 1998 and which resumed production on or after such date, the quantity of oil produced in a month and the value of the oil.  Oil produced from pools discovered after June 30, 1974 may be exempt from the payment of a royalty for the first 36 months of production.  Subject to the minimum royalties described in the following sentence, the royalty payable on natural gas is determined by a sliding scale based on a reference price, which is the greater of the amount obtained by the producer and a prescribed minimum price.  Gas produced in association with oil has a minimum royalty of 8% while the royalty in respect of other gas may not be less than 15%.

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

On March 3, 2003 the Department of Finance (Canada) released a technical paper entitled “Improving the Income Taxation of the Resource Sector in Canada” (the “Technical Paper”).  The new structure for federal taxation of resource income proposed by the Technical Paper contains the following initiatives applicable to the oil and gas industry to be phased in over a five year period: (i) a reduction of the federal statutory corporate income tax rate on income earned from resource activities from 28 to 21%, beginning with a one percentage point reduction effective January 1, 2003, and (ii) a deduction for federal income tax purposes of actual provincial and other Crown royalties and mining taxes paid and the elimination of the 25% resource allowance.  The Technical Paper also proposes that the percentage of ARTC that the Trust will be required to include in federal taxable income will be 5% in 2003; 12.5% in 2004; 17.5% in 2005; 32.5% in 2006; 50% in 2007; 60% in 2008; 70% in 2009; 80% in 2010; 90% in 2011, and 100% in 2012 and beyond.

Land Tenure

Crude oil and natural gas located in the western Canadian provinces is owned predominantly 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 periods and on conditions set forth in provincial legislation including 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 granted by lease on such terms and conditions as may be negotiated.

Environmental Regulation

The oil and natural gas industry is subject to environmental regulation pursuant to local, provincial and federal legislation.  Environmental legislation provides for restrictions and prohibitions on releases or emissions and regulation on the storage and

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transportation of various substances produced or utilized in association with certain oil and gas industry operations and can affect the location and operation of wells and facilities and the extent to which exploration and development is permitted.  In addition, legislation requires that well and facilities sites be abandoned and reclaimed to the satisfaction of provincial authorities.  As well, 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 and a breach of such legislation may result in the suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage, the imposition of fines and penalties or the issuance of clean-up orders.

Acclaim Energy anticipates making increased, although not material, expenditures of both a capital and expense nature as a result of increasingly stringent laws relating to the protection of the environment.

ADDITIONAL INFORMATION RESPECTING ACCLAIM ENERGY TRUST

Units

An unlimited number of Units may be created and issued pursuant to the Trust Indenture.  Each Unit represents an equal fractional undivided beneficial interest in any distribution from the Trust (whether of net income, net realized capital gains or other amounts) and in any net assets of the Trust in the event of termination or winding-up of the Trust.  All Units outstanding from time to time is entitled to an equal share of any distributions from, and in any net assets of, the Trust in the event of the termination or winding-up of the Trust.  All Units of the Trust rank among themselves equally and ratably without discrimination, preference or priority.  Each Unit is transferable, is not be subject to any conversion or pre-emptive rights and entitles the holder thereof to require the Trust to redeem any or all of the Units held by such holder (see “Redemption Right”) and to one vote at all meetings of Unitholders for each Unit held.  Unitholders shall not be subject to any liability in contract or tort or of any other kind in connection with the assets, obligations or affairs of the Trust or with respect to any acts performed by the Trustee or any other person pursuant to the Trust Indenture.

At March 23, 2005, there were 104,423,403 Units outstanding, 645,039 Units reserved for issuance upon exercise of Acclaim Exchangeable Shares (subject to increase for distributions), 5,633,515 Units reserved for issuance on conversion of the Convertible Debentures and up to 2,500,000 Units reserved for issuance pursuant to the Trust’s Unit Award Incentive Plan (subject to increase in accordance with such plan).  See “Additional Information Respecting Acclaim Energy Inc. – Share Capital of Acclaim Energy” and “— Convertible Debentures of the Trust”.

Special Voting Units

In order to allow the Trust flexibility in pursuing corporate acquisitions, the Trust Indenture allows for the creation of Special Voting Units which will enable the Trust to effect exchangeable securities transactions.  Exchangeable securities transactions are commonly used in corporate acquisitions to give the selling securityholder a tax deferred “rollover” on the sale of the securityholder’s securities, which may not otherwise be available.  In an exchangeable securities transaction the tax event is generally deferred until the exchangeable securities are actually exchanged.

An unlimited number of Special Voting Units may be created and issued pursuant to the Trust Indenture.  Holders of Special Voting Units are not be entitled to any distributions of any nature whatsoever from the Trust, but are entitled to such number of votes at meetings of Unitholders as may be prescribed by the Board of Directors of Acclaim Energy in the resolution authorizing the issuance of any Special Voting Units.  Except for the right to vote at meetings of the Unitholders, the Special Voting Units shall not confer upon the holders thereof any other rights.

One Special Voting Unit is issued and outstanding and is entitled to that number of votes at all meetings of Unitholders equal to the number of Acclaim Exchangeable Shares outstanding from time to time.  At March 23, 2005, there were  645,039 Acclaim Exchangeable Shares outstanding.

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Convertible Debentures of the Trust

The Trust has outstanding two series of convertible debenture outstanding, the 8% Debentures and the 11% Debentures (collectively, the “Convertible Debentures”). The following is a summary of the material attributes and characteristics of the Convertible Debentures.

The 8% Debentures have been issued pursuant to the provisions of a supplemental indenture (the “8% Debenture Indenture”) dated as of June 15, 2004 among the Trust, Acclaim Energy and Computershare Trust Company of Canada, as trustee (the “8% Debenture Trustee”).  The 11% Debentures have been issued pursuant to the provisions of an indenture (the “11% Debenture Indenture”) dated as of December 17, 2002 among the Trust, Acclaim Energy and Computershare Trust Company of Canada, as trustee (the “11% Debenture Trustee”).  This summary does not purport to be complete and is subject to, and qualified in its entirety by, reference to the terms of the 8% Debenture Indenture and the 11% Debenture Indenture (collectively, the “Debenture Indentures”).

The 8% Debentures were originally issued in the aggregate principal amount of $75 million and approximately $ 67.9  million principal amount were outstanding at March 23, 2005.  The 8% Debentures mature on August 31, 2009.

The 11% Debentures were originally issued in the aggregate principal amount of $45 million and approximately $ 5.9  million principal amount were outstanding at  March 23, 2005.  The 11% Debentures mature on December 31, 2007.

Terms and Issue of Convertible Debentures

The 8% Debentures bear interest from the date of issue at 8% per annum, which is payable semi-annually in arrears on February 28 and August 31 in each year.  The 11% Debentures bear interest from the date of issue at 11% per annum, which is payable semi-annually in arrears on June 30 and December 31 in each year.

The principal amount of the Convertible Debentures is payable in lawful money of Canada or, at the option of the Trust and subject to applicable regulatory approval, by payment of Units as further described under “Payment upon Redemption or Maturity” and “Redemption and Purchase”.  The interest on the Convertible Debentures is payable in lawful money of Canada including, at the option of the Trust and subject to applicable regulatory approval, in accordance with the Unit Interest Payment Obligation as described under “Interest Payment Option”.

The Convertible Debentures are direct obligations of the Trust and are not secured by any mortgage, pledge, hypothec or other charge and are subordinated to other liabilities of the Trust as described under “Subordination”.  The Debenture Indentures do not restrict the Trust from incurring additional indebtedness for borrowed money or from mortgaging, pledging or charging its properties to secure any indebtedness.

Conversion Privilege

The 8% Debentures are convertible at the holder’s option into fully paid and non-assessable Units at any time prior to 5:00 p.m. (Calgary time) on the earlier of August 31, 2009, and the business day immediately preceding the date specified by the Trust for redemption of the 8% Debentures, at a conversion price of $13.50 per Unit, being a conversion rate of 74.0741 Units for each $1,000 principal amount of 8% Debentures.

The 11% Debentures are convertible at the holder’s option into fully paid and non-assessable Units at any time prior to 5:00 p.m. (Calgary time) on the earlier of December 31, 2007 and the business day immediately preceding the date specified by the Trust for redemption of the 11% Debentures, at a conversion price of $9.75 per Unit (the “11% Conversion Price”), being a conversion rate of 102.56 Units for each $1,000 principal amount of 11% Debentures.

No adjustment will be made for distributions on Units issuable upon conversion or for interest accrued on Convertible Debentures surrendered for conversion; however, holders converting their Convertible Debentures will receive accrued and unpaid interest thereon.

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Redemption and Purchase

The 8% Debentures are not redeemable on or before August 31, 2007. After August 31, 2007 and prior to maturity, the Debentures may be redeemed in whole or in part from time to time at the option of the Trust on not more than 60 days and not less than 40 days prior notice, at a redemption price of $1,050 per 8% Debenture after August 31, 2007 and on or before August 31, 2008 and at a redemption price of $1,025 per 8% Debenture after August 31, 2008 and before maturity (each an “8% Redemption Price”), in each case, plus accrued and unpaid interest thereon, if any.

The 11% Debentures are not redeemable on or before January 1, 2006.  After January 1, 2006 and prior to maturity, the 11% Debentures may be redeemed in whole or in part from time to time at the option of the Trust on not more than 60 days and not less than 30 days prior notice, at a redemption price of $1,050 per 11% Debenture after January 1, 2006 and on or before January 1, 2007 and at a redemption price of $1,025 per 11% Debenture after January 1, 2007 and before maturity (each an “11 % Redemption Price”), in each case, plus accrued and unpaid interest thereon, if any.

In the case of redemption of less than all of the 8% Debentures or 11% Debentures, as the case may be, the 8% Debentures or 11% Debentures, as the case may be, to be redeemed will be selected by the Debenture Trustee or 11% Debenture Trustee on a pro rata basis or in such other manner as the Debenture Trustee or 11% Debenture Trustee deems equitable, subject to the consent of the TSX.

The Trust has the right to purchase Convertible Debentures in the market, by tender or by private contract.

Payment upon Redemption or Maturity

On redemption or at maturity, the Trust will repay the indebtedness represented by the Convertible Debentures by paying to the Debenture Trustee in lawful money of Canada an amount equal to the aggregate applicable Redemption Price of the outstanding Convertible Debentures which are to be redeemed or the principal amount of the outstanding Convertible Debentures which have matured, as the case may be, together with accrued and unpaid interest thereon. The Trust may, at its option, on not more than 60 days and not less than 40 days prior notice (30 days in the case of the 11% Debentures) and subject to applicable regulatory approval, elect to satisfy its obligation to pay the Redemption Price of the Convertible Debentures which are to be redeemed or the principal amount of the Convertible Debentures which have matured, as the case may be, by issuing Units to the holders of the 8% Debentures.  Any accrued and unpaid interest thereon will be paid in cash.  The number of Units to be issued will be determined by dividing the aggregate Redemption Price of the outstanding Convertible Debentures which are to be redeemed or the principal amount of the outstanding 8% Debentures which have matured, as the case may be, by 95% of the current market price on the date fixed for redemption or the maturity date, as the case may be.  No fractional Units will be issued on redemption or maturity but in lieu thereof the Trust shall satisfy fractional interests by a cash payment equal to the current market price of any fractional interest.

The term “current market price” is defined in the Debenture Indentures to mean the weighted average trading price of the Units on the TSX for the 20 consecutive trading days ending on the fifth trading day preceding the date fixed for redemption or the maturity date, as the case may be.

Subordination

The payment of the principal of, and interest on, the Convertible Debentures is subordinated in right of payment, as set forth in the Debenture Indentures, to the prior payment in full of all Senior Indebtedness of the Trust and indebtedness to trade creditors of the Trust. “Senior Indebtedness” of the Trust is defined in the Debenture Indentures as the principal of and premium, if any, and interest on and other amounts in respect of all indebtedness of the Trust (whether outstanding as at the date of the Indenture or thereafter incurred), other than indebtedness evidenced by the Convertible Debentures and all other existing and future debentures or other instruments of the Trust which, by the terms of the instrument creating or evidencing the indebtedness, is expressed to be pari passu with, or subordinate in right of payment to, the Convertible Debentures.

The Debenture Indentures provide that in the event of any insolvency or bankruptcy proceedings, or any receivership, liquidation, reorganization or other similar proceedings relative to the Trust, or to its property or assets, or in the event of any proceedings for voluntary liquidation, dissolution or other winding-up of the Trust, whether or not involving insolvency or bankruptcy, or any marshalling of the assets and liabilities of the Trust, then those holders of Senior Indebtedness, including any indebtedness to trade creditors, will receive payment in full before the holders of Convertible Debentures will be entitled to receive any payment or distribution of any kind or character, whether in cash, property or securities, which may be payable or deliverable in any such event in

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respect of any of the Convertible Debentures or any unpaid interest accrued thereon.  The Debenture Indentures also provide that the Trust will not make any payment, and the holders of the Convertible Debentures will not be entitled to demand, institute proceedings for the collection of, or receive any payment or benefit (including, without any limitation, by set-off, combination of accounts or realization of security or otherwise in any manner whatsoever) on account of indebtedness represented by the Convertible Debentures (a) in a manner inconsistent with the terms (as they exist on the date of issue) of the Convertible Debentures or (b) at any time when an event of default has occurred under the Senior Indebtedness and is continuing and the notice of such event of default has been given by or on behalf of the holders of Senior Indebtedness to the Trust, unless the Senior Indebtedness has been repaid in full.

The Convertible Debentures are effectively subordinate to claims of creditors of the Trust’s subsidiaries except to the extent the Trust is a creditor of such subsidiaries ranking at least pari passu with such other creditors.  Specifically, the Convertible Debentures are subordinated in right of payment to the prior payment in full of all indebtedness under the Trust’s credit facilities.

Priority over Trust Distributions

The Debenture Indentures provide that certain expenses of the Trust must be deducted in calculating the amount to be distributed to the Unitholders.  Accordingly, the funds required to satisfy the interest payable on the Convertible Debentures, as well as the amount payable upon redemption or maturity of the Convertible Debentures or upon an Event of Default (as defined below), will be deducted and withheld from the amounts that would otherwise be payable as distributions to Unitholders.

Change of Controlof the Trust

Within 30 days following the occurrence of a change of control of the Trust involving the acquisition of voting control or direction over 66²/₃% or more of the Units (a “Change of Control”), the Trust is required to make an offer in writing to purchase all of the Convertible Debentures then outstanding (the “Debenture Offer”), at a price equal to 101% of the principal amount thereof plus accrued and unpaid interest (the “Debenture Offer Price”).

If 90% or more of the aggregate principal amount of the 8% Debentures or 11% Debentures outstanding on the date of the giving of notice of the Change of Control have been tendered to the Trust pursuant to the applicable Debenture Offer, the Trust will have the right and obligation to redeem all the remaining 8% Debentures or 11% Debentures at the applicable Debenture Offer Price.

Interest Payment Option

The Trust may elect, from time to time, to satisfy its obligation to pay all or any part of the interest on the Convertible Debentures (the “Interest Obligation”), on the date it is payable under the applicable Debenture Indenture (an “Interest Payment Date”), by delivering sufficient Units to the Debenture Trustee to satisfy all or the part, as the case may be, of the Interest Obligation in accordance with the applicable Debenture Indenture (the “Unit Interest Payment Election”). The Debenture Indentures provide that, upon such election, the Debenture Trustee shall (a) accept delivery from the Trust of Units, (b) accept bids with respect to, and consummate sales of, such Units, each as the Trust shall direct in its absolute discretion, (c) invest the proceeds of such sales in short-term permitted government securities (as defined in the Indenture) which mature prior to the applicable Interest Payment Date, and use the proceeds received from such permitted government securities, together with any proceeds from the sale of Units not invested as aforesaid, to satisfy the Interest Obligation, and (d) perform any other action necessarily incidental thereto.

If a Unit Interest Payment Election is made, the sole right of a holder of Convertible Debentures in respect of interest will be to receive cash from the Debenture Trustee out of the proceeds of the sale of Units (plus any amount received by the Debenture Trustee from the Trust attributable to any fractional Units) in full satisfaction of the Interest Obligation, and the holder of such Convertible Debentures will have no further recourse to the Trust in respect of the Interest Obligation.

Events ofDefault

The Debenture Indentures provide that an event of default (“Event of Default”) in respect of the Convertible Debentures will occur if any one or more of the following described events has occurred and is continuing with respect of the Convertible Debentures: (a) failure for 10 days to pay interest on the Convertible Debentures when due; (b) failure to pay principal or premium, if any, on the Convertible Debentures when due, whether at maturity, upon redemption, by declaration or otherwise; (c) certain events of bankruptcy, insolvency or reorganization of the Trust under bankruptcy or insolvency laws; or (d) default in the observance or performance of any material covenant or condition of the Indenture and continuance of such default for a period of 30 days after

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notice in writing has been given by the Debenture Trustee to the Trust specifying such default and requiring the Trust to rectify the same.  If an Event of Default has occurred and is continuing, the Debenture Trustee may, in its discretion, and shall upon request of holders of not less than 25% of the principal amount of the applicable Convertible Debentures then outstanding, declare the principal of and interest on all outstanding such Convertible Debentures to be immediately due and payable. In certain cases, the holders of more than 50% of the principal amount of the applicable Convertible Debentures then outstanding may, on behalf of the holders of all such Convertible Debentures, waive any Event of Default and/or cancel any such declaration upon such terms and conditions as such holders shall prescribe.

Offers for Debentures

The Debenture Indentures contain provisions to the effect that if an offer is made for the 8% Debentures or the 11% Debentures, as the case may be, which is a take-over bid for such Convertible Debentures within the meaning of the Securities Act (Alberta) and not less than 90% of such Convertible Debentures (other than Debentures held at the date of the take-over bid by or on behalf of the offeror or associates or affiliates of the offeror) are taken up and paid for by the offeror, the offeror will be entitled to acquire the Convertible Debentures held by the holders of such Convertible Debentures who did not accept the offer on the terms offered by the offeror.

Modification

The rights of the holders of the Convertible Debentures may be modified in accordance with the terms of the Debenture Indentures.  For that purpose, among others, the Debenture Indentures contain certain provisions which will make binding on all Convertible Debenture holders’ resolutions passed at meetings of the holders of Convertible Debentures by votes cast thereat by holders of not less than 66²/₃% of the principal amount of the Convertible Debentures present at the meeting or represented by proxy, or rendered by instruments in writing signed by the holders of not less than 66²/₃% of the principal amount of the Convertible Debentures then outstanding.  In certain cases, the modification will, instead or in addition, require assent by the holders of the required percentage of Debentures of each particularly affected series.

Limitation on Issuance of Additional Convertible Debentures

The Debenture Indentures provide that the Trust shall not issue additional convertible debentures of equal ranking if the principal amount of all issued and outstanding convertible debentures of the Trust exceeds 25% of the Total Market Capitalization of the Trust immediately after the issuance of such additional convertible debentures.  “Total Market Capitalization” is defined in the Debenture Indentures as the total principal amount of all issued and outstanding debentures of the Trust which are convertible at the option of the holder into Units of the Trust plus the amount obtained by multiplying the number of issued and outstanding Units of the Trust by the current market price of the Units on the relevant date.

Limitation on Non Resident Ownership

At no time may non-residents of Canada be the beneficial owners of a majority of the Units, on a fully diluted basis, including any Units that may be issued upon conversion, redemption or maturity of the Convertible Debentures.  The Debenture Trustee may require declarations as to the jurisdictions in which beneficial owners of Convertible Debentures are resident.  If the Debenture Trustee becomes aware as a result of requiring such declarations as to beneficial ownership, that the beneficial owners of 49% of the Units then outstanding, on a fully diluted basis, are, or may be, non residents or that such a situation is imminent, the Debenture Trustee may make a public announcement thereof and shall not register a transfer of Convertible Debentures to a person unless the person provides a declaration that the person is not a non resident.  If, notwithstanding the foregoing, the Debenture Trustee determines that a majority of the Units are held by non-residents, the Debenture Trustee may send a notice to non resident holders of Convertible Debentures, chosen in inverse order to the order of acquisition or registration of the Convertible Debentures or in such manner as the Debenture Trustee may consider equitable and practicable, requiring them to sell their Convertible Debentures or a portion thereof within a specified period of not less than 60 days.  If the Convertible Debenture holders receiving such notice have not sold the specified number of Convertible Debentures or provided the Debenture Trustee with satisfactory evidence that they are not non residents within such period, the Debenture Trustee may on behalf of such Debenture holder sell such Convertible Debentures, and, in the interim, shall suspend the rights attached to such Convertible Debentures.  Upon such sale the affected holders shall cease to be holders of Convertible Debentures, and their rights shall be limited to receiving the net proceeds of sale upon surrender of such Convertible Debentures.

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Book-Entry System for 8% Debentures

The 8% Debentures are issued in “book-entry only” form and must be purchased or transferred through a participant in the depository service of CDS. The 8% Debentures are evidenced by a single book-entry only certificate. Registration of interests in and transfers of the Debentures is made only through the depository service of CDS.

Issuance of Units

The Trust Indenture provides that Units, including rights, warrants, options and other securities to purchase, to convert into or to exchange into Units, may be created, issued, sold and delivered on such terms and conditions and at such times as the Board of Directors of Acclaim Energy may determine.

Cash Distributions

The Trust makes cash distributions in amounts equal to all of the interest and dividend income of the Trust, net of the Trust’s administrative expenses.  In addition, Unitholders may, at the discretion of the Board of Directors of Acclaim Energy, receive distributions in respect of repayments of principal made by Acclaim Energy to the Trust on the Acclaim Notes.  Acclaim Energy endeavors to retain approximately 25 to 30% of its cash flow over time to fund capital expenditures and to distribute the balance to the Trust. The actual percentage retained by Acclaim Energy is subject to the discretion of the Board of Directors of Acclaim Energy and will vary from month to month depending on, among other things, the current and anticipated commodity price environment.

Cash distributions are made on or about the 20th day of each month to Unitholders of record on the immediately preceding distribution record date.  The Trust’s current policy is to distribute $0.1625 per Unit per month ($1.95 per Unit per annum).

Redemption Right

Units are redeemable at any time on demand by the holders thereof upon delivery to the Trust of the certificate or certificates representing such Units, accompanied by a duly completed and properly executed notice requesting redemption.  Upon receipt of the redemption request by the Trust, the holder thereof shall only be entitled to receive a price per Unit (the “Market Redemption Price”) equal to the lesser of: (i) 90% of the “market price” of the Units on the principal market on which the Units are quoted for trading during the 10 trading day period commencing immediately after the date on which the Units are surrendered for redemption; and(ii) the “closing market price” on the principal market on which the Units are quoted for trading on the date that the Units are surrendered for redemption.

For the purposes of this calculation, “market price” will be an amount equal to the simple average of the closing price of the Units for each of the trading days on which there was a closing price; provided that, if the applicable exchange or market does not provide a closing price but only provides the highest and lowest prices of the Units traded on a particular day, the market price shall be an amount equal to the simple average of the average of the highest and lowest prices for each of the trading days on which there was a trade; and provided further that if there was trading on the applicable exchange or market for fewer than five of the 10 trading days, the market price shall be the simple average of the following prices established for each of the 10 trading days: the average of the last bid and last ask prices for each day on which there was no trading; the closing price of the Units for each day that there was trading if the exchange or market provides a closing price; and the average of the highest and lowest prices of the Units for each day that there was trading, if the market provides only the highest and lowest prices of Units traded on a particular day.  The “closing market price” shall be: an amount equal to the closing price of the Units if there was a trade on the date; an amount equal to the average of the highest and lowest prices of the Units if there was trading and the exchange or other market provides only the highest and lowest prices of Units traded on a particular day, and the average of the last bid and last ask prices if there was no trading on the date.

The aggregate Market Redemption Price payable by the Trust in respect of any Units surrendered for redemption during any calendar month shall be satisfied by way of a cash payment on the last day of the following month.  The entitlement of Unitholders to receive cash upon the redemption of their Units is subject to the limitation that the total amount payable by the Trust in respect of such Units and all other Units tendered for redemption in the same calendar month and in any preceding calendar month during the same year shall not exceed $100,000; provided that, Acclaim Energy may, in its sole discretion, waive such limitation in respect of any calendar month.  If this limitation is not so waived, the Market Redemption Price payable by the Trust in respect of Units tendered for redemption in such calendar month shall be paid on the last day of the following month by: (i) the Trust distributing Danoil Notes having an aggregate principal amount equal to the aggregate Market Redemption Price of the Units tendered for redemption; or (ii) if

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the Trust does not hold Danoil Notes having a sufficient principal amount outstanding to effect such payment, by the Trust issuing its own promissory notes having an aggregate principal amount equal to the aggregate Market Redemption Price of the Units tendered for redemption, which promissory notes (“Redemption Notes”) shall have terms and conditions substantially identical to those of the Danoil Notes.

If at the time Units are tendered for redemption by a Unitholder, the outstanding Units are not listed for trading on the TSX and are not traded or quoted on any other stock exchange or market which Acclaim Energy considers, in its sole discretion, provides representative fair market value price for the Units or trading of the outstanding Units is suspended or halted on any stock exchange on which the Units are listed for trading or, if not so listed, on any market on which the Units are quoted for trading, on the date such Units are tendered for redemption or for more than five trading days during the 10 trading day period, commencing immediately after the date such Units were tendered for redemption then such Unitholder shall, instead of the Market Redemption Price, be entitled to receive a price per Unit (the “Appraised Redemption Price”) equal to 90% of the fair market value thereof as determined by Acclaim Energy as at the date upon which such Units were tendered for redemption.  The aggregate Appraised Redemption Price payable by the Trust in respect of Units tendered for redemption in any calendar month shall be paid on the last day of the third following month by, at the option of the Trust: (i) a cash payment; or (ii) a distribution of Notes or Redemption Notes as described above.

It is anticipated that this redemption right will not be the primary mechanism for holders of Units to dispose of their Units.  Danoil Notes or Redemption Notes that may be distributed in specie to Unitholders in connection with a redemption will not be listed on any stock exchange and no market is expected to develop in such Danoil Notes or Redemption Notes.  Danoil Notes or Redemption Notes will not be qualified investments for trusts governed by registered retirement savings plans, registered retirement income funds and deferred profit sharing plans.

Non-Resident Unitholders

Certain provisions of the Tax Act require that the Trust not be established nor maintained primarily for the benefit of Non-Residents.  Accordingly, in order to comply with such provisions, the Trust Indenture contains restrictions on the ownership of Units by Unitholders who are Non-Residents.  Unitholders may be required to provide to the Trustee a declaration (a “Residence Declaration”) specifying whether or not they are Non-Residents and if the Trustee becomes aware, as a result of requiring Residence Declarations or otherwise, that the beneficial owners of 25% of the Units then outstanding are or may be Non-Residents or such a situation is imminent, the Trustee shall thereafter request Residence Declarations at least annually in conjunction with the annual meetings of Unitholders.  If at any time the Trustee becomes aware, as a result of requiring Residence Declarations as to beneficial ownership or otherwise, that the beneficial owners of 49% of the Units then outstanding are or may be Non-Residents or that such a situation is imminent, the Trustee may make a public announcement thereof and shall not accept a subscription for Units from or issue or register a transfer of Units to a person unless the person provides a Residence Declaration that the person is not a Non-Resident.  If notwithstanding the foregoing, the Trustee determines that a majority of the Units are held by Non-Residents, the Trustee may send a notice to Non-Resident holders of Units, chosen in inverse order to the order of acquisition or registration or in such other manner as the Trustee may consider equitable and practicable, requiring them to sell their Units or a specified portion thereof within a specified period of not less than 60 days.  If the Unitholders receiving such notice have not sold the specified number of Units or provided the Trustee with satisfactory evidence that they are not Non-Residents within such period, the Trustee may on behalf of such Unitholder sell such Units and, in the interim, shall suspend the voting and distribution rights attached to such Units and shall make any distribution in respect of such Units by depositing such amount in a separate bank account in a Canadian chartered bank (net of any applicable taxes).  Any sale shall be made on any stock exchange on which the Units are then listed and, upon such sale, the affected holders shall cease to be holders of Units and their rights shall be limited to receiving the net proceeds of sale upon surrender of the Trust certificates representing such Units.

Meetings of Unitholders

The Trust Indenture provides that meetings of Unitholders must be called and held for, among other matters, the appointment or removal of the Trustee, the appointment or removal of the auditors of the Trust, the approval of amendments to the Trust Indenture (except as described under “Amendments to the Trust Indenture”), the sale of the property of the Trust as an entirety or substantially as an entirety, and the commencement of winding-up the affairs of the Trust.  Meetings of Unitholders will be called and held annually for, among other things, the election of the Trust’s nominees to the Board of Directors of Acclaim Energy and the appointment of the auditors of the Trust.

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A meeting of Unitholders may be convened at any time and for any purpose by the Trustee and must be convened, except in certain circumstances, if requisitioned by the holders of not less than 25% of the Units then outstanding by a written requisition. A requisition must, among other things, state in reasonable detail the business proposed to be transacted at the meeting.

Unitholders may attend and vote at all meetings of Unitholders either in person or by proxy and a proxyholder need not be a Unitholder.  Two persons present in person or represented by proxy and representing in the aggregate at least 5% of the votes attaching to all outstanding Units shall constitute a quorum for the transaction of business at all such meetings.  The holders of any issued Special Voting Units who are present at the meeting shall not be regarded as representing outstanding Units for the purposes of determining such quorum.

The Trust Indenture contains provisions as to the notice required and other procedures with respect to the calling and holding of meetings of Unitholders in accordance with the requirements of applicable laws.

The Trustee

Computershare Trust Company of Canada is the trustee of the Trust.  The Trustee is responsible for, among other things: (a) accepting subscriptions for Units and issuing Units pursuant thereto; (b) maintaining the books and records of the Trust and providing timely reports to holders of Units; and (c) paying cash distributions to Unitholders.  The Trust Indenture provides that the Trustee shall exercise its powers and carry out its functions thereunder as Trustee honestly, in good faith and in the best interests of the Trust and the Unitholders and, in connection therewith, shall exercise that degree of care, diligence and skill that a reasonably prudent trustee would exercise in comparable circumstances.

The term of the Trustee’s appointment is until the annual meeting of Unitholders to be held in 2003.  Thereafter, the Trustee shall be reappointed or changed every year as may be determined by a majority of the votes cast at a meeting of the Unitholders.  The Trustee may resign upon 60 days’ notice to the Trust.  The Trustee may also be removed by Special Resolution of the Unitholders.  Such resignation or removal becomes effective upon the acceptance or appointment of a successor trustee.

Delegation of Authority, Administration and Trust Governance

The Board of Directors of Acclaim Energy is generally delegated the significant management decisions of the Trust and Acclaim Energy has been retained to administer the Trust on behalf of the Trustee.  In particular, the Trustee has delegated to Acclaim Energy responsibility for any and all matters relating to: (a) the redemption of Units; (b) the making of investments by the Trust and the negotiation of management agreements respecting such investments; (c) any offering of securities of the Trust including: (i) the listing and maintaining of the listing on the TSX (or any other stock exchange) of the Units; (ii) the filing of documents or obtaining of permission from any governmental or regulatory authority or the taking of any other step under federal or provincial law to enable securities which a Unitholder is entitled to receive to be properly and legally delivered and thereafter traded; (iii) ensuring compliance with all applicable laws; (iv) all matters relating to the content of any prospectus, information memorandum, private placement memorandum and similar public or private securities offering documents, and the certification thereof; (v) all matters concerning the terms of the sale or issuance of Units or rights to Units; (d) the determination of any record date for distributions; and (e) the determination of any borrowing or granting of security under the Trust Indenture.

Board of Directors

Acclaim Energy currently has a Board of Directors consisting of eight individuals.  Unitholders are entitled to elect the Board of Directors of Acclaim Energy.  In its Information Circular -Proxy Statement dated March 23, 2005, Acclaim Energy has proposed the election of eight directors by Unitholders.  See “Additional Information Respecting Acclaim Energy Inc.”.

Decision Making

The Board of Directors of Acclaim Energy supervises the management of the business and affairs of Acclaim Energy, including the business and affairs of the Trust delegated to Acclaim Energy.  The Trustee delegated certain matters to the Board of Directors of Acclaim Energy including all decisions relating to: (i) issuance of additional Units; and (ii) the determination of the amount of distributable cash.  The Board of Directors of Acclaim Energy generally intends to hold regularly scheduled meetings to review the business and affairs of Acclaim Energy and make any necessary decisions relating thereto.

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Liability of the Trustee

The Trust Indenture provides that the Trustee, its directors, officers, employees, shareholders and agents shall not be liable to any Unitholder or any other person, in tort, contract or otherwise, in connection with any matter pertaining to the Trust or the Assets, arising from the exercise by the Trustee of any powers, authorities or discretion conferred under the Trust Indenture, including, without limitation, any action taken or not taken in good faith in reliance on any documents that are, prima facie, properly executed, any depreciation of, or loss to, the Assets incurred by reason of the sale of any asset, any inaccuracy in any evaluation provided by Acclaim Energy or any other appropriately qualified person, any reliance on any such evaluation, any action or failure to act of Acclaim Energy or any other person to whom the Trustee has, with the consent of Acclaim Energy, delegated any of its duties thereunder, or any other action or failure to act (including failure to compel in any way any former trustee to redress any breach of trust or any failure by Acclaim Energy to perform its duties under or delegated to it under the Trust Indenture or any material contract), unless such liabilities arise out of the gross negligence, willful default or fraud of the Trustee or any of its directors, officers, employees, shareholders or agents.  If the Trustee has retained an appropriate expert, adviser or legal counsel with respect to any matter connected with its duties under the Trust Indenture or any material contract, the Trustee may act or refuse to act based on the advice of such expert, adviser or legal counsel, and the Trustee shall not be liable for and shall be fully protected from any loss or liability occasioned by any action or refusal to act based on the advice of any such expert, adviser or legal counsel.  In the exercise of the powers, authorities or discretion conferred upon the Trustee under the Trust Indenture, the Trustee is and shall be conclusively deemed to be acting as Trustee of the assets of the Trust and shall not be subject to any personal liability for any debts, liabilities, obligations, claims, demands, judgments, costs, charges or expenses against or with respect to the Trust or the Assets.  In addition, the Trust Indenture contains other customary provisions limiting the liability of the Trustee.

Amendments to the Trust Indenture

The Trust Indenture may be amended or altered from time to time by Special Resolution.  The Trustee may, without the approval of the Unitholders, make certain amendments to the Trust Indenture, including amendments for the purpose of:

(a)ensuring the Trust’s continuing compliance with applicable laws or requirements of any governmental agency or authority of Canada or of any province;

(b)ensuring that the Trust will satisfy the provisions of each of subsections 108(2) and 132(6) of the Tax Act as from time to time amended or replaced;

(c)ensuring that such additional protection is provided for the interests of Unitholders as the Trustee may consider expedient;

(d)removing or curing any conflicts or inconsistencies between the provisions of the Trust Indenture or any supplemental indenture, the Administration Agreement and any other agreement of the Trust or any offering document pursuant to which securities of the Trust are issued with respect to the Trust, or any applicable law or regulation of any jurisdiction, provided that in the opinion of the Trustee the rights of the Trustee and of the Unitholders are not prejudiced thereby; and

(e)curing, correcting or rectifying any ambiguities, defective or inconsistent provisions, errors, mistakes or omissions, provided that in the opinion of the Trustee the rights of the Trustee and of the Unitholders are not prejudiced thereby.

Take-over Bids

The Trust Indenture contains provisions to the effect that if a take-over bid is made for the Units and not less than 90% of the Units (other than Units held at the date of the take-over bid by or on behalf of the offeror or associates or affiliates of the offeror) are taken up and paid for by the offeror, the offeror will be entitled to acquire the Units held by Unitholders who did not accept the take-over bid on the terms offered by the offeror.

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Termination of the Trust

The Unitholders may vote to terminate the Trust at any meeting of the Unitholders duly called for that purpose, subject to the following: (a) a vote may only be held if requested in writing by the holders of not less than 25% of the Units; (b) a quorum of 50% of the issued and outstanding Units is present in person or by proxy; and (c) the termination must be approved by Special Resolution of Unitholders.

Unless the Trust is terminated or extended by vote of the Unitholders earlier, the Trustee shall commence to wind-up the affairs of the Trust on December 31, 2099.  In the event that the Trust is wound-up, the Trustee will sell and convert into money the trust assets in one transaction or in a series of transactions at public or private sale and do all other acts appropriate to liquidate the trust assets, and shall in all respects act in accordance with the directions, if any, of the Unitholders in respect of termination authorized pursuant to the Special Resolution authorizing the termination of the Trust.  In no event shall the Trust be wound up until the trust assets shall have been disposed of, and under no circumstances shall any Unitholder come into possession of any interest in the trust assets.  After paying, retiring or discharging or making provision for the payment, retirement or discharge of all known liabilities and obligations of the Trust and providing for indemnity against any other outstanding liabilities and obligations, the Trustee shall distribute the remaining part of the proceeds of the sale of the trust assets among the Unitholders in accordance with their pro rata share.

Reporting to Unitholders

The financial statements of the Trust will be audited annually by an independent recognized firm of chartered accountants.  The audited financial statements of the Trust, together with the report of such chartered accountants, will be mailed by the Trustee to Unitholders and the unaudited interim financial statements of the Trust will be mailed to Unitholders within the periods prescribed by securities legislation. The year-end of the Trust is December 31.

The Trust is subject to the continuous disclosure obligations under applicable securities legislation.

Management of the Trust

Pursuant to the provisions of the Administration Agreement, Acclaim Energy provides certain management, administrative and support services to the Trust, including those necessary: (a) to ensure compliance by the Trust with continuance disclosure obligations under applicable securities legislation; (b) to provide investor relations services; (c) to provide or cause to be provided to Unitholders all information to which Unitholders are entitled to under the Trust Indenture; (d) to call, hold and distribute materials including notices of meetings and information circulars in respect of all necessary meetings of Unitholders; (e) to determine the amounts payable from time to time to Unitholders; and (f) to determine the timing and terms of future offerings of Units, if any.  The Board of Directors of Acclaim Energy is required to approve all matters referred to in items (d), (e) and (f) above.

ADDITIONAL INFORMATION RESPECTING ACCLAIM ENERGY INC.

Management of Acclaim Energy

Acclaim Energy has a Board of Directors comprised of not more than nine nor less than five members, consisting currently of eight individuals.  Unitholders are entitled to elect the Board of Directors of Acclaim Energy.  In its Information Circular - Proxy Statement dated March 23, 2005, the Trust has proposed the election of eight directors by Unitholders.

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The following table sets forth certain information respecting the directors, nominees as directors and executive officers of Acclaim Energy.

Name and Municipality of Residence	Offices Held	Principal Occupation During the Past Five Years	Director Since
Robert G. Brawn, B.Sc. P.Eng. (1)(2) Calgary, Alberta	Chairman Emeritus of the Board and Director	President of 738831 Alberta Ltd. (a private investment company) since May 30, 2003. From April 20, 2001 until May 30, 2003, Chairman of Acclaim Energy and prior thereto, Chairman of Danoil Energy Ltd., a predecessor of Acclaim Energy. Mr. Brawn has more than 42 years' experience in the oil and gas industry. He is also a Director of ATB Financial, a provincially owned financial institutional; Parkland Industries Ltd., a retail oil marketing company; Forzani Group Ltd., a retail sporting goods company; the Calgary Airport Authority; Zapata Energy Corporation, an oil and gas exploration company and is Chairman and Director of Grande Cache Coal Corporation, a coal mining company, and The Van Horne Institute, a transportation policy study organization.	April 20, 2001
J. Paul Charron, B.Comm, C.A. Calgary, Alberta	President, Chief Executive Officer and Director	President and Chief Executive Officer of Acclaim Energy since October 1, 2002, Vice President and Chief Financial Officer of Ketch Energy Ltd. from April 2000 until October 1, 2002 and prior thereto held positions of Managing Director, Vice President and Director and Vice President of BMO Nesbitt Burns Inc. from May 1997 to April 2000	October 1, 2002
W. Peter Comber, MBA, C.A. (1)(4) Toronto, Ontario	Director	Managing Director of Barrantagh Investment Management Inc. ("Barrantagh") (an investment counseling firm specializing in portfolio management for individuals and small pension funds) since 1999 and prior thereto President of Newtonhouse Investment Management Ltd., a predecessor company of Barrantagh. Mr. Comber has previously served in senior corporate finance positions with two major investment banking firms, and has served as a director of a number of oil and gas companies, including Elk Point Resources Ltd., which was acquired by Acclaim Energy in January 2003.	May 29, 2003
Daryl Gilbert, P. Eng. (6) Calgary, Alberta	Director Nominee	Businessman from January 2005 and prior thereto President and Chief Executive Officer of Gilbert Laustsen Jung Associates Ltd. (an engineering consulting firm). Mr. Gilbert has been active in the western Canadian oil and gas sector for over 30 years. Mr. Gilbert is also a Director of AltaGas Income Trust (public energy facilities and services trust), Kereco Energy Ltd. (public oil and gas company).	–
Murray M. Frame, B. Sc. (Honours) Calgary, Alberta	Director Nominee	Chairman and Chief Executive Officer of Canoil Inc. (private oil and gas company) since 2002. Prior thereto President and Chief Executive Officer of Canoil Energy Corporation (private oil and gas company) from 1996-2001 and prior thereto held positions of Vice- President Exploration, Executive Vice-President and Chief Operating Officer and President and Chief Operating Officer of Inverness Petroleum Ltd. (public oil and gas company) from 1981 to 1996. Mr. Frame has 32 years of experience in the oil and gas industry.	–
Frank W. King, P.Eng. (3)(4)(5)(7) Calgary, Alberta	Director	President of Metropolitan Investment Corporation (a financial services company).	April 20, 2001

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Name and Municipality of Residence	Offices Held	Principal Occupation During the Past Five Years	Director Since
Nancy M. Laird, MBA (3)(4) Calgary, Alberta	Director	Corporate director since July 2002. Former Senior Vice President,  Marketing and Midstream of EnCana Corporation and of PanCanadian Energy Corporation, a predecessor company to EnCana Corporation, from 1997 to July 2002. Ms. Laird has over 20 years of experience in the Canadian oil and gas and technology sectors. She currently serves as a Director of the Keyera Facilities Income Fund, Enerflex Systems Ltd. and the Alberta Electric System Operator. She was formerly President of NrG Information Services Inc. and held various positions of increasing responsibility with Norcen Energy Inc., North Canadian Marketing Inc., Canpet Marketing Limited and Shell Canada Limited.	July 22, 2004
Jack C. Lee, B.A., B.Comm (1)(2)(3)(4) Calgary, Alberta	Chairman of the Board and Director	Corporate director since October 1, 2002, President and Chief Executive Officer of Acclaim Energy from April 20, 2001 until  October 1, 2002 and prior thereto President and Chief Executive Officer of Danoil Energy Ltd., a predecessor of Acclaim Energy. Mr. Lee has been involved in the start-up of a number of successful oil and gas companies. He began his career in the oil and gas industry as a Landman with Amoco Canada in 1973. He was Vice President of Land at Sceptre Resources from 1976 to 1979. In 1979 he participated in the start up of Gane Energy Ltd. (predecessor to Northstar Energy Ltd.) and was President and CEO until 1986. In 1994 he co-founded Independent Energy Inc. which was sold in 1996. He was one of the founding shareholders and executive officers of Cabos Resources Inc., which was acquired by Danoil Energy Ltd. He is currently Chairman and CEO of Independent Energy Ltd., a private oil and gas company.	April 20, 2001
R. Gregory Rich, P.Eng.(2)(3) Houston, Texas	Director	Consulting advisor to Ziff Energy Group (an energy consulting firm) since May 2003 and a Principal of Blackrock Energy Associates (an energy consulting firm) since October 2002. President and Chief Executive Officer of XPRONET Resources, Inc. (private oil and gas company) since April 1999. Prior thereto, Chairman and President of Amoco Canada Petroleum Company, Ltd. Mr. Rich has over 30 years of experience in the international oil and gas industry, most of it with Amoco Corporation. Mr. Rich has lived and worked in Canada, Azerbaijan, Gabon, the U.S.A. and Trinidad & Tobago and has had responsibility for the pursuit, capture and operation of upstream projects and opportunities worldwide.	January 27, 2004
R. Carl Smith (1)(4)(7) Calgary, Alberta	Director	Corporate director.	April 20, 2001
David J. Broshko, C.A. Calgary, Alberta	Vice President, Finance and Chief Financial Officer	Chief Financial Officer of Acclaim Energy since May 5, 2003. Prior thereto Chief Financial Officer of Paramount Resources Ltd.	–
Richard J. Tiede, P.Eng. Calgary, Alberta	Vice President, Business Development	Vice President, Business Development of Acclaim Energy since October 1, 2002. President and Chief Operating Officer of Landover Energy Inc. from January 2000 to June 2002. Manager of Engineering, Vice President, Engineering and Chief Engineer of Northrock Resources Ltd. from December 1993 until January 2000.	–

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Name and Municipality of Residence	Offices Held	Principal Occupation During the Past Five Years	Director Since
Mark P. Fitzgerald, MBA, P.Eng. Calgary, Alberta	Vice President, Operations	Vice President, Operations of Acclaim Energy since February 15, 2005, formerly VP, Engineering of Acclaim Energy since April 1, 2004. Manager, Western District of Acclaim Energy from August 2003 to March 31, 2004. Prior thereto worked in asset management, acquisitions and mergers for Dominion Energy Canada Ltd. (oil and gas company).	–
Wes Morningstar Calgary, Alberta	Vice-President, Exploration and Development	Vice-President, Exploration and Development of Acclaim Energy since August 2003. Manager, Geology and Geophysics of Acclaim Energy since October 2002. Business Unit Coordinator for the southern district for Ketch Energy Ltd., from October 2001 to October 1, 2002 and Vice-President, Exploration and Development of Magin Energy Ltd. (oil and gas company) from June 1998 to June 2001.	–
William S. Maslechko Calgary, Alberta	Secretary	Partner, Burnet, Duckworth & Palmer LLP (law firm).	–

Notes:

(1)Member of the Audit Committee.

(2)Member of the Reserves Committee.

(3)Member of the Human Resources and Compensation Committee.

(4)Member of the Governance Committee.

(5)Mr. King is a director of Wi-LAN Inc. (“Wi-LAN”). The Executive Director of the Alberta Securities Commission, Wi-LAN and certain of its directors, including Mr. King, entered into a Settlement Agreement and Undertaking in March, 1998 to resolve certain matters relating to non-compliance with applicable Alberta securities laws in connection with certain share issuances by Wi-LAN. Pursuant to the agreement, among other things, Wi-LAN undertook that, subject to certain exceptions, before it availed itself of any of the exemptions contained in the Securities Act (Alberta) for a period of one year from the date of the agreement, it would seek the permission of the Executive Director and the Wi-LAN directors undertook not to sell securities of Wi-LAN for a period of 18 months from the date of the agreement.

(6)Mr. Gilbert is a director of Globel Direct, Inc., which was subject to a cease trade order issued by the British Columbia Securities Commission on November 20, 2002 and the Alberta Securities Commission on November 22, 2002 for delay in filing financial statements. The required financial statements were filed and the cease trade orders were revoked effective December 23, 2002.

(7)Messrs. King and Smith will retire as directors at the Trust's 2005 annual meeting.

As at March 23, 2005, the directors and executive officers of Acclaim Energy, as a group, beneficially owned, directly or indirectly, Units or approximately 1.4% of the issued and outstanding Units, assuming the exercise of 557,768 Exchangeable Shares beneficially owned or controlled by two directors, which are exchangeable for an aggregate 716,728 Units as at March 23, 2005.

Share Capital of Acclaim Energy

The authorized capital of Acclaim Energy consists of an unlimited number of Acclaim Common Shares, an unlimited number of non-voting common shares, an unlimited number of preferred shares, issuable in series, and an unlimited number of exchangeable shares, issuable in series.

The following is a general description of the material rights, privileges, restrictions and conditions attaching to each class of shares.

Common Shares

Each Acclaim Common Share entitles its holder to receive notice of and to attend all meetings of shareholders of Acclaim Energy and to one vote at such meetings.  The holders of Acclaim Common Shares are, at the discretion of the Board of Directors of Acclaim Energy and subject to the rights of holders of the preferred shares and the exchangeable shares and applicable legal restrictions, entitled to receive any dividends or other distributions declared by the Board of Directors of Acclaim Energy on the Acclaim Common Shares.  The holders of Acclaim Common Shares are, subject to the rights of holders of the preferred shares and the exchangeable shares, entitled to share equally in any distribution of the assets of Acclaim Energy upon the liquidation, dissolution or winding-up of

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Acclaim Energy or other distribution of its assets among its shareholders for the purpose of winding-up its affairs. All of the issued and outstanding Acclaim Common Shares are owned by the Trust.

Non-voting Common Shares

The non-voting common shares of Acclaim Energy have the same rights, privileges, restrictions and conditions as the Acclaim Common Shares, with the exception that holders thereof are not entitled to notice of or to vote at meetings of shareholders of Acclaim Energy (except where required by applicable law).  Dividends may be declared on either the Acclaim Common Shares or the non-voting common shares of Acclaim Energy to the exclusion of the other.  No non-voting common shares have been issued.

Preferred Shares

The preferred shares rank equal to the exchangeable shares and have a priority over all common shares and non-voting common shares with respect to the payment of dividends and distributions on a liquidation, dissolution or winding up of Acclaim Energy.  The Board of Directors of Acclaim Energy has the authority to fix the number and particular rights, privileges, restrictions and conditions attaching to each series of the preferred shares.

The Board of Directors of Acclaim Energy authorized the creation of the first series of preferred shares of Acclaim Energy designated as the Acclaim Preferred Shares, which are limited in number to 2,500,000 shares.  The Acclaim Energy Preferred Shares have the following attributes: (a) a stated value of $4.86 per share; (b) a 14% annual cumulative dividend; and (c) are convertible on a one-for-one basis for the Acclaim Exchangeable Shares at any time at the option of the holder or Acclaim Energy following receipt of all necessary regulatory approvals for the issuance of the Units underlying the Acclaim Exchangeable Shares.

The 705,038 Acclaim Preferred Shares issued in connection with the acquisition of all of the issued and outstanding shares of Acclaim Management have been converted into Acclaim Exchangeable Shares and there are no Acclaim Preferred Shares outstanding.

Exchangeable Shares

The exchangeable shares rank equal to the preferred shares and have a priority over all common shares and non-voting common shares with respect to the payment of dividends and distributions on a liquidation, dissolution or winding-up of Acclaim Energy.  The Board of Directors of Acclaim Energy has the authority to fix the number and particular rights, privileges, restrictions and conditions attaching to each series of the exchangeable shares.

The first series of exchangeable shares of Acclaim Energy designated as the Acclaim Exchangeable Shares are limited in number to 2,750,000 shares.  Each Acclaim Exchangeable Share is exchangeable on a one-for-one basis for Units, subject to adjustments for distributions.

MARKET FOR SECURITIES

The Units, the 11% Debentures and the 8% Debentures are listed for trading on the TSX under the symbols “AE.UN”, “AE.DB” and “AE.DB.A” respectively.

The following table sets forth the closing price range and trading volumes of the Units (adjusted to give effect to the Consolidation) as reported by the TSX for the periods indicated.

Period	High ($)	Low ($)	Volume (000’s)
2003
January	10.50	9.98	7,458
February	10.88	10.05	7,576
March	10.98	10.00	3,864
April	10.48	9.63	5,953
May	10.50	9.80	8,793
June	11.55	10.45	8,444

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Period	High ($)	Low ($)	Volume (000’s)
July	11.61	10.50	7,207
August	11.31	11.01	5,045
September	11.68	10.87	6,414
October	11.41	11.00	6,385
November	11.45	11.14	5,904
December	12.08	11.15	5,278
2004
January	12.27	11.66	8,419
February	12.18	11.07	7,023
March	12.36	11.36	5,785
April	12.98	12.21	5,380
May	13.20	12.21	6,346
June	13.18	12.36	8,057
July	14.55	12.96	8,110
August	14.74	13.79	6,530
September	15.17	13.60	10,286
October	15.60	13.88	11,767
November	14.88	13.50	9,286
December	14.84	13.85	7,239

The following table sets forth the closing price range and trading volume of the 11% Debentures ("AE.DB") as reported by the TSX for the periods indicated.

Period	High ($)	Low ($)	Volume (000's)
2003
January	107.50	102.00	28.9
February	112.00	104.50	19.7
March	112.00	103.00	23.0
April	109.00	102.00	8.6
May	109.50	106.00	6.5
June	117.90	109.49	12.0
July	115.50	112.00	4.6
August	120.00	112.05	17.4
September	118.27	112.50	14.5
October	117.25	113.51	2.8
November	116.50	114.00	7.5
December	122.95	114.00	12.5

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Period	High ($)	Low ($)	Volume (000’s)
2004
January	125.01	119.51	16.4
February	123.50	111.17	11.9
March	126.25	120.00	10.6
April	131.89	120.01	7.6
May	134.00	124.59	15.2
June	133.50	125.00	11.2
July	145.22	134.96	24.5
August	150.00	140.00	5.3
September	151.80	142.68	3.9
October	157.98	144.00	1.6
November	151.00	140.00	2.8
December	150.50	130.23	2.0

The following table sets forth the closing price range and trading volume of the 8% Debentures (“AE.DB.A”) as reported by the TSX for the periods indicated.

Period	High ($)	Low ($)	Volume (000's)
2004
June (from June 15)	104.99	100.60	22.3
July	107.50	104.50	64.5
August	108.60	105.00	16.7
September	110.25	105.00	66.6
October	114.16	106.00	77.8
November	110.00	105.01	10.5
December	111.90	106.27	35.9

DISTRIBUTIONS

Policy

The Trust makes cash distributions in amounts equal to all of the interest, dividend and other income of the Trust, net of the Trust’s administrative expenses.  In addition, Unitholders may, at the discretion of the Board of Directors of Acclaim Energy, receive distributions in respect of repayments of principal made by Acclaim Energy to the Trust on the Acclaim Notes. Acclaim Energy endeavors to retain approximately 25 to 30% of its cash flow over time to fund capital expenditures and to distribute the balance to the Trust. The actual percentage retained by Acclaim Energy is subject to the discretion of the board of directors of Acclaim Energy and will vary from month to month depending on, among other things, the current and anticipated commodity price environment.

Cash distributions are made on or about the 20th day of each month to Unitholders of record on the immediately preceding distribution record date.  The Trust’s current policy is to distribute $0.1625 per Unit per month ($1.95 per Unit per annum).

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Distribution Record

The following table sets forth the per Unit amount of monthly cash distributions (adjusted to give effect to the Consolidation) paid by the Trust since the completion of the Danoil Merger.

	Distribution Per Unit (2)
2001
September (1)	$	0.20
October	$	0.20
November	$	0.125
December	$	0.125
2002
January	$	0.125
February	$	0.125
March	$	0.125
April	$	0.125
May	$	0.15
June	$	0.15
July	$	0.15
August	$	0.15
September	$	0.15
October	$	0.1625
November	$	0.1625
December	$	0.1625
2003
January	$	0.1625
February	$	0.1625
March	$	0.1625
April	$	0.1625
May	$	0.1625
June	$	0.1625
July	$	0.1625
August	$	0.1625
September	$	0.1625
October	$	0.1625
November	$	0.1625
December	$	0.1625
2004
January	$	0.1625
February	$	0.1625
March	$	0.1625
April	$	0.1625
May	$	0.1625
June	$	0.1625
July	$	0.1625
August	$	0.1625
September	$	0.1625
October	$	0.1625
November	$	0.1625
December	$	0.1625

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	Distribution Per Unit (2)
2005
January	$	0.1625
February	$	0.1625
March	$	0.1625	(3)

Notes:

(1)First cash distribution of the Trust following the completion of the Danoil Merger.

(2)Monthly information refers to the month in which the record date for the relevant distribution occurs, with the distribution being paid in the following month.

(3)The Trust announced on March 18, 2005 that the next monthly distribution of distributable cash of $0.1625 per Unit will be paid on April 20, 2005 to Unitholders of record on March 31, 2005.

RISK FACTORS

The following is a summary of certain risk factors relating to the business of the Trust and the Operating Entities.  The following information is a summary only of certain risk factors and is qualified in its entirety by reference to, and must be read in conjunction with, the detailed information appearing elsewhere in this annual information form.  Unitholders and potential Unitholders should consider carefully the information contained herein and, in particular, the following risk factors.

General

The Trust is a limited purpose trust that is entirely dependent upon the operations and assets of the Operating Entities through its ownership, directly and indirectly, of securities of Operating Entities including the Acclaim Common Shares, the Acclaim Notes and the NPI.  Accordingly, the Trust is dependent upon the ability of the Operating Entities to meet their interest, principal dividend and other distribution obligations on the securities of the Operating Entities and the NPI.  The Operating Entities’ income is received from the production of oil and natural gas from the Operating Entities’ Canadian resource properties and is susceptible to the risks and uncertainties associated with the oil and natural gas industry generally.  If the oil and natural gas reserves associated with the Operating Entities’ resource properties are not supplemented through additional development or the acquisition of additional oil and natural gas properties, the ability of the Operating Entities to meet their obligations to the Trust and the Trust’s ability to pay distributions to Unitholders may be adversely affected.

Possible Failure to Realize Anticipated Benefits of Acquisitions

Since October 2002, the Trust has completed a number of acquisitions and anticipates making additional acquisitions in the future to strengthen its position in the oil and natural gas industry and to create the opportunity to realize certain benefits.  Achieving the benefits of completed and future acquisitions depends in part on successfully consolidating functions and integrating operations, procedures and personnel in a timely and efficient manner, as well as the Trust’s and Acclaim Energy’s ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of Acclaim Energy.  The integration of acquired businesses requires the dedication of substantial management effort, time and resources, which may divert management’s focus, and resources from other strategic opportunities and from operational matters.  The integration process may result in the loss of key employees and the disruption of ongoing business, customer and employee relationships that may adversely affect the Trust’s ability to achieve the anticipated benefits of past and future acquisitions.

Exploitation and Development

Exploitation and development risks are due to the uncertain results of searching for and producing oil and natural gas using imperfect scientific methods.  These risks are mitigated by using experienced staff, focusing exploitation efforts in areas in which the Operating Entities have existing knowledge and expertise or access to such expertise, using up-to-date technology to enhance methods and controlling costs to maximize returns.

Reserve Estimates

The Reserve and recovery information contained in the GLJ Report are only estimates and the actual production and ultimate Reserves from the properties may be greater or less than the estimates prepared. In addition, Probable Reserve estimates for properties may

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require revision based on the actual development strategies employed to prove such Reserves.  Estimated Reserves may also be affected by changes in oil and natural gas prices.  Declines in the reserves of the Operating Entities that are not offset by the acquisition or development of additional Reserves may reduce the underlying value of Units to Unitholders.

Volatility of Oil and Natural Gas Prices

The price of oil and natural gas will fluctuate throughout the life of the Operating Entities’ reserves and price and demand are factors largely beyond their control.  Such fluctuations will have a positive or negative effect on the revenue to be received.  Such fluctuations will also have an effect on the acquisition costs of any future oil and natural gas properties that the Operating Entities may acquire.  As well, cash distributions from the Trust will be highly sensitive to the prevailing price of crude oil and natural gas.

Oil and natural gas prices have fluctuated widely during recent years and are subject to fluctuations in response to relatively minor changes in supply, demand, market uncertainty and other factors that are beyond the Trust’s control. These factors include, but are not limited to, worldwide political instability, foreign supply of oil and natural gas, the level of consumer product demand, government regulations and taxes, the price and availability of alternative fuels and the overall economic environment.

The Trust uses financial derivative instruments and other hedging mechanisms to try to limit a portion of the adverse effects resulting from changes in natural gas and oil commodity prices. In hedging its commodity price exposure, the Trust attempts whenever possible to use financial instruments that protect the Trust against downward price movements while still providing some variable level of participation in the event that prices increase. To the extent the Trust hedges its commodity price exposure, the Trust recognizes that depending on the type of structure used, it may forego some or all of the benefit that it would have received if commodity prices increase. The Trust recognizes that this potential opportunity cost is a trade-off for limiting its exposure downward price movements. In addition to the potential of experiencing an opportunity cost, other potential costs or losses associated with hedging could include situations where the other party to a hedge does not perform its obligations under the hedge agreement, the hedge is imperfect or the Trust’s hedging policies and procedures are not followed. Furthermore, the Trust cannot guarantee that such hedging transactions will fully offset the risks of changes in commodity prices.  The Trust’s commodity hedging activities could expose it to losses. Such losses could occur under various circumstances.

In addition, the Trust regularly assesses the carrying value of its assets in accordance with Canadian generally accepted accounting principles under the full cost method. If oil and natural gas prices become depressed or decline, the carrying value of the Trust’s assets could be subject to downward revision.

Marketing

The marketability and price of oil and natural gas that may be acquired or discovered by the Operating Entities will be affected by numerous factors beyond their control. These factors include demand for oil and natural gas, market fluctuations, the proximity and capacity of oil and natural gas pipelines and processing equipment and government regulations, including regulations relating to environmental protection, royalties, allowable production, pricing, importing and exporting of oil and natural gas.

Capital Investment

The timing and amount of capital expenditures directly affect the amount of income for distribution to the Unitholders.  Distributions may be reduced, or even eliminated, at times when significant capital or other expenditures are made.

Operational Matters

The operation of oil and gas wells involves a number of operating and natural hazards, which may result in blowouts, environmental damage and other unexpected or dangerous conditions resulting in damage to the Operating Entities and possible liability to third parties.  The Operating Entities maintain liability insurance, where available, in amounts consistent with industry standards.  Business interruption insurance may also be purchased for selected facilities, to the extent that such insurance is available.  The Operating Entities may become liable for damages arising from such events against which they cannot insure or against which they may elect not to insure because of high premium costs or other reasons.  Costs incurred to repair such damage or pay such liabilities will have an adverse effect on the Trust’s financial condition and therefore on the distributable income to be distributed to holders of Units.  See “Risk Factors – Contingency”.

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Continuing production from a property, and to some extent the marketing of production therefrom, are largely dependent upon the ability of the operator of the property.  To the extent the operator fails to perform these functions properly, revenue may be reduced.  Payments from production generally flow through the operator and there is a risk of delay and additional expense in receiving such revenues if the operator becomes insolvent.  To the extent the Operating Entities are not the operators of their oil and natural gas properties, the Operating Entities will be dependent on such operators for the timing of activities related to such properties and will be largely unable to direct or control the activities of the operators.

Although title reviews are generally conducted in accordance with industry standards, such reviews do not guarantee or certify that a defect in the chain of title may not arise to defeat the claim of an Operating Entity to certain properties.  A reduction of distributable income could result in such circumstances.

An increase in operating costs or a decline in production levels could have a material adverse effect on the Trust’s results of operations and financial condition and, therefore, could reduce distributions to Unitholders as well as affect the market price of the Units.

Higher operating costs for the Operating Entities’ properties will directly decrease the amount of cash flow received by the Trust and, therefore, may reduce distributions to Unitholders. Electricity, chemicals, supplies, reclamation and abandonment and labor costs are a few of the operating costs that are susceptible to material fluctuation.

The level of production from the Operating Entities’ existing properties may decline at rates greater than anticipated due to unforeseen circumstances, many of which are beyond the Operating Entities’ control. A significant decline in production could result in materially lower revenues and cash flow and, therefore, could reduce the amount available for distributions to Unitholders.

Contingency

On December 12, 2004, a gas release occurred at an Acclaim Energy operated well site west of the city of Edmonton, Alberta. Acclaim Energy’s emergency response plan was engaged and the resulting fire was extinguished on January 10, 2005.  The well was not producing at the time of the incident and has not had an impact on production in the area.

Acclaim Energy carries control of well and general liability insurance in the amount of $10 million and $50 million less applicable deductibles respectively.  Total costs associated with the incident are currently estimated to approximate $45 million including the cost of drilling two relief wells and subsequent abandonment and reclamation of the site.  Acclaim is currently working through the claims process with its insurers.  At December 31, 2004, costs approximating $28 million were included in the Trust’s consolidated financial statements as accrued liabilities with an offsetting accrual to accounts receivable for anticipated insurance recoveries.

As the reclamation and claim process is ongoing the financial impact of the incident on Acclaim is currently not determinable.

See “Risk Factors – Operational Matters”.

Variations in Foreign Currency Exchange Rates

Fluctuations in foreign currency exchange rates could adversely affect the Operating Entities’ business, and could affect the market price of the Units as well as distributions to Unitholders. The price that the Operating Entities receive for a majority of their oil and natural gas is based on United States dollar denominated benchmarks, and therefore the price received in Canadian dollars is affected by the exchange rate between the two currencies. A material increase in the value of the Canadian dollar relative to the United States dollar may negatively impact net production revenue by decreasing the Canadian dollars received for a given United States dollar price. The Trust could be subject to unfavorable price changes to the extent that the Trust has engaged, or in the future engages, in risk management activities related to foreign exchange rates, through entry into forward foreign exchange contracts or otherwise.

The Trust’s operational results and financial condition are dependent on the prices received by the Operating Entities for oil and natural gas production.  Oil and natural gas prices have fluctuated widely during recent years and are determined by supply and demand factors, including weather and general economic conditions as well as economic, political and other conditions in other oil and natural gas regions, all of which are beyond the Trust’s control.  Any decline in oil and natural gas prices could have an adverse effect on the Trust’s financial condition and therefore on the distributable income to be distributed to holders of Units as well as on the future value of the Trust’s Reserves as determined by independent evaluators.

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Environmental Concerns

The oil and natural gas industry is subject to environmental regulation pursuant to local, provincial and federal legislation. A breach of such legislation may result in the imposition of fines or issuance of clean up orders in respect of the Operating Entities or their oil and gas properties.  Such legislation may be changed to impose higher standards and potentially more costly obligations on the Operating Entities. See also “Business and Properties – Industry Conditions – Environmental Regulation”.

Kyoto Protocol

Canada is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto Protocol established thereunder to set legally binding targets to reduce nationwide emissions of carbon dioxide, methane, nitrous oxide and other so-called “greenhouse gases”.  The Operating Entities’ exploration and production facilities and other operations and activities emit a small amount of greenhouse gases, which may subject the Operating Entities to legislation regulating emissions of greenhouse gases.  The Government of Canada has put forward a Climate Change Plan for Canada which suggests further legislation will set greenhouse gases emission reduction requirements for various industrial activities, including oil and gas exploration and production.  Future federal legislation, together with provincial emission reduction requirements, such as those proposed in Alberta’s Bill 32: Climate Change and Emissions Management, may require the reduction of emissions or emissions intensity of the Operating Entities’ operations and facilities.  The direct or indirect costs of these regulations may adversely affect the Operating Entities’ business.

Debt Service

Amounts paid in respect of interest and principal on debt incurred in respect of the Operating Entities’ properties will reduce distributable income.  Variations in interest rates and scheduled principal repayments could result in significant changes in the amount required to be applied to debt service before payment of any amounts to the Trust.  Certain covenants of the agreements with Acclaim Energy’s lenders may also limit distributions to the Trust.  Although Acclaim Energy believes its credit facilities will be sufficient for Acclaim Energy’s immediate requirements, there can be no assurance that the amount will be adequate for the financial obligations of the Operating Entities or that additional funds can be obtained.

Acclaim Energy’s principal lenders have security over substantially all of the assets of the Operating Entities.  If the Operating Entities become unable to pay their debt service charges or otherwise commit an event of default such as bankruptcy, the lenders may foreclose on or sell the Operating Entities’ oil and gas properties free from or together with the NPI.

Structural Subordination of the Units

In the event of a bankruptcy, liquidation or reorganization of Acclaim Energy or any of the other Operating Entities, holders of their indebtedness and their trade creditors will generally be entitled to payment of their claims from the assets of Acclaim Energy and the other Operating Entities, before any assets are made available for distribution to the Trust (including pursuant to the Acclaim Notes). The Units are therefore effectively junior to the bank indebtedness and most other liabilities (including trade payables) of Acclaim Energy and the other Operating Entities.  Neither Acclaim Energy nor any of the other Operating Entities is limited in their ability to incur secured or unsecured indebtedness.

Delay in Cash Receipts

In addition to the usual delays in payment by purchasers of oil and natural gas to the operators of oil and gas properties, and by the operator to the Operating Entities, payments between any of such parties may also be delayed by restrictions imposed by lenders, delays in the sale or delivery of products, delays in the connection of wells to a gathering system, blowouts or other accidents, recovery by the operator of expenses incurred in the operation of oil and gas properties or the establishment by the operator of reserves for such expenses.

Reliance on Senior Management and Key Personnel

Unitholders are dependent on the senior management and Board of Directors of Acclaim Energy in respect of all aspects of the management of matters relating to the Operating Entities and their properties and all material matters relating to the Trust. The success of the Trust’s operations is largely dependent on the skills and expertise of senior management and other key personnel.  The continued success of the Trust will be dependent on its ability to retain or recruit such personnel.

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Depletion of Reserves

The Trust has certain unique attributes that differentiate it from other oil and gas industry participants.  Distributions of distributable income in respect of the Operating Entities’ oil and gas properties, absent commodity price increases or cost effective acquisition and development activities, will decline over time in a manner consistent with declining production from typical oil, natural gas and natural gas liquids reserves.  The Operating Entities will not be reinvesting cash flow in the same manner as other industry participants.  Accordingly, absent capital injections, the Operating Entities’ initial production levels and reserves will decline.

The Operating Entities’ future oil and natural gas reserves and production, and therefore their cash flows, will be highly dependent on the Operating Entities’ success in exploiting their reserve base and acquiring additional reserves.  Without reserve additions through acquisition or development activities, the Operating Entities’ reserves and production will decline over time as reserves are exploited.

To the extent that external sources of capital, including the issuance of additional Units become limited or unavailable, the Operating Entities’ ability to make the necessary capital investments to maintain or expand their oil and natural gas reserves will be impaired.  To the extent that the Operating Entities are required to use cash flow to finance capital expenditures or property acquisitions, the level of distributable income will be reduced.

There can be no assurance that the Operating Entities will be successful in developing or acquiring additional reserves on terms that meet the Trust’s investment objectives.

Aboriginal Land Claims

The economic impact on the Trust of claims of aboriginal title is unknown. Aboriginal people have claimed aboriginal title and rights to a substantial portion of western Canada. The Trust is unable to assess the effect, if any, that any such claim would have on the Operating Entities’ business and operations.

Additional Financing

To the extent that external sources of capital, including the issuance of additional Units, become limited or unavailable, the Trust’s and the Operating Entities’ ability to make the necessary capital investments to maintain or expand their oil and gas reserves will be impaired.  To the extent that the Trust or the Operating Entities are required to use cash flow to finance capital expenditures or property acquisitions, the level of distributable income will be reduced.

Competition

There is strong competition relating to all aspects of the oil and gas industry.  The Trust and the Operating Entities actively compete for reserve acquisitions and skilled industry personnel with a substantial number of other oil and gas companies, many of which have significantly greater financial and other resources than the Trust or the Operating Entities.

Changes in Legislation

There can be no assurance that income tax laws and government incentive programs relating to the oil and gas industry, such as the status of mutual fund trusts and the resource allowance, will not be changed in a manner that adversely affects Unitholders.

Investment Eligibility; Mutual Fund Trust Status

If the Trust ceases to qualify as a mutual fund trust, the Units will cease to be qualified investments for RRSPs, RRIFs, DPSPs and RESPs (“Deferred Plans”). Where at the end of any month a Deferred Plan holds Units that are not qualified investments, the Deferred Plan must, in respect of that month, pay a tax under Part XI.1 of the Tax Act equal to 1% of the fair market value of the Units at the time such Units were acquired by the Deferred Plan.  In addition, where a trust governed by an RRSP or RRIF holds Units that are not qualified investments, the trust will become taxable on its income attributable to the Units while they are not qualified investments, including the full amount of any capital gain realized on a disposition of Units while they are not qualified investments. Where a trust governed by an RESP holds Units that are not qualified investments, the plan’s registration may be revoked.  In addition, if the Trust were to cease to qualify as a mutual fund trust:

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•If proposed changes to the Tax Act are not enacted, Units would become foreign property for registered pension plans.

•The Trust would be taxed on certain types of income distributed to Unitholders, including income generated by the royalty held by the Trust.  Payment of this tax may have adverse consequences for some Unitholders, particularly Unitholders that are not residents of Canada and residents of Canada that are otherwise exempt from Canadian income tax.

•Units held by Unitholders that are not residents of Canada would become taxable Canadian property.  These non-resident holders would be subject to Canadian income tax on any gains realized on a disposition of Units held by them.

Redemption of Units

It is anticipated that the redemption right associated with Units will not be the primary mechanism for holders of Units to dispose of their Units.  Danoil Notes (or Redemption Notes), which may be distributed in specie to Unitholders in connection with a redemption, will not be listed on any stock exchange and no market is expected to develop in such Danoil Notes (or Redemption Notes).  Danoil Notes (or Redemption Notes) will not be qualified investments for trusts governed by Deferred Plans.

Nature of Units

The Units do not represent a traditional investment in the oil and natural gas sector and should not be viewed by investors as shares in Acclaim Energy or any other Operating Entities or as a direct investment in the Operating Entities’ business or assets.  The Units represent a fractional interest in the Trust.  As holders of Units, Unitholders do not have the statutory rights normally associated with ownership of shares of a corporation including, for example, the right to bring “oppression” or “derivative” actions.

The Trust’s primary assets are the Acclaim Notes, the NPI and the direct and indirect ownership of common shares of the Operating Entities.  The price per Unit is a function of the anticipated distributable income, the oil and gas properties of the Operating Entities and Acclaim Energy’s ability to effect long-term growth in the value of the Trust.  The market price of Units will be sensitive to a variety of market conditions including, but not limited to, interest rates and the ability of the Trust to acquire suitable oil and natural gas properties.  Changes in market conditions may adversely affect the trading price of Units.

The Units are not “deposits” within the meaning of the Canada Deposit Insurance Corporation Act (Canada) and are not insured under the provisions of that Act or any other legislation.  Furthermore, the Trust is not a trust company and, accordingly, is not registered under any trust and loan company legislation, as it does not carry on or intend to carry on the business of a trust company.

Unitholder Limited Liability

The Trust Indenture provides that no Unitholder will be subject to any liability in connection with the Trust or its obligations or affairs and, in the event that a court determines that Unitholders are subject to any such liabilities, the liabilities will be enforceable only against, and will be satisfied only out of, the Unitholder’s share of the Trust’s assets.

The Trust Indenture provides that all written instruments signed by or on behalf of the Trust must contain a provision to the effect that such obligation will not be binding upon Unitholders personally.  Personal liability may also arise in respect of claims against the Trust that do not arise under contracts, including claims in tort, claims for taxes and possibly certain other statutory liabilities.  The possibility of any personal liability of this nature arising is considered unlikely by the Trust.

The operations of the Trust will be conducted, upon the advice of counsel, in such a way and in such jurisdictions as to avoid as far as possible any material risk of liability on Unitholders for claims against the Trust.

Unitholders will have the benefit of Income Trusts Liability Act (Alberta) which provides that a unitholder will not be, as a beneficiary, liable for any act, default, obligation or liability of the Trustee of an Alberta income trust that arises after the legislation came into force (July 1, 2004).

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Restrictions on Non Resident Ownership

The Trust Indenture restricts the ownership of Units by Unitholders who are non residents of Canada for the purposes of the Tax Act. If the Trustee becomes aware that the beneficial owners of 49% of the Units are or may be non residents or that such a situation is imminent, the Trustee may not accept subscriptions for or issue or register transfers of Units to non residents and if the Trustee determines that a majority of the Units are held by non residents, the Trustee may require non resident Unitholders to sell all or a specified portion of their Units within a specified period of not less than 60 days.  See “Additional Information Respecting Acclaim Energy Trust – Non Resident Unitholders”.

Dependence on Operating Entities

The Trust is an open-ended energy trust that is entirely dependent upon the operations and assets of the Operating Entities through the direct and indirect ownership of the Operating Entities’ common shares, the Acclaim Notes and the NPI.  Accordingly, the cash distributions to Unitholders will be dependent upon the ability of the Operating Entities to pay their interest obligations under the Acclaim Notes, to declare and pay dividends on the Operating Entities’ common shares and to make payments under the NPI.

Regulatory Matters

The Operating Entities’ operations are subject to a variety of federal, provincial laws and regulations, including laws and regulations relating to the protection of the environment.

Return of Capital

Units will have no value when reserves from the Operating Entities’ properties can no longer be economically produced and, as a result, cash distributions do not represent a “yield” in the traditional sense as they represent both return of capital and return on investment.

Potential Conflicts of Interest

The directors and officers of Acclaim Energy are engaged in and will continue to engage in other activities in the oil and natural gas industry and, as a result of these and other activities, the directors and officers of Acclaim Energy may become subject to conflicts of interest.  The ABCA provides that in the event that a director has an interest in a contract or proposed contract or agreement, the director shall disclose his interest in such contract or agreement and shall refrain from voting on any matter in respect of such contract or agreement unless otherwise provided under the ABCA.  To the extent that conflicts of interest arise, such conflicts will be resolved in accordance with the provisions of the ABCA.

Additional Risk Factors

The business of the Operating Entities is subject to other risks and matters that are outside of their control.  See “Business and Properties – Industry Conditions”.

INTEREST OF EXPERTS

GLJ has prepared the GLJ Report.  As at the date hereof, neither GLJ nor any of its directors or officers owns, directly or indirectly, any of the Units.

LEGAL PROCEEDINGS

There are no outstanding legal proceedings material to the Trust to which the Trust or Acclaim Energy is a party or in respect of which any of their respective properties are subject, nor are there any such proceedings known to be contemplated.

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for the Units and Convertible Debentures is Computershare Trust Company of Canada at its principal offices in Calgary, Alberta and Toronto, Ontario.

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INTEREST OF INSIDERS IN MATERIAL TRANSACTIONS

To the knowledge of the directors and executive officers of Acclaim Energy, there were no material interests, direct or indirect, of directors or senior officers of Acclaim Energy, nominees for director of Acclaim Energy, any Unitholder who beneficially owns more than 10% of the Units of the Trust, or any known associate or affiliate of such persons, in any transaction during 2004 or in any proposed transaction which has materially affected or would materially affect the Trust or Acclaim Energy other than as disclosed herein.

MATERIAL CONTRACTS

The only material contracts in effect as of the date hereof entered into by the Trust or Acclaim Energy within the most recently completed financial year, or before the most recently completed financial year but that are still in effect, other than in the ordinary course of business, is the Trust Indenture, which is summarized under the heading “Additional Information Respecting Acclaim Energy Trust”.

ADDITIONAL INFORMATION

Additional information including remuneration and indebtedness of directors and officers, principal holders of securities and securities authorized for issuance under equity compensation plans is contained in the Information Circular – Proxy Statement of the Trust dated March 23, 2005 and additional financial information is provided in the financial statements and management’s discussion and analysis of the Trust for the year ended December 31, 2004.

For additional copies of the Annual Information Form and the materials listed in the preceding paragraphs please contact:

Acclaim Energy Trust
c/o Acclaim Energy Inc.
1900, 255 – 5th Avenue S.W.
Calgary, Alberta  T2P 3G6

Phone: (403) 539-6300
Fax:     (403) 539-6499
Toll Free:  1-877-539-6300

Copies of the materials listed in the preceding paragraphs, together with additional information relating to the Trust may also be accessed through the SEDAR website at www.sedar.com or through the Trust’s website at www.acclaimtrust.com.

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GLOSSARY OF TERMS

“ABCA” means the Business Corporations Act (Alberta), R.S.A. 2000, c. B-9, as amended, including the regulations promulgated thereunder;

“Acclaim Common Shares” means the common shares of Acclaim Energy;

“Acclaim Energy” means Acclaim Energy Inc., a corporation incorporated under the ABCA, and, except where the context otherwise requires, includes the other Operating Entities;

“Acclaim Exchangeable Shares” means the exchangeable shares, series 1 of Acclaim Energy;

“Acclaim LP” means Acclaim Limited Partnership, an indirect wholly owned subsidiary of the Trust formed under the laws of the Province of Alberta;

“Acclaim Notes” means, collectively, the Danoil Notes, the Exodus Notes, the Ketch Energy Notes and the Elk Point Notes;

“Acclaim Preferred Shares” means the 14% cumulative, redeemable, retractable, exchangeable preferred shares, series 1 of Acclaim Energy;

“ACT” means Acclaim Commercial Trust, an open-end unincorporated trust governed by the laws of Alberta;

“ACT Notes” means the unsecured subordinated notes of ACT issued in connection with the ChevronTexaco Acquisition;

“ACT Units” means trust units of ACT;

“Administration Agreement” means the administration agreement dated April 20, 2001 between Acclaim Energy and the Trust, pursuant to which Acclaim Energy provides administration services to the Trust;

“ARTC” means Alberta Royalty Tax Credit;

“Assets” means the fee simple, working, royalty or other interests of Acclaim Energy in any petroleum and natural gas rights, tangibles and miscellaneous interests and other assets and properties, including, without limitation, assets and properties which may be acquired by Acclaim Energy from time to time;

“Burmis Assets” means the oil and gas assets of Elk Point acquired by Burmis Energy Inc. from Elk Point as part of the Elk Point Arrangement;

“CBCA” means the Canada Business Corporation Act, R.S.C. 1985, c. C-44, as amended, including the regulations promulgated thereunder;

“CDS” means The Canadian Depository for Securities Limited;

“Chevron Canada” means, collectively, Chevron Canada Limited and Chevron Canada Resources, as vendor of the Chevron Properties;

“ChevronTexaco Acquisition” means the acquisition of the ChevronTexaco Properties by the Trust as more particularly described under the heading “Business and Properties – Significant Transactions and Recent Developments – CheveronTexaco Acquisition”;

“ChevronTexaco Properties” means the interests in oil and natural gas reserves and associated facilities located in Alberta, British Columbia, Saskatchewan and Manitoba acquired by the Trust pursuant to the ChevronTexaco Acquisition as more particularly described under the heading “Business and Properties - Significant Transactions and Recent Developments – CheveronTexaco Acquisition”;

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“Consolidation” means the consolidation of the Units on a one for 2.5 basis effective May 31, 2003 as more particularly described under “Significant Transactions and Recent Developments – Consolidation of Units”;

“Constant prices and costs” means prices and costs used in an estimate that are:

(a)Acclaim Energy’s prices and costs as at the effective date of the estimation, held constant throughout the estimated lives of the properties to which the estimate applies; and

(b)if, and only to the extent that, there are fixed or presently determinable future prices or costs to which Acclaim Energy is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in paragraph (a).

“Convertible Debentures” means, collectively, the 8% Debentures and the 11% Debentures;

“8% Debentures” means 8% convertible extendible unsecured subordinated debentures of the Trust;

“11% Debentures” means the 11% convertible extendible unsecured subordinated debentures of the Trust;

“Danoil” means Danoil Energy Ltd., a predecessor corporation of Acclaim Energy, incorporated under the ABCA;

“Danoil Merger” means the transaction described under the heading “Business and Properties – Significant Transactions – Danoil Merger”;

“Danoil Notes” means the 12% unsecured subordinated notes of Acclaim Energy issued in connection with the Danoil Merger;

“Development costs” means costs incurred to obtain access to reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas from reserves. More specifically, development costs, including applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(a)gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground draining, road building, and relocating public roads, gas lines and power lines, pumping equipment and wellhead assembly;

(b)drill and equip development wells, development type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment and wellhead assembly;

(c)acquire, construct and install production facilities such as flow lines, separators, treaters, heaters, manifolds, measuring devices and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and

(d)provide improved recovery systems.

“Developed Non-Producing Reserves” are those Reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of Production is unknown.

“Developed Producing Reserves” are those Reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of Production must be known with reasonable certainly.

“Developed Reserves” are those Reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the Reserves on Production.

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“Development well” means a well drilled inside the established limits of an oil and gas reservoir, or in close proximity to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive.

“Economic Assumptions” are the prices and costs used in the estimate, namely:

(a)constant prices and costs as at the last day of Acclaim Energy’s financial year; and

(b)forecast prices and costs.

“Elk Point” means Elk Point Resources Inc., a predecessor corporation of Acclaim Energy West Inc., incorporated under the CBCA;

“Elk Point Arrangement” means the business combination involving the Trust, Acclaim Energy, Elk Point and Burmis Energy Inc. completed on January 28, 2003 by way of plan of arrangement under the CBCA pursuant to which, among other things, the Trust indirectly acquired all of the issued and outstanding common shares of Elk Point, the United States assets and certain minor Alberta properties of Elk Point were acquired by Burmis Energy Inc. and the shares of Burmis Energy Inc. were distributed to the former holders of common shares of Elk Point;

“Elk Point Notes” means the 12% unsecured subordinated notes of Acclaim Energy West Inc., a wholly-owned subsidiary of Acclaim Energy, issued in connection with Elk Point Arrangement;

“Established Reserves” means proved reserves plus risked (50%) probable reserves, with “proved reserves” and “probable reserves” having the meanings ascribed to them under former National Policy Statement 2-B of the Canadian Securities Administrators;

“Exodus” means Exodus Energy Ltd., a predecessor corporation of Acclaim Energy, incorporated under the ABCA and acquired by Acclaim Energy on December 19, 2003 pursuant to the Exodus Acquisition;

“Exodus Acquisition” means the acquisition by Acclaim Energy of all of the issued and outstanding shares in the capital of Exodus on December 19, 2003;

“Exodus Notes” means the 12% unsecured subordinated notes of Acclaim Energy issued in connection with the Exodus Acquisition;

“Exploration costs” means costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects that may contain oil and gas reserves, including costs of drilling exploratory wells and exploratory type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property and after acquiring the property. Exploration costs, which include applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(a)costs of topographical, geochemical, geological and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews and others conducting those studies;

(b)costs of carrying and retaining unproved properties, such as delay rentals, taxes (other than income and capital taxes) on properties, legal costs for title defence, and the maintenance of land and lease records;

(c)dry hole contributions and bottom hole contributions;

(d)costs of drilling and equipping exploratory wells; and

(e)costs of drilling exploratory type stratigraphic test wells.

“Exploration well” means a well that is not a development well, a service well or a stratigraphic test well.

“ExploreCo Assets” means certain growth assets of Ketch Energy acquired by Ketch Resources Ltd. from Ketch Energy as part of the Ketch Energy Arrangement;

“Forecast Prices and Costs” means future prices and costs that are:

49

(a)generally acceptable as being a reasonable outlook of the future; and

(b)if and only to the extent that, there are fixed or presently determinable future prices or costs to which Acclaim Energy is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in paragraph (a).

“Future income tax expenses” means future income tax expenses estimated (generally, year-by-year):

(a)making appropriate allocations of estimated unclaimed costs and losses carried forward for tax purposes, between oil and gas activities and other business activities;

(b)without deducting estimated future costs (for example, Crown royalties) that are not deductible in computing taxable income;

(c)taking into account estimated tax credits and allowances (for example, royalty tax credits);

(d)applying to the future pre-tax net cash flows relating to Acclaim Energy’s oil and gas activities the appropriate year-end statutory rates, taking into account future tax rates already legislated.

“Gilby/Willesden Green Acquisition” means the acquisition of the Gilby/Willesden Green Properties by Acclaim Energy as more particularly described under the heading “Business and Properties – Significant Transactions and Recent Developments – Gilby/Willesden Green Acquisition”;

“Gilby/Willesden Green Properties” means the interests in oil and natural gas reserves and associated facilities located in the Gilby West and Willesden Green areas of west central Alberta acquired by Acclaim Energy pursuant to the Gilby/Willesden Green Acquisition as more particularly described under the heading “Business and Properties – Significant Transactions and Recent Developments – Gilby/Willesden Green Acquisition”;

“GLJ” means Gilbert Laustsen Jung Associates Ltd., independent petroleum consultants of Calgary, Alberta;

“GLJ Report” means the report dated February 23, 2005 evaluating, effective December 31, 2004, crude oil, natural gas liquids and natural gas reserves attributable to Acclaim Energy’s properties as at December 31, 2004;

“Gross” means:

(a)in relation to Acclaim Energy’s interest in production and reserves, its “company gross reserves”, which are Acclaim Energy’s interest (operating and non-operating) share before deduction of royalties and without including any royalty interest of Acclaim Energy;

(b)in relation to wells, the total number of wells in which Acclaim Energy has an interest; and

(c)in relation to properties, the total area of properties in which Acclaim Energy has an interest.

“Ketch Energy” means Ketch Energy Ltd., a predecessor corporation of Acclaim Energy, incorporated under the ABCA;

“Ketch Energy Arrangement” means the business combination involving the Trust, Acclaim Energy, Ketch Energy and Ketch Resources Ltd. completed on October 1, 2002 by way of a plan of arrangement under the ABCA pursuant to which, among other things, the Trust indirectly acquired all of the issued and outstanding shares of Ketch Energy, certain growth assets of Ketch Energy were acquired by Ketch Resources Ltd. and the shares of Ketch Resources Ltd. were distributed to the former holders of common shares of Ketch Energy;

“Ketch Energy Notes” means the 12% unsecured subordinated notes of Acclaim Energy issued in connection with the Ketch Energy Arrangement;

“Net” means:

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(a)in relation to Acclaim Energy’s interest in production and reserves, its “company gross reserves”, which are Acclaim Energy’s interest (operating and non-operating) share after deduction of royalty obligations, plus Acclaim Energy’s royalty interest in production or reserves.

(b)in relation to wells, the number of wells obtained by aggregating Acclaim Energy’s working interest in each of its Gross wells; and

(c)in relation to Acclaim Energy’s interest in a property, the total area in which Acclaim Energy has an interest multiplied by the working interest owned by Acclaim Energy.

“Nevis” means Nevis Ltd., a predecessor corporation of Acclaim Energy, incorporated under the ABCA;

“NG Acquisition” means the acquisition of the NG Properties by Acclaim Energy as more particularly described under the heading “Business and Properties –  Significant Transactions and Recent Developments – NG Acquisition”;

“NG Properties” means the interests in oil and natural gas reserves and associated facilities located in Alberta and British Columbia acquired by Acclaim Energy pursuant to the NG Acquisition as more particularly described under the heading “Business and Properties – Significant Transactions and Recent Developments – NG Acquisition”;

“NPI” means the net profits interest, commencing October 1, 2002, entitling the Trust to approximately 99% of the net cash flow generated from certain of the present and future oil and gas interests and related tangibles owned, directly or indirectly, by Acclaim Energy after certain costs, expenditures and deductions;

“Operating Entities” means Acclaim Energy, ACT, 960347 Alberta Inc., Acclaim Resource Partnership, Acclaim Energy Partnership, Acclaim Saskatchewan and 101001276 Saskatchewan Ltd.]

“Operating Entities Securities” means the Acclaim Notes, the ACT Notes, the NPI, the Acclaim Common Shares, the ACT Units and any other securities of the Operating Entities held by the Trust;

“Proved Reserves” are those Reserves that can be estimated with a high degree of certainty to be recoverable. There is believed to be at least a 90% probability that the quantities actually recovered will equal or exceed the estimated proved reserves.

“Probable Reserves” are those additional Reserves that are less certain to be recovered than Proved Reserves. It is equally likely that the actual remaining quantities recovered will be greater or lesser than the sum of the estimated Proved plus Probable Reserves. There is believed to be at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated Proved plus Probable Reserves.

“Reserves” are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on:

(a)analysis of drilling, geological, geophysical and engineering data;

(b)the use of established technology; and

(c)specified economic conditions which are generally accepted as being reasonable and shall be disclosed.

“Service well” means a well drilled or completed for the purpose of supporting production in an existing field. Wells in this class are drilled for the following specific purposes: gas injection (natural gas, propane, butane or flue gas), water injection, steam injection, air injection, salt water disposal, water supply for injection, observation or injection for combustion.

“Special Voting Units” means the special voting units authorized pursuant to the Trust Indenture, one of which has been issued to the Voting Trustee pursuant to the Voting Trust Agreement;

“Tax Act” means the Income Tax Act (Canada), R.S.C. 1985, c. 1 (5th Supp), as amended, including the regulations promulgated thereunder;

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“Trust” means Acclaim Energy Trust, a trust formed pursuant to the laws of Alberta;

“Trust Indenture” means the amended and restated trust indenture dated April 20, 2001 pursuant to which the Trust is governed;

“Trustee” means Computershare Trust Company of Canada as trustee of the Trust;

“TSX” means the Toronto Stock Exchange;

“Undeveloped Reserves” are those Reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of Production. They must fully meet the requirements of the reserves classification (Proved, Probable or Possible) to which they are assigned.

“Units” means trust units of the Trust;

“Unitholders” means the holders of Units;

“Voting Trust Agreement” means the voting trust agreement dated April 20, 2001 between Computershare Trust Company of Canada, as trustee, and the Trust; and

“Voting Trustee” means Computershare Trust Company of Canada, in its capacity as trustee under the Voting Trust Agreement.

In addition, any words or expression used in this Statement and not otherwise defined herein have the meanings attributed to them in NI 51-101 unless otherwise indicated.

All dollar amounts set forth in this annual information form are in Canadian dollars, except where otherwise indicated.

ABBREVIATIONS

Oil and Natural Gas Liquids
Bbls	barrels
MBbls	thousand barrels
Bbls/d	barrels of oil per day
BOE/d	barrels of oil equivalent per day
liquids	NGL
MBOE	one thousand barrels of oil equivalent
MMBbls	million barrels
NGL	natural gas liquids (consisting of any one or more of propane, butane and condensate)
mstb	thousand stock tank barrels of oil
bpd	barrels of production per day
Natural Gas
Mcf	thousand cubic feet
MMcf	million cubic feet
Bcf	billion cubic feet
Mcf/d	thousand cubic feet per day
MMcf/d	million cubic feet per day
m3	cubic metres
mmbtu	million British Thermal Units
Other
BOE	means barrels of oil equivalent. A barrel of oil equivalent is determined by converting a volume of natural gas to barrels using the ratio of six Mcf to one barrel. Boes may be misleading, particularly if used in isolation. The BOE conversion ration of 6 Mcf: 1 Bbl is based on an energy equivalency method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
WTI	means West Texas Intermediate.
API	means the measure of the density or gravity of liquid petroleum products derived from a specific gravity.
$M	means thousands of dollars

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CONVERSION

The following table sets forth certain standard conversions between Standard Imperial Units and the International System of Units (or metric units).

To Convert From	To	Multiply By
Mcf	cubic metres	28.174
cubic metres	cubic feet	35.494
Bbls	cubic metres	0.159
cubic metres	Bbls	6.289
feet	metres	0.305
metres	feet	3.281
miles	kilometres	1.609
kilometers	miles	0.621
acres	hectares	0.405
hectares	acres	2.471
gigajoules	mmbtu	0.95

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REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION

Management of Acclaim Energy Inc. (“Acclaim Energy”) are responsible for the preparation and disclosure of information with respect to Acclaim Energy’s oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data, which consist of the following:

(a)	(i)	proved and proved plus probable oil and gas reserves estimated as at December 31, 2004 using forecast prices and costs; and
	(ii)	the related estimated future net revenue; and
(b)	(i)	proved oil and gas reserves estimated as at December 31, 2004 using constant prices and costs; and
	(ii)	the related estimated future net revenue.

An independent qualified reserves evaluator has evaluated Acclaim Energy’s reserves data. The report of the independent qualified reserves evaluator is presented below.

The Reserves Committee of the Board of Directors of Acclaim Energy has

(a)reviewed Acclaim Energy’s procedures for providing information to the independent qualified reserves evaluator;

(b)met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluator to report without reservation; and

(c)reviewed the reserves data with management and the independent qualified reserves evaluator.

The Reserves Committee of the Board of Directors has reviewed Acclaim Energy’s procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The board of directors has, on the recommendation of the Reserves Committee, approved

(a)the content and filing with securities regulatory authorities of the reserves data and other oil and gas information;

(b)the filing of the report of the independent qualified reserves evaluator on the reserves data; and

(c)the content and filing of this report.

Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.

(signed) “J. Paul Charron”	(signed) “Richard J. Tiede”
J. Paul Charron	Richard J. Tiede
President and Chief Executive Officer	Vice-President, Business Development
(signed) “R. Gregory Rich”	(signed) “Jack C. Lee”
R. Gregory Rich	Jack C. Lee
Director and Chairman of the Reserves Committee	Chairman and Member of the Reserves Committee
March 10, 2005

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REPORT ON RESERVES DATA

To the board of directors of Acclaim Energy Inc. (the “Company”):

1.We have evaluated the Company’s reserves data as at December 31, 2004.  The reserves data consist of the following:

(a)	(i)	proved and proved plus probable oil and gas reserves estimated as at December 31, 2004 using forecast prices and costs; and
	(ii)	the related estimated future net revenue; and
(b)	(i)	proved oil and gas reserves estimated as at December 31, 2004 using constant prices and costs; and
	(ii)	the related estimated future net revenue.

2.The reserves data are the responsibility of the Company’s management.  Our responsibility is to express an opinion on the reserves data based on our evaluation.

We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).

3.Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement.  An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook.

4.The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated by us for the year ended December 31, 2004, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company’s board of directors:

	Description and	Location of
Independent Qualified	Preparation Date	Reserves (County	Net Present Value of Future Net Revenue
Reserves Evaluator or	of	or Foreign	(before income taxes, 10% discount rate)
Auditor	Report	Geographic Area)	Audited	Evaluated		Reviewed	Total
				($M)			($M)
Gilbert Laustsen Jung Associates Ltd.	Jan. 21, 2005	Canada	0	$	1,256,998	0	$	1,256,998

5.In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook.  We express no opinion on the reserves data that we reviewed but did not audit or evaluate.

6.We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates.

7.Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.

(signed) “Gilbert Laustsen Jung Associates Ltd.”

Gilbert Laustsen Jung Associates Ltd.

Calgary, Alberta

February 23, 2005

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