EX-99.8 9 a06-8040_1ex99d8.htm EXHIBIT 99

Exhibit 99.8

CANETIC RESOURCES TRUST

ANNUAL INFORMATION FORM

For the year ended December 31, 2005

March 24, 2006

TABLE OF CONTENTS

	Page
CANETIC RESOURCES TRUST	4
BUSINESS AND PROPERTIES	6
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION	15
ADDITIONAL INFORMATION RESPECTING CANETIC RESOURCES TRUST	31
ADDITIONAL INFORMATION RESPECTING CANETIC RESOURCES INC.	42
AUDIT COMMITTEE INFORMATION	45
MARKET FOR SECURITIES	47
DISTRIBUTIONS	48
RISK FACTORS	49
INTEREST OF INSIDERS IN MATERIAL TRANSACTIONS	57
INTEREST OF EXPERTS	57
MATERIAL CONTRACTS	58
LEGAL PROCEEDINGS	58
AUDITORS, TRANSFER AGENT AND REGISTRAR	58
ADDITIONAL INFORMATION	58
GLOSSARY OF TERMS	59
ABBREVIATIONS	66
CONVERSIONS	67

APPENDIX “A” –
MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION	A-1
APPENDIX “B” -
REPORT ON RESERVES DATA	B-1
APPENDIX “C”
TERMS OF REFERENCE FOR THE AUDIT COMMITTEE	C-1

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 Canetic 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 herein, contain forward-looking statements pertaining to the following:

• oil and natural gas production levels;

• timing, allocation and amounts of capital expenditures;

• distribution policies and future payout ratios;

• business strategies;

• estimates of net future revenues;

• development costs and the sources of funding thereof;

• farmout plans;

• abandonment and reclamation costs;

• hedging programs;

• anticipated tax obligations;

• the quantity of 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;

• changes in laws and regulations;

• 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 Canetic undertakes any obligation to publicly update or revise any forward-looking statements except as expressly required by applicable securities law.

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.

EFFECTIVE DATE OF INFORMATION

Except where otherwise indicated, the information in this Annual Information Form and in the Canetic Trust Engineering Report assumes that the Arrangement was completed on December 31, 2005, and assumes that the properties and assets of the Operating Entities acquired pursuant to the Arrangement were acquired by the Operating Entities on December 31, 2005. See “Canetic Resources Trust – The Arrangement”.

CANETIC RESOURCES TRUST

General

Canetic Resources Trust (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 - 5^th Avenue S.W., Calgary, Alberta, T2P 3G6.

The Trust owns, directly or indirectly, all of the outstanding common shares of Canetic (“Canetic Common Shares”), all of the outstanding Canetic Notes, the Canetic NPIs and securities of the other Operating Entities. Canetic is the corporation resulting from the amalgamation of AEI, SEL and certain other subsidiaries

Canetic 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 primarily in Alberta, British Columbia, Saskatchewan, Manitoba, North Dakota, Montana and Wyoming. The Trust participates in the cash flow from such business through its direct and indirect ownership of the Operating Entities Securities.

Organizational Structure of Canetic Resources Trust

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

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 to be made on or in respect of the Operating Entity Securities.

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

(5) Canetic directly or indirectly holds all of the assets formerly held by Acclaim and StarPoint, other than the TriStar Assets, which were transferred to TriStar pursuant to the Arrangement.

The Arrangement

The Trust was formed on November 16, 2005 and commenced operations on January 5, 2006 as a result of the completion of the Arrangement. The Arrangement was conducted for the purpose of combining the businesses of Acclaim and StarPoint into two new entities, namely, the Trust and TriStar. Prior to the Arrangement, each of Acclaim and StarPoint were open-ended unincorporated trusts indirectly engaged through their respective operating entities in the acquisition, development, exploitation, production, processing, upgrading and marketing of crude oil, natural gas liquids and natural gas. The trust units of Acclaim and StarPoint were listed on the TSX.

The Arrangement involved many steps, but the net effect of the Arrangement was as follows:

• the holders of Acclaim Units exchanged each Acclaim Unit for 0.8333 of a Unit;

• the holders of StarPoint Units exchanged each StarPoint Unit for one (1) Unit;

• holders of Acclaim Units and StarPoint Units also received, as a separate distribution, common shares of TriStar (“TriStar Common Shares”) on the basis of 0.0833 of a TriStar Common Share for each Acclaim Unit and 0.1 of a TriStar Common Share for each StarPoint Unit;

• holders of Acclaim Units received 0.0175 of a TriStar Arrangement Warrant for each Acclaim Unit held and holders of StarPoint Units received 0.0210 of a TriStar Arrangement Warrant for each StarPoint Unit held; and

• holders of Acclaim and StarPoint exchangeable shares participated in the Arrangement and received Units, TriStar Common Shares and TriStar Arrangement Warrants on the same basis as holders of Acclaim Units and StarPoint Units, respectively, based on the number of Acclaim Units or StarPoint Units into which such shares were exchangeable.

As a result of the Arrangement and the issue of Units pursuant to incentive plans of Acclaim and StarPoint in connection with the Arrangement, a total of approximately 200 million Units were issued to the former holders of trust units, exchangeable shares and incentive plan rights of Acclaim and StarPoint.

Summary Description of Business

Canetic Resources Trust

The principal undertaking of the Trust is to indirectly acquire and hold, through Canetic and the other Operating Entities, interests in petroleum and natural gas properties and assets related thereto.

The Trust owns, directly or indirectly, all of the assets of Acclaim and StarPoint other than the TriStar Assets, which were transferred to TriStar pursuant to the Arrangement. The Trust retained all of the liabilities of Acclaim and StarPoint, including liabilities relating to corporate and income tax matters.

The Trust’s primary assets consist of all of the outstanding Canetic Common Shares, the Canetic Notes, the Canetic NPIs and the other Operating Entities Securities.

The Trust’s distribution policy is currently set at $0.23 per Unit per month. It is anticipated that this distribution policy will result in a 2006 payout ratio of approximately 60% to 65% based on a commodity price forecast of US$62 WTI for oil and C$8.25 AECO for natural gas. Future distributions and the actual payout ratio is subject to the discretion of the Board of Directors and may vary depending on, among other things, the current and anticipated commodity price environment. See also “Information Concerning Canetic Resources Trust – Risk Factors.”

Operating Entities

Canetic, directly and through the other Operating Entities, is actively involved in the acquisition, development, exploitation, production, processing, upgrading and marketing of crude oil, natural gas liquids and natural gas primarily in Alberta, British Columbia, Saskatchewan, Manitoba, North Dakota, Montana and Wyoming. See also “Business and Properties”, “Statement of Reserves Data and Other Oil and Gas Information” and “Additional Information Respecting Canetic Resources Inc.”.

BUSINESS AND PROPERTIES

Since January 5, 2006 Canetic and the other Operating Entities have been, directly and indirectly, actively involved in the acquisition, development, exploitation, production, processing, upgrading and marketing of crude oil, natural gas liquids and natural gas primarily in Alberta, British Columbia, Saskatchewan, Manitoba, North Dakota, Montana and Wyoming. References in this section to Canetic include the other Operating Entities unless the context otherwise requires.

General Development of the Business

Certain information relating to the oil and natural gas properties discussed in this Annual Information Form is limited to the period of time during which Canetic, Acclaim or StarPoint were the owners of such properties. Any information relating to periods prior to the effective date of such acquisitions is based upon publicly available information or the records of Canetic, Acclaim or StarPoint, as the case may be. While Canetic has no reason to believe that such information is not accurate, Canetic can provide no assurance that such information is accurate.

The principal business of Canetic is to acquire, explore, develop and produce oil and natural gas reserves primarily in western Canada and the northern U.S. Canetic focuses its efforts primarily on acquisition and subsequent exploitation opportunities, especially those that are expected to offer a stable production base with the potential of upside through development drilling and production optimization. Canetic endeavors to maintain a high working interest in its core areas, which is expected to enable it to maximize operational flexibility and to better control the nature and timing of its expenditures.

Significant Transactions and Recent Developments

As the Trust was formed as a result of the combination of the business of Acclaim and StarPoint pursuant to the Arrangement (see “Canetic Resources Trust – The Arrangement”), the following is a description of the significant transactions in the development of Acclaim and StarPoint prior to the Arrangement.

Acclaim Significant Transactions

Danoil Merger

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

Ketch Energy Arrangement

On October 1, 2002, Acclaim 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 Acclaim 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 Ketch 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 Reserves and approximately 247,000 net acres of undeveloped lands to Acclaim.

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

As a condition of the Ketch Energy Arrangement, AEI acquired all of the issued and outstanding shares of Acclaim Energy Management Inc., the former manager of AEI, 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.

Elk Point Arrangement

On January 28, 2003, Acclaim 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 Acclaim Units and $10.9 million in cash. Acclaim 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 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’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 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, AEI 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 AEI’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, AEI 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. Acclaim issued approximately 1,341,905 Acclaim 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.

Chevron Texaco Acquisition

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

Production from the Chevron Texaco 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 Chevron Texaco 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 Chevron Texaco 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 Chevron Texaco 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.

StarPoint Significant Transactions

Creation of StarPoint Energy Ltd.

On September 5, 2003 StarPoint Energy Ltd. (“SEL”) was created as a result of the successful reorganization of Crescent Point Energy Ltd. and Tappit Resources Ltd. into Crescent Point Energy Trust and SEL.

SEL’s average production for the three months ended December 31, 2003 was 1,421 Boe/d weighted 13% to oil and 87% to natural gas. Assets held by the company at that time consisted of properties in southeast Saskatchewan, west central Alberta (Paddle River) and northeastern British Columbia (Fort St. John).

Acquisition of Upton

On January 27, 2004, SEL completed the acquisition of Upton Resources Inc. (“Upton”) pursuant to a plan of arrangement under the provisions of The Business Corporations Act (Saskatchewan). Under the arrangement, SEL acquired all of the issued and outstanding common shares of Upton in exchange for a total of approximately 23,700,625 common shares of SEL.

The acquisition increased SEL’s production by an estimated 5,000 Boe/d of primarily light oil and natural gas, focused mainly in southeast Saskatchewan and North Dakota.

E3 Plan of Arrangement and Creation of StarPoint Energy Trust

On January 7, 2005, SEL and E3 Energy Inc. completed a plan of arrangement, creating StarPoint Energy Trust (“StarPoint”) and Mission Oil & Gas Inc.

Upon completion of the transaction SEL’s production was approximately 8,000 Boe/d, weighted 74% to oil and 26% to natural gas. Assets held by the Trust were largely focused in southeast Saskatchewan.

Acquisition of Selkirk

On January 28, 2005, StarPoint acquired all of the issued and outstanding shares of four private corporations for aggregate net cash consideration of $63.1 million. Together, the private corporations owned 100% of the interests in Selkirk, a general partnership formed under the laws of the Province of Alberta.

Selkirk’s principal properties were located in the Deep Basin area of Alberta, approximately 75 kilometers southwest of the city of Grand Prairie. Production was primarily from the Chinook formation at Red Rock, with minor volumes from Elmworth and Wapiti. Selkirk had an average working interest of 38% in its Deep Basin assets. At Red Rock, Selkirk’s interest was limited to production from certain wellbores from the Chinook Formation.

Net production from this area was approximately 1,140 Boe/d in the month of December, 2004. Production is processed through third party gas plants, with Selkirk holding a 57.2% net working interest in a 400 HP booster compressor located at Wapiti.

The APF Plan of Arrangement

On June 27, 2005, StarPoint completed a plan of arrangement with APF Energy Trust (“APF”). Pursuant to the APF plan of arrangement, StarPoint acquired all of the assets of APF and assumed all of its liabilities. In exchange, StarPoint issued 0.63 of a trust unit for every outstanding trust unit of APF.

Production acquired through the APF transaction averaged 16,796 Boe/d for the three months ended March 31, 2005. Volumes were weighted 37% light and medium crude, 7% heavy oil and 56% to natural gas and NGLs.

The APF assets included properties in Manitoba, Saskatchewan, Alberta, Montana and Wyoming. These properties were prospective for both conventional oil and gas from multiple zones in each area and non-conventional coalbed methane production.

The EnCana Acquisition

On June 30, 2005, StarPoint completed an asset acquisition from EnCana Corporation (“EnCana”). Pursuant to the EnCana acquisition, StarPoint indirectly acquired certain assets, effective May 1, 2005, for aggregate cash consideration of $392 million.

The EnCana assets included properties located in southern Alberta at Countess, Provost and Alderson. Production from these assets for the three months ended March 31, 2005 was 6,890 Boe/d weighted 86% to oil and 14% to gas and NGLs.

The Nexen Acquisition

On August 9, 2005, StarPoint indirectly acquired certain assets from Nexen Inc. (“Nexen”) for aggregate cash consideration of $317.3 million.

The properties comprising the Nexen assets are located in southeast Saskatchewan, approximately 210 kilometers southeast of Regina. The properties feature a land base situated along the Frobisher/Kisbey/Alida subcrop edge. Interests range from royalty interests to working interests up to 100%, with the average working interest being approximately 65%.

Production from the assets was weighted 92% to oil, with the balance being solution gas. Average production from the properties during the six months ended June 30, 2005 was 6,350 Boe/d. Oil production from the assets is generally light sweet crude with a 38° API. The acquired properties include Edenvale, Ingoldsby, Nottingham, Cantal and Queensdale.

Oil and Gas Properties

The following is a description of Canetic’s principal oil and natural gas properties. Unless otherwise specified, production estimates, gross and net acres and well count information are as at December 31, 2005. Reserve amounts are stated, before deduction of royalties as at December 31, 2005, based on escalating cost and price assumptions as evaluated in the Canetic Trust Engineering 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.

Canetic’s operations are entirely land-based and are focused primarily in western Canada, concentrated in eight geographic operating districts. Canetic operates approximately 80 percent of its production and has a large opportunity profile for continued growth through its detailed technical analysis and operational expertise. Canetic has minor interests in the United States.

Williston Basin District

The Williston Basin district includes properties located in southeast Saskatchewan, Manitoba, North Dakota, Montana and Wyoming. In total 118 (60.0 net) wells were drilled on these properties during 2005, including 57 (41.5 net) oil, 56 (15.3 net) gas, 3 (2.0 net) D&A and 2(1.2 net) test wells.

Greater Queensdale, Saskatchewan

The Greater Queensdale assets are located in southeast Saskatchewan about 100-150 kilometers north and east of Estevan. This area includes the Ingoldsby, Queensdale, Gainsborough, Cantal and Edenvale properties.

The main producing assets of this area include portions of the Queensdale Frobisher-Alida Pool, Alida West Frobisher-Alida Pool (Edenvale), Cantal Frobisher-Alida Pool, Nottingham South Frobisher-Alida Pool, Rosebank Alida Pool, and the Ingoldsby Frobisher Alida Pool. The light oil (30-38°API) is produced from the Frobisher-Alida beds at 1,000 to 1,400 meters in depth. Substantially all of the production in which Canetic has an interest is pipelined to company owned central facilities including oil, gas and water separation and treating equipment, crude oil pipeline connection, and salt water disposal facilities. Canetic has a working interest in the NAL-operated Nottingham gas plant at 8-17-5-32 W1M and associated gas-gathering system where the majority of the area’s conserved solution gas is processed.

Greater Midale, Saskatchewan

The Greater Midale assets are located in southeast Saskatchewan about 50-100 kilometers north and west of Estevan. This area includes the Bryant, Tatagwa, Midale and Innes assets.

The main producing assets in this area include portions of the Bryant Midale Pool, Tatagwa Midale Pool, Radville Midale Pool, Midale Frobisher Pool and the Innes Frobisher Pool. The medium oil (22-29° API) is produced from the Midale and Frobisher beds at 1,200 to 1,400 meters in depth. Substantially all of the production in which Canetic has an interest is pipelined to central facilities owned by Canetic including oil, gas and water separation and treating equipment, a crude oil pipeline connection, and salt water disposal facilities. Some facilities are connected to solution gas gathering facilities resulting in small quantities of solution gas sales. Some production is produced to single well batteries where oil and water are separated and trucked to Canetic owned facilities for processing and sale.

Heward/Handsworth, Saskatchewan

The Heward/Handsworth assets are located in southeast Saskatchewan about 100 kilometers north of Estevan. These properties include the Heward, Handsworth, Coyote Lake and Pheasant Rump properties.

The main producing assets in this area include portions of the Heward Frobisher-Alida Pool, Hartaven Alida Pool, Melrose Frobisher-Alida Pool, Handsworth Alida Pool and Pheasant Rump Alida Pool. The medium to light oil (26-32° API) is produced from the Frobisher-Alida beds at 1,000 to 1,100 meters in depth. Substantially all of the production in which Canetic has an interest is pipelined to company owned central facilities including oil, gas and water separation and treating equipment, a crude oil pipeline connection, and salt water disposal facilities. Some facilities are connected to solution gas gathering facilities resulting in small quantities of solution gas sales. Some company production is produced to single well batteries where oil and water are separated and trucked to company owned facilities for processing and sale.

North Dakota and Montana, USA

The properties located in eastern Montana and southwest North Dakota, USA are about 200-300 kilometers south of Estevan. Canetic has working interests ranging from 19% to 100%.

The main producing assets in this area include portions of the Brush Mountain Ratcliffe Pool, Tracy Mountain Tyler Pool and Davis Creek Madison Pool. The light oil (35-42° API) is produced from the Mississippian Madison and Pennsylvanian Tyler beds at 2,500 to 3000 meters in depth.

Substantially all of the production in which Canetic has an interest is produced to single well batteries where oil, water and gas are separated; gas is consumed as well site fuel or flared oil and water are trucked for sale and disposal respectively.

Wyoming, USA – Powder River Basin Coalbed Methane (“CBM”)

The Wyoming properties are located in the Powder River Basin, north of Casper. The properties have 10,141 net acres of undeveloped land with an average working interest of 47%. During 2005, 56 (15.3 net) development CBM wells were drilled on these properties. Assets at Big Bend, North Carson and Kane target the Big George, Anderson, Canyon/Cook, Wall/Pawnee and Wyodak coals at depths ranging from 100 to 700 meters.

Southern District

The Southern district includes properties located in southern Alberta and southwest Saskatchewan. In total 66 (48.2 net) wells were drilled on these properties during 2005, including 22 (15.1 net) oil, 42 (32.7 net) gas and 2 (0.4 net) D&A.

Countess, Alberta

The Countess properties are located in southern Alberta, approximately 130 kilometers southeast of Calgary. The properties in this area have a working interest between 50 and 100% for the oil assets and 17.5 to 100% for the gas assets.

These assets are comprised of Mannville oil and shallow Medicine Hat/Milk River gas. The gas wells are drilled at an average depth of 550 meters. Canetic gas facilities at Countess are comprised of a compressor and processing facility and several booster compressors. The compression facilities supply gas to pipelines for sales distribution.

The majority of the Countess oil production is obtained from the Rosemary Lower Mannville Z and RR oil pools and the Duchess Lower Mannville X and VVV oil pools, which are currently under active waterflood schemes. A small portion of the production is produced to single well batteries. The medium oil (26-33° API) is produced from Lower Mannville sandstones at 1,100 to 1,200 meters in depth.

Substantially all of the Countess oil production is pipelined to one of two 100% working interest central facilities located at Rosemary and Duchess. The central facilities include oil, gas and water separation and treating equipment, a crude oil pipeline connection, salt water disposal facilities, and solution gas gathering facilities. A small portion of the production is produced to single well batteries where oil and water are separated and trucked to various area facilities for processing and sale.

Alderson, Alberta

The Alderson properties are located in southern Alberta, approximately 190 kilometers southeast of Calgary. The properties in this area have an average operated working interest of 100%.

The majority of the Alderson production is obtained from the Suffield West Arcs D and Lower Mannville D3D and E3E oil pools and several Alderson Lower Mannville oil pools, which are currently under active waterflood schemes. A small portion of the production is produced to single well batteries. The medium oil (27-31° API) is produced from Lower Mannville sandstones at 900 to 1,000 meters in depth and the Arcs Nisku carbonate formation at approximately 1,250 meters in depth.

Substantially all of the Alderson production is pipelined to one of four 100% working interest central facilities located at Suffield West and Alderson. The central facilities will include oil, gas and water separation and treating equipment, a crude oil pipeline connection, salt water disposal facilities, and solution gas gathering facilities. A small portion of the production is produced to single well batteries where oil and water is separated and trucked to various area facilities for processing and sale.

Innisfail, Alberta

The Innisfail properties are located in central Alberta, south of Red Deer. Drilling activity at Innisfail targets shallow Edmonton Sand gas and deeper Pekisko and Leduc oil.

Sibbald/Acadia, Alberta

The Sibbald/Acadia property is located approximately 260 kilometers east of Calgary. Canetic has an average working interest of 67%. The facilities on the property in which Canetic has an interest consist of two multi-well oil batteries and one single well oil battery.

Border Plains District

The Border Plains district includes properties located in east central Alberta and west central Saskatchewan. In total 53 (47.4 net) wells were drilled on these properties during 2005, including 40 (39.2 net) oil, 11 (6.7 net) gas and 2 (1.5 net) D&A.

Provost, Alberta

The Provost properties are located in eastern Alberta, approximately 260 kilometers southeast of Edmonton. The properties in this area have an average operated working interest of approximately 100%.

The majority of the Provost production is obtained from the Provost Lloydminster O and Sparky D oil pools and the Hayter Sparky W oil pool. The Provost and Hayter oil pools are currently under active waterflood schemes. A small portion of the production is obtained from Cummings and Colony oil pools at Provost and Cummings and General Petroleum oil pools at Hayter. The medium and heavy oil (20-25° API) is produced from Middle and Lower Mannville sandstones at 700 to 900 meters in depth.

The majority of the production is processed through a pipeline connected 100% working interest central facility located at Provost. The central facility includes oil, gas and water separation and treating equipment, a crude oil pipeline connection, salt water disposal facilities, and solution gas gathering facilities. Gas production at Hayter is custom processed through a third party facility.

Furness, Saskatchewan

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.

Canetic has a 75% working interest in a central oil battery that is connected to a sales oil pipeline. The battery is located at 14-08-048-27W3M and is capable of handling 1,600 Bbls/d of oil.

South Central District

The South Central district includes properties located in central Alberta. In total 19 (8.0 net) wells were drilled on these properties during 2005, including 9 (2.0 net) oil, 8 (4.5 net) gas and 2 (1.5 net) D&A.

Acheson, Alberta

The Acheson area is west of Edmonton and 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. Canetic’s overall working interest in the area is 99.7%.

Gas is processed at the 100% working interest operated 5-2-53-26W4M Acheson gas plant, capable of processing 25 MMcf/d of gas. The oil from the 100% owned Acheson field is processed at the unit battery facility located at the 5-2-53-26W4 site.

Acheson is a multi-zone area with production coming from the Leduc, Nisku, Detrital, Basal Quartz and Viking 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.

Golden Spike, Alberta

The Golden Spike area is located approximately five miles west of Edmonton. Working interests in the area vary, with the majority of working interests ranging from 95 to 100%. The vast majority of the wells and related facilities are Canetic 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.

North Central District

The North Central district includes properties located in central Alberta. In total 6 (1.8 net) oil wells were drilled on these properties during 2005.

Mitsue, Alberta

The Mitsue oil field is located near Slave Lake in north central Alberta approximately 125 miles north of Edmonton. AEI 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. AEI assumed operatorship of the unit following the acquisition of assets from ChevronTexaco on June 30, 2004. Canetic also has various interests in non-unit production in this area.

The oil from the Mitsue Gilwood Sand Units No. 1 and 2 is collected at one of 37 satellites where the fluids are commingled and moved via three-phase group lines to one of three main batteries. The main batteries consist of separation, compression, treating, fresh water injection, water disposal and storage facilities. The treated oil is shipped to Edmonton for sale through the Rainbow Pipeline. The solution gas is collected at the main batteries, compressed and sent to the unit Mitsue Gas Plant located at 16-30-072-04W5M. The plant current average throughput is 7.0 MMcf/day of gas. The plant consists of sweetening, turbo expansion and refrigeration.

Rocky District

The Rocky district includes properties located in west central Alberta. In total 82 (45.1 net) wells were drilled on these properties during 2005, including 8 (5.9 net) oil, 73 (38.2 net) gas and 1 (1.0 net) D&A.

Willesden Green, Alberta

The Willesden Green area is located approximately 80 miles southwest of Edmonton. The properties 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 Scollard, Belly River, Cardium, Ellerslie, Ostracod, Rock Creek and Nordegg formations. This is a multi-target area with shallow to moderate drill depths and a large concentrated land position 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. Canetic owns the facilities associated with the production, as well as a 21.7% interest in the Imperial Oil Ltd. Willesden Green natural gas plant.

Gilby/Medicine River, Alberta

The Gilby area is situated approximately 20 miles southeast 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 was acquired pursuant to the Gilby/Willesden Green Acquisition and consists of six units (three operated) and non-unit holdings producing from early Cretaceous 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 Canetic was elected operator, and working interests in a number of operated facilities.

Drayton Valley District

The Drayton Valley district includes properties located in western Alberta. In total 51 (16.7 net) wells were drilled on these properties during 2005, including 28 (6.4 net) oil, 19 (8.2 net) gas, 1 (0.1 net) service and 3 (2.0 net) D&A.

Brazeau/Bigoray, Alberta

There are 10 Nisku Pools in the Bigoray, Brazeau, and West Pembina areas. Canetic is the operator of all these pools. Eight of the pools were on miscible flood, 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.

Gas from the 10 Nisku Pools is processed at one of the following three Keyspan operated facilities: 10-07-051-09W5 Bigoray Gas Plant, or 16-35-048-12W5 Brazeau River Gas Plant, or 11-22-049-12W5 West Pembina Gas Plant.

Kaybob, Alberta

The Kaybob district covers a very large area approximately 150 miles northwest of Edmonton.

Kaybob Gas – Kaybob South Beaverhill Lake Units 1, 2, and 3

The Kaybob natural gas production comes from the Kaybob South Beaverhill Lake Units 1, 2 and 3. The units are located south of the town of Fox Creek. BP Canada operates Units 1 and 2 and Trilogy Energy operates Unit 3. AEI 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 Beaverhill Lake Group. The reservoir was a retrograde gas condensate reservoir, and as a result, all three units 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.

The gas from the Kaybob South Beaverhill Lake Units No. 1 and No. 2 is processed at the Central Alberta Midstream operated Kaybob Amalgamated Gas Plant located at 12-01-062-20W5M. Gas from the Kaybob South Beaverhill Lake Unit No. 3 is processed at the Central Alberta Midstream operated Kaybob South 3 Gas Plant located at 01-15-059-18W5M.

Kaybob South Triassic Unit No. 2

Canetic 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. The oil from Kaybob Triassic Unit No. 2 is processed at a central unit battery located at 03-24-062-20W5 operated by PrimeWest Energy Inc. The battery is equipped with solution gas recovery and compression. The solution gas is compressed and shipped to the Central Alberta Midstream operated Kaybob Amalgamated Gas Plant at 12-01-062-20W5 for processing.

Peace River Arch District

The Peace River Arch district includes properties located in northwest Alberta and northeast British Columbia. In total 28 (10.6 net) wells were drilled on these properties during 2005, including 8 (3.4 net) oil and 20 (7.2 net) gas.

Pouce Coupe, Alberta

The Pouce Coupe properties are located approximately 50 miles northwest of Grande Prairie. Canetic 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. Canetic 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 a 78.75% working interest. Producing formations primarily include the Doig, Bluesky, Gething, Baldonnel, Halfway and Boundary Lake.

Red Rock, Alberta

The Red Rock Property is located in the Deep Basin area of Alberta, approximately 75 kilometers southwest of Grande Prairie. Production is primarily from the Chinook formation. Production from this area is processed through third party gas plants.

Simonette, Alberta

The Simonette Beaverhill Lake A and B Pools are located approximately 150 kilometers southeast of Grande Prairie. Canetic 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.

Multiphase sour lines gather oil production from the Simonette Beaverhill Lake A and B pools to the battery located at 16-17-064-26W5M. Canetic has a 32% working interest in the battery, which consists of three phase inlet separation, compression, treating, gas dehydration, produced and fresh water injection and storage. The solution gas is shipped to the Central Alberta Midstream operated Kaybob 3 Gas Plant via a 65-mile pipeline operated by Central Alberta Midstream.

Fort St. John, British Columbia

The Fort St. John properties are primarily located in the Fort St. John area in northeast British Columbia. The principal properties are within a 20 kilometer radius of Fort St. John. Canetic has an average working interest of 55%. Canetic also has 50% and 65% working interests, respectively, in two operated compressor stations and 38.44% and 27% working interests, respectively, in a further two non-operated compressor stations.

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

The effective date of the statement of reserves data and other oil and gas information set forth below (the “Statement”) is December 31, 2005 and the preparation date of the Statement is February 28, 2006.

In this section “Canetic” shall mean Canetic or one or more of the other Operating Entities.

Disclosure of Reserves Data

The reserves data of Canetic set forth below (the “Reserves Data”) is based upon evaluations by GLJ and Sproule with effective dates of December 31, 2005 contained in the Canetic Trust Engineering Report. The Reserves Data summarizes the crude oil, liquids and natural gas reserves of Canetic 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 Canetic believes is important to the readers of this information.

The majority of Canetic’s reserves are located in Canada and, specifically, in the provinces of Alberta, British Columbia, Saskatchewan and Manitoba. Canetic has minor interests in the United States.

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.

Reserves Data (Forecast Prices and Costs)

The reserves information presented does not report the U.S. reserves separately. The U.S. properties have proved plus probable gross reserves of approximately 7,179 MBoe or 3.0% of total reserves with a before tax net present value discounted at 10% of approximately $104,693,000 or 2.8% of total value.

The following tables provide Reserves Data and future net revenues of Canetic using forecast prices and costs.

Summary of Oil and Gas Reserves and Net Present Values of Future Net Revenue as of December 31, 2005

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
	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(MMcf)	(MMcf)	(Mbbls)	(Mbbls)	(MBoe)	(MBoe)

Proved
Developed Producing	66,496	59,310	16,459	15,086	265,632	211,206	8,661	6,223	135,888	115,820
Developed Non-Producing	2,290	2,064	1,892	1,686	31,684	24,264	931	667	10,392	8,461
Undeveloped	13,430	12,112	1,396	1,287	54,855	43,534	744	528	24,712	21,182
Total Proved	82,215	73,487	19,747	18,059	352,171	279,005	10,335	7,417	170,992	145,463
Probable	33,420	29,754	6,472	5,931	135,106	108,717	3,637	2,684	66,046	56,489

Total Proved Plus Probable	115,635	103,241	26,219	23,990	487,277	387,721	13,972	10,101	237,038	201,952

Royalty interest reserves for Proved Developed Producing, Total Proved, and Total Proved Plus Probable are 978 MBoe, 1,039 MBoe, and 1,340 MBoe respectively, which equate to Company Interest Reserves of 136,865 MBoe, 172,032 MBoe, and 238,378 MBoe respectively.

	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	3,869,809	3,040,225	2,571,173	2,261,424	2,037,449	3,869,809	3,040,225	2,571,173	2,261,424	2,037,449
Developed Non-Producing	268,511	202,284	166,720	143,232	126,104	268,511	202,284	166,720	143,232	126,104
Undeveloped	504,181	366,783	281,124	222,193	179,069	504,181	366,783	281,124	222,193	179,069
Total Proved	4,642,501	3,609,292	3,019,017	2,626,849	2,342,622	4,642,501	3,609,292	3,019,017	2,626,849	2,342,622
Probable	1,751,663	1,072,083	767,825	596,645	486,468	1,751,663	1,072,083	767,825	596,645	486,468

Total Proved Plus Probable	6,394,164	4,681,375	3,786,842	3,223,494	2,829,090	6,394,164	4,681,375	3,786,842	3,223,494	2,829,090

Total Future Net Revenue (Undiscounted) as of December 31, 2005

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 Reserves	9,095,872	1,487,109	2,513,562	291,950	160,749	4,642,502	0	4,642,502

Proved Plus Probable Reserves	12,639,412	2,047,603	3,580,963	434,826	181,855	6,394,165	0	6,394,165

Future Net Revenue by Production Group as of December 31, 2005

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)	1,829,219
	Heavy Oil (including solution gas and other by-products)	238,909
	Natural Gas (including CBM and by-products but excluding solution gas from oil wells)	949,951
	Other Company Revenue/Costs	938
	Total	3,019,017

Reserves Category	Production Group	Future Net Revenue Before Income Taxes (discounted at 10%/year)
		(M$)
Proved Plus Probable Reserves	Light and Medium Crude Oil (including solution gas and other by-products)	2,314,428
	Heavy Oil (including solution gas and other by-products)	291,241
	Natural Gas (including CBM and by-products but excluding solution gas from oil wells)	1,180,666
	Other Company Revenue/Costs	507
	Total	3,786,842

Reserves Data (Constant Prices and Costs)

The following tables provide Reserves Data and future net revenue of Canetic using constant prices and costs.

Summary of Oil and Gas Reserves and Net Present Values of Future Net Revenue as of December 31, 2005

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
	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(MMcf)	(MMcf)	(Mbbls)	(Mbbls)	(MBoe)	(MBoe)

Proved
Developed Producing	68,637	61,315	16,441	15,073	277,050	221,548	8,888	6,376	140,141	119,689
Developed Non-Producing	2,314	2,089	1,897	1,695	31,994	24,610	939	674	10,482	8,560
Undeveloped	13,551	12,206	1,400	1,293	55,881	44,452	757	535	25,021	21,443
Total Proved	84,502	75,610	19,738	18,062	364,926	290,610	10,584	7,585	175,644	149,692
Probable	34,627	30,863	6,509	5,974	140,726	113,867	3,736	2,749	68,326	58,564

Total Proved Plus Probable	119,129	106,473	26,247	24,037	505,651	404,477	14,320	10,333	243,970	208,255

Royalty interest reserves for Proved Developed Producing, Total Proved, and Total Proved Plus Probable are 1,008 MBoe, 1,066 MBoe, and 1,374 MBoe respectively, which equate to Company Interest Reserves of 141,149 MBoe, 176,710 MBoe, and 245,345 MBoe respectively.

	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	4,522,279	3,454,547	2,847,088	2,449,795	2,166,898	4,522,279	3,454,547	2,847,088	2,449,795	2,166,898
Developed Non-Producing	312,185	233,289	189,098	159,729	138,455	312,185	233,289	189,098	159,729	138,455
Undeveloped	654,240	468,570	354,845	277,584	221,696	654,240	468,570	354,845	277,584	221,696
Total Proved	5,488,704	4,156,406	3,391,031	2,887,108	2,527,048	5,488,704	4,156,406	3,391,031	2,887,108	2,527,048
Probable	2,109,267	1,290,900	913,897	699,731	561,982	2,109,267	1,290,900	913,897	699,731	561,982

Total Proved Plus Probable	7,597,971	5,447,307	4,304,929	3,586,838	3,089,030	7,597,971	5,447,307	4,304,929	3,586,838	3,089,030

Total Future Net Revenue (Undiscounted) as of December 31, 2005

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 Reserves	9,870,112	1,627,449	2,340,204	286,108	127,647	5,488,704	0	5,488,704

Proved Plus Probable Reserves	13,619,132	2,244,651	3,216,659	425,532	134,322	7,597,968	0	7,597,968

Future Net Revenue by Production Group as of December 31, 2005

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)	2,062,530
	Heavy Oil (including solution gas and other by-products)	206,788
	Natural Gas (including CBM and by-products but excluding solution gas from oil wells)	1,120,592
	Other Company Revenue/Costs	1,120
	Total	3,391,030

Proved Plus Probable Reserves	Light and Medium Crude Oil (including solution gas and other by-products)	2,617,625
	Heavy Oil (including solution gas and other by-products)	254,358
	Natural Gas (including CBM and by-products but excluding solution gas from oil wells)	1,432,207
	Other Company Revenue/Costs	738
	Total	4,304,928

Pricing Assumptions

The following tables set forth the pricing assumptions used in preparing the Reserves Data, which was an average of the GLJ and Sproule January 1, 2006 reference prices and, in the case of forecast prices and costs, the inflation rate assumptions.

Summary of Pricing Assumptions as of December 31, 2005

Constant Prices and Costs

		December 31, 2005
Inflation Rate Percent		0.00

Crude Oil $Cdn/Bbl
Light Sweet Crude @ Edmonton		68.20
Heavy @ Hardisty		29.56
Medium @ Cromer		52.06

WTI @ Cushing, Oklahoma ($US/Bbl)		61.04

NGLs $Cdn/Bbl at Edmonton
Propane		47.80
Butane		54.92
Condensate		71.51

Natural Gas $Cdn/MMBTU
AECO Spot		9.85
Alberta Spot Plant-gate		9.30
Alberta Government Reference Plant-gate		9.30
Alberta Aggregator Plant-gate		9.02
Saskatchewan Spot Plant-gate		9.61
B.C. Spot Plant-gate		8.91
Canwest Plant-gate		7.77

Exchange Rate $US/$Cdn		.8589

Summary of Pricing and Inflation Rate Assumptions as of December 31, 2005

Forecast Prices and Costs

	Oil
Year	WTI Cushing Oklahoma	Edmonton Par Price 40° API	Hardisty Heavy 12° API	Cromer Medium 29° 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
2006	58.91	68.16	35.16	57.69	11.09	40.88	48.00	69.38	2.25	0.8500
2007	58.30	67.50	35.02	57.82	10.05	40.38	47.44	68.98	2.25	0.8500

	Oil
Year	WTI Cushing Oklahoma	Edmonton Par Price 40° API	Hardisty Heavy 12° API	Cromer Medium 29° 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)

2008	52.80	60.99	33.37	52.37	8.47	36.57	42.92	62.37	2.25	0.8500
2009	49.10	56.64	32.14	48.72	7.68	33.99	39.92	57.83	1.75	0.8500
2010	47.13	54.32	31.58	46.75	7.38	32.55	38.33	55.48	1.75	0.8500
2011	46.74	53.86	32.72	46.40	7.30	32.29	37.98	55.03	1.75	0.8500
2012	47.10	54.28	33.12	46.80	7.36	32.52	38.26	55.46	1.75	0.8500
2013	47.97	55.20	33.78	47.59	7.50	33.01	38.92	56.39	1.75	0.8500
2014	48.72	56.13	34.57	48.50	7.65	33.62	39.58	57.33	1.75	0.8500
2015	49.60	57.20	35.24	49.43	7.82	34.24	40.25	58.41	1.75	0.8500
2016	50.49	58.14	36.04	50.23	7.96	34.87	40.93	59.49	1.75	0.8500
2017+	+1.75%/yr	+1.75%/yr	+1.75%/yr	+1.75%/yr	+1.75%/yr	+1.75%/yr	+1.75%/yr	+1.75%/yr	1.75	0.8500

Weighted average historical prices realized by Acclaim for the year ended December 31, 2005, were $9.08/Mcf for natural gas, $64.48/Bbl for light/medium crude oil, $40.44/Bbl for natural gas liquids and $37.49/Bbl for heavy oil.

Reconciliations of Changes in Reserves and Future Net Revenue

The following table sets forth the reconciliation of Acclaim’s net reserves for the year ended December 31, 2005 using an average of the GLJ and Sproule forecast price and cost estimates, reconciled to Acclaim’s net reserves at December 31, 2004.

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)

Acclaim Dec 31, 2004	33,427		8,761		42,188		8,142		2,432		10,574

Acquisitions	28		—		28		—		—		—
Dispositions	(277	)	(141	)	(418	)	—		—		—
Discoveries	69		325		394		249		218		467
Extensions	575		450		1,025		280		444		724
Infill Drilling	678		64		742		—		370		370
Improved Recovery	118		54		172		338		68		406
Economic Factors	501		131		633		122		36		159
Technical Revisions	2,548		(719	)	1,829		70		(559	)	(490	)
Production	(4,197	)	—		(4,197	)	(1,585	)	—		(1,585	)

Acclaim Dec 31, 2005	33,471		8,925		42,396		7,617		3,009		10,626
StarPoint Dec 31, 2005	40,016		20,829		60,845		10,442		2,922		13,364
Canetic Dec 31, 2005	73,487		29,754		103,241		18,059		5,931		23,990

	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)

Acclaim Dec 31, 2004	148,825		44,798		193,623		5,540		1,766		7,306		71,913		20,425		92,339

Acquisitions	51		263		314		2		—		2		38		44		82
Dispositions	(1,711	)	(431	)	(2,142	)	(18	)	(9	)	(28	)	(580	)	(222	)	(802	)
Discoveries	2,267		590		2,857		30		9		39		725		650		1,376
Extensions	24,908		12,707		37,615		574		254		828		5,580		3,266		8,846
Infill Drilling	3,365		406		3,770		58		(13	)	45		1,297		488		1,785
Improved Recovery	1,748		1,064		2,812		152		66		218		900		366		1,266
Economic Factors	2,232		672		2,904		83		26		110		1,079		306		1,385
Technical Revisions	7,773		(6,925	)	848		420		(232	)	187		4,333		(2,665	)	1,668
Production	(29,203	)	—		(29,203	)	(1,328	)	—		(1,328	)	(11,976	)	—		(11,976	)

Acclaim Dec 31, 2005	160,254		53,144		213,398		5,511		1,868		7,379		73,308		22,659		95,967
StarPoint Dec 31, 2005	118,753		55,572		174,324		1,907		814		2,721		72,157		33,827		105,984
Canetic Dec 31, 2005	279,007		108,716		387,722		7,418		2,682		10,100		145,465		56,486		201,951

The following table sets forth the reconciliation of Acclaim’s net present value of future net revenue for the year ended December 31, 2005 using an average of the GLJ and Sproule constant price and cost estimates.

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$)

Acclaim Estimated Future Net Revenue at Beginning of Year	1,122,818

Sales and Transfers of Oil and Gas Produced, Net of Production Costs and Royalties	(201,813	)
Net Change in Prices, Production Costs and Royalties Related to Future Production	551,948
Changes in Previously Estimated Development Costs Incurred During the Period	—
Changes in Estimated Future Development Costs	(33,532	)
Extensions, Infill Drilling and Improved Recovery	153,210
Discoveries	14,288
Acquisitions of Reserves	752
Dispositions of Reserves	(12,177	)
Net Change Resulting from Revisions in Quantity Estimates	85,351
Accretion of Discount	112,282
Net Change in Income Taxes	—

Acclaim Estimated Future Net Revenue at End of Year	1,793,126
StarPoint Estimated Future Net Revenue at End of Year	1,597,906
Canetic Estimated Future Net Revenue at End of Year	3,391,032

Additional Information Relating to Reserves Data

Undeveloped Reserves

The following tables set forth the net proved undeveloped reserves and the probable undeveloped reserves, each by-product type, attributed to the Canetic Assets for the periods indicated, based on forecast prices.

Net Proved Undeveloped

Net Probable Undeveloped

Year

Light /
Medium
Crude Oil

Heavy Oil

Natural Gas

NGL

Light /
Medium
Crude Oil

Heavy Oil

Natural Gas

NGL

(Mbbls)

(MMcf)

(MBbls)

(Mbbls)

(MMcf)

(Mbbls)

2005

13,430

1,396

54,855

744

10,989

1,669

45,884

919

Canetic invests capital into development work, which moves its proved undeveloped reserves and probable reserves into the proved developed producing category. In 2005, $172.2 million was spent on capital development of the assets owned by Acclaim and approximately $320.0 million has been budgeted for development capital in 2006 with respect to the Canetic Assets. A portion of the development capital is intended to 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. Canetic’s focus for 2006 development will be in the areas of Pouce Coupe in the Northern District, Willesden Green in the Western District, as well the Southern District, the Williston Basin and Central Alberta.

Canetic 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, Canetic 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 Canetic’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%

2006	195,248	186,161	272,717	260,025	195,248	186,161
2007	52,356	45,381	102,776	89,085	51,358	44,516
2008	16,588	13,071	18,866	14,866	15,942	12,562
2009	9,813	7,030	11,082	7,939	9,249	6,626
2010	3,403	2,216	4,053	2,639	3,148	2,050
Thereafter	14,542	4,851	25,328	8,640	11,165	4,121
Total	291,950	258,711	434,822	383,194	286,110	256,037

The future development costs are capital expenditures required in the future for Canetic to convert proved non producing reserves and probable reserves into proved developed producing reserves. Canetic 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 Canetic had a working interest as at December 31, 2005.

	Oil Wells				Natural Gas Wells
	Producing		Non-Producing(1)		Producing		Non-Producing(1)
	Gross(2)	Net	Gross	Net	Gross(2)	Net	Gross	Net

Alberta	3,059	1,068	207	118	3,159	1,009	197	127
British Columbia	20	3	1	1	104	36	27	11
Saskatchewan	2,677	1,239	183	134	272	40	1	1
Manitoba	489	171	0	0	0	0	0	0
United States	20	8	17	10	190	57	17	14
Total	6,265	2,488	408	263	3,725	1,142	242	153

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.

Properties with no Attributed Reserves

The following table sets out the total land holding of proved and unproved properties held by Canetic as at December 31, 2005.

	Developed (Acres)		Undeveloped Land (Acres)		Total (Acres)
	Gross	Net	Gross	Net	Gross	Net

Alberta	1,489,705	655,174	1,050,264	559,675	2,539,969	1,214,849
British Columbia	83,878	31,667	118,869	57,447	202,748	89,114
Saskatchewan	231,086	127,642	313,677	200,071	544,763	327,713
Manitoba	37,510	13,647	9,310	3,775	46,820	17,422
Wyoming	8,546	3,430	20,326	10,141	28,872	13,571
Montana	1,520	937	3,449	1,581	4,969	2,517
North Dakota	7,506	3,736	31,855	24,328	39,361	28,064
Total	1,859,752	836,232	1,547,750	857,018	3,407,502	1,693,250

Management expects that rights to explore, develop and exploit 187,419 net acres of Canetic’s undeveloped land holdings will expire within one year.

Forward Contracts

Canetic 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. The reduction of price risk is designed to result in an enhanced degree of stability and certainty of distribution payments to Unitholders. Core to Canetic’s risk management strategy is the choice of the appropriate type of financial product at the time of execution which will give the optimal level of protection against downward price movements while maintaining as much exposure as possible to potential price increases. The objective of Canetic’s risk management team is to hedge up to 50% of Canetic’s budgeted production for the current and following year in accordance with the guidelines established by the Board of Directors.

Canetic expects to sell its physical production to independent marketers and end-users that meet Canetic’s credit and payment requirements. Canetic directs all of its crude oil and 90% of its natural gas production to the spot markets.

Additional Information Concerning Abandonment and Reclamation Costs

Future abandonment and reclamation costs for the Canetic Assets have been estimated based on actual costs incurred to date by Canetic for abandonment. Costs to abandon approximately 2,322 net producing wells totaling $161.0 million ($63.0 million discounted at 10%) are included in the estimate of future net revenue. Facility abandonment and reclamation costs of $227.8 million ($59.6 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 the Operating Entities, any taxable income that would otherwise arise in Canetic or any other affiliated entities will accrue in the Trust and will be allocated by the Trust to Unitholders. This is primarily accomplished through the payment and deduction of interest on debt or the payment of the Canetic NPI’s to the Trust. Therefore, no tax is anticipated to be incurred or paid by Canetic.

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’s activities with respect to the year ended December 31, 2005:

Year Ended December 31, 2005
Land and seismic		16,500
Exploration and development costs		155,721
Property acquisitions and dispositions		8,944
Total		181,165

Exploration and Development Activities

The following table sets forth the gross and net exploratory and development wells on the Canetic Assets in which Acclaim and StarPoint participated during the year ended December 31, 2005:

	Year Ended December 31, 2005
	Exploration Wells		Development Wells
	Gross	Net	Gross	Net
Oil	1	.3	184	121.3
Natural Gas	16	10.6	206	96
Service	0	0	13	8.3
Dry	0	0	3	1.3
Total	17	10.9	406	226.9

Production Estimates

The following table sets out the volume of the Trust’s company interest forecast pricing production estimated for 2006, which is reflected in the estimate of future net revenue disclosed in the tables contained under “Disclosure of Reserves Data”.

2006	Light and Medium Oil	Heavy Oil	Natural Gas	Natural Gas Liquids	Boe
	(Bbls/d)	(Bbls/d)	(Mcf/d)	(Bbls/d)	(Boe/d)
Proved Producing	27,226	6,589	145,870	4,728	62,855
Total Proved	31,858	7,015	164,335	5,221	71,483
Proved plus probable	35,301	7,306	179,017	5,786	78,229

Production History

The information in the following table only includes information with respect to Acclaim and its assets. The information does NOT assume that the Arrangement was completed on December 31, 2005 and does NOT assume that the properties and assets of the Operating Entities acquired pursuant to the Arrangement were acquired by the Operating Entities on December 31, 2005.

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

	Quarter Ended
	2005
	Dec 31	Sept 30	June 30	Mar 31
Average Daily Production
Light and Medium Crude Oil (Bbls/d)	12,194	12,823	13,861	14,628
Heavy Oil (Bbls/d)	4,751	4,390	4,086	4,415
Natural Gas (Mcf/d)	105,761	107,427	100,607	104,090
NGL (Bbls/d)	4,970	5,110	5,302	5,698
Combined (Boe/d)	39,542	40,228	40,017	42,089

Average Price Received (before hedging)
Light and Medium Crude Oil ($/Bbl)	68.18	72.79	60.76	57.45
Heavy Oil ($/Bbl)	36.78	49.38	33.40	30.01
Natural Gas ($/Mcf)	12.40	9.08	7.76	7.02
NGL ($/Bbl)	44.96	46.61	35.99	34.93
Combined ($/Boe)	64.35	58.76	48.74	45.20

Royalties
Light and Medium Crude Oil ($/Bbl)	12.37	14.91	12.22	11.72
Heavy Oil ($/Bbl)	5.63	7.80	4.37	3.78
Natural Gas ($/Mcf)	2.99	2.24	1.63	1.69
NGL ($/Bbl)	15.09	13.35	10.69	8.70
Combined ($/Boe)	14.38	13.27	10.19	9.81

Operating Expenses
Light and Medium Crude Oil ($/Bbl)	11.66	9.69	8.02	8.04
Heavy Oil ($/Bbl)	10.29	12.15	8.42	11.37
Natural Gas ($/Mcf)	1.58	1.71	1.71	1.60
NGL ($/Bbl)	—	—	—	—
Combined ($/Boe)	9.05	8.98	8.04	7.93

Transportation
Light and Medium Crude Oil ($/Bbl)	0.26	0.26	0.15	0.14
Heavy Oil ($/Bbl)	0.26	0.26	0.15	0.14
Natural Gas ($/Mcf)	1.79	1.12	1.30	1.18
NGL ($/Bbl)	—	—	—	—
Combined ($/Boe)	0.91	0.61	0.61	0.55

Netback Received ($/Boe)
Light and Medium Crude Oil	43.89	47.93	40.37	37.56
Heavy Oil	20.60	29.17	20.46	14.72
Natural Gas	6.04	4.01	3.12	2.55
NGL	29.87	33.26	25.30	26.23
Combined	40.01	35.90	29.90	26.91

The following table indicates Acclaim’s average daily production from its important fields for the year ended December 31, 2005:

	Light and Medium Crude Oil	Heavy Oil	Gas	NGL	BOE
	(Bbl/d)	(Bbl/d)	(MMcf/d)	(Bbls/d)	(BOE/d)

Alberta
Acheson	1,725	—	19,727	2,120	7,133
Bigoray/Brazeau	1,594	—	13,056	589	4,359
Willesden Green	1,376	—	5,274	250	2,505
Golden Spike	183	—	4,443	440	1,364
Gilby/Medicine River	427	—	5,444	65	1,399
Kaybob South	193	—	6,588	420	1,711
Simonette	880	—	1,623	121	1,272
Mitsue	1,265	—	1,454	194	1,701
Pouce Coupe	407	—	2,385	41	846
Other Properties	3,282	618	37,372	946	11,074
Total Alberta	11,332	618	97,366	5,186	33,364

Saskatchewan
Furness		1,954	52	—	1,963
Dodsland	401	—	151	—	426
Other Properties	391	1,839	289	5	2,283
Total Saskatchewan	792	3,793	492	5	4,672

British Columbia
Buick Creek	115	—	2,240	58	546
BC Minor	—	—	1,683	6	287
Other Properties	7	—	2,699	12	469
Total British Columbia	122	—	6,622	76	1,302

Manitoba
Virden	735	—	—	—	735
Other Properties	387	—	—	—	387
Total Manitoba	1,122	—	—	—	1,122

Total	13,368	4,411	104,480	5,267	40,460

Note:

(1) Production numbers reflect total production averaged over the course of the year, during which Acclaim owned the properties.

Employees

Acclaim had a total of approximately 320 full time employees and 100 persons on a contract or consulting basis at December 31, 2005.

Industry Conditions

Introduction

The oil and gas industry is subject to extensive controls and regulations governing its operations (including land tenure, exploration, development, production, refining, transportation and marketing) imposed by legislation enacted by various levels of government and with respect to pricing and taxation of oil and natural gas by agreements among the governments of Canada,

Alberta, British Columbia, Saskatchewan and Manitoba, all of which should be carefully considered by investors in the oil and gas industry. It is not expected that any of these controls and regulations will affect the operations of the Operating Entities in a manner materially different than they would affect other oil and gas companies of similar size. All current legislation is a matter of public record and Canetic is unable to predict what additional legislation or amendments may be enacted. Outlined below are some of the principal aspects of legislation, regulations and agreements governing the oil and gas industry.

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. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet certain other criteria prescribed by the NEB and the Government of Canada. As in the case with oil, natural gas exports for a term of less than 2 years or for a term of 2 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 issuance 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 of energy resources 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 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 NAFTA also contemplates clearer disciplines on regulators to ensure fair implementation of any regulatory changes and to minimize disruption of contractual arrangements and avoid undue interference with pricing, marketing and distribution arrangements, which is important for Canadian natural gas exports.

Provincial Royalties and Incentives

General

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 crude oil, natural gas, natural gas liquids and sulphur 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. 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. 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. Other royalties and royalty-like interests are from time to time carved out of the working interest owner’s interest through non-public transactions. These are often referred to as overriding royalties, gross overriding royalties, net profits interests or net carried interests.

From time to time the governments of the western Canadian provinces have established incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced recovery projects. The programs are designed to encourage exploration and development activity by improving earnings and cash flow within the industry. Royalty holidays and reductions would reduce the amount of Crown royalties paid by oil and gas producers to the provincial governments and would increase the net income and funds from operations of such producers. However, 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.

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”). In November, 2003 the Tax Act was amended to provide the following initiatives applicable to the oil and gas industry (to a maximum of $2,000,000) 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. In addition, the percentage of ARTC (as such term is defined in the section entitled “Provincial Royalties and Incentives – Alberta” below) that Canetic is required to include in federal taxable income will be 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.

Alberta

Regulations made pursuant to the Mines and Minerals Act (Alberta) provide various incentives for exploring for and developing oil reserves in Alberta. Oil produced from horizontal extensions commenced at least 5 years after the well was originally spudded may also qualify for a royalty reduction. A 24 month, 8,000 m³ exemption is available to production from a reactivated well that has not produced for: (i) a 12 month period, if resuming production in October, November or December of 1992 or January, 1993; or (ii) a 24 month period, if resuming production in February 1993 or later. As well, oil production from eligible new field and new pool wildcat wells and deeper pool test wells spudded or deepened after September 30, 1992 is entitled to a 12 month royalty exemption (to a maximum of $1 million). Oil produced from low productivity wells, enhanced recovery schemes (such as injection wells) and experimental projects is also subject to royalty reductions.

The Alberta government has also introduced a Third Tier Royalty with a base rate of 10% and a rate cap of 25% for oil pools discovered after September 30, 1992. The new oil royalty reserved to the Crown has a base rate of 10% and a rate cap of 30%. The old oil royalty reserved to the Crown had a base rate of 10% and a rate cap of 35%.

In Alberta, the royalty reserved to the Crown in respect of natural gas production, subject to various incentives, is between 15% and 30%, in the case of new natural gas, and between 15% and 35%, in the case of old natural gas, depending upon a prescribed or corporate average reference price. Natural gas produced from qualifying intervals in eligible gas wells spudded or deepened to a depth below 2,500 meters 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 is entitled to a credit on qualified oil and natural gas production against the royalties payable to the Crown by virtue of the Alberta royalty tax credit (“ARTC”) program. The ARTC rate is based on a price sensitive formula and the ARTC rate varies between 75% at prices at and below $100 per cubic meter and 25% at prices at and above $210 per cubic meter. In general, the ARTC program provides a rebate on Alberta Crown royalties paid in respect of eligible producing properties. The ARTC rate is 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 a corporation 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 was conducting 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 for the program. Canetic believes that such rules will not presently preclude the Operating Entities from being eligible for the ARTC program.

British Columbia

Producers of oil and natural gas in the Province of British Columbia are also required to pay annual rental payments in respect of the 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 type of oil, the value of the oil, the quantity of oil produced in a month and the vintage of the oil. Generally, the vintage of oil is based on the determination of whether the oil is produced from a pool discovered before October 31, 1975 (old oil) between October 31, 1975 and June 1, 1998 (new oil) or after June 1, 1998 (third-tier oil). Oil produced from newly discovered pools may be exempt from the payment of a royalty for the first 36 months of production. 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. As an incentive for the production and marketing of natural gas, which may have been flared, natural gas produced in association with oil has a lower royalty then the royalty payable on non-conservation gas.

On May 30, 2003, the Ministry of Energy and Mines for the province of British Columbia announced an Oil and Gas Development Strategy for the Heartlands (“Strategy”). The Strategy is a comprehensive program to address road infrastructure, targeted royalties, regulatory reduction and British Columbia service sector opportunities. In addition, the Strategy will result in economic and employment opportunities for communities in British Columbia’s heartlands.

Some of the financial incentives in the Strategy include:

Royalty credits of up to $30 million annually towards the construction, upgrading and maintenance of road infrastructure in support of resource exploration and development. Funding will be contingent upon an equal contribution from industry.

Changes to provincial royalties: new royalty rates for low productivity natural gas to enhance marginally economic resources plays, royalty credits for deep gas exploration to locate new sources of natural gas, and royalty credits for summer drilling to expand the drilling season.

Saskatchewan

In Saskatchewan, the amount payable as a royalty in respect of oil depends on the vintage of the oil, the type of oil, the quantity of oil produced in a month and the value of the oil. For Crown royalty and freehold production tax purposes, crude oil is considered “heavy oil”, “southwest designated oil” or “non heavy oil other than southwest designated oil”. The conventional royalty and production tax classifications (“fourth tier oil” introduced October 1, 2002, “third tier oil”, “new oil” or “old oil”) of oil production are applicable to each of the three crude oil types. The Crown royalty and freehold production tax structure for crude oil is price sensitive and varies between the base royalty rates of 5% for all “fourth tier oil” to 20% for “old oil”. Marginal royalty rates are 30% for all “fourth tier oil” to 45% for “old oil”.

The amount payable as a royalty in respect of 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), the quantity produced in a given month, the type of natural gas and the vintage of the natural gas. As an incentive for the production and marketing of natural gas which may have been flared, the royalty rate on natural gas produced in association with oil is less than on non-associated natural gas. The

royalty and production tax classifications of gas production are “fourth tier gas” introduced October 1, 2002, “third tier gas”, “new gas” and “old gas”. The Crown royalty and freehold production tax for gas is price sensitive and varies between the base royalty rate of 5% for “fourth tier gas” and 20% for “old gas”. The marginal royalty rates are between 30% for “fourth tier gas” and 45% for “old gas”.

On October 1, 2002, the following changes were made to the royalty and tax regime in Saskatchewan:

A new Crown royalty and freehold production tax regime applicable to associated natural gas (gas produced from oil wells) that is gathered for use or sale. The royalty/tax will be payable on associated natural gas produced from an oil well that exceeds approximately 65 thousand cubic meters in a month.

A modified system of incentive volumes and maximum royalty/tax rates applicable to the initial production from oil wells and gas wells with a finished drilling date on or after October 1, 2002 was introduced. The incentive volumes are applicable to various well types and are subject to a maximum royalty rate of 2.5% and a freehold production tax rate of zero per cent.

The elimination of the re entry and short section horizontal oil well royalty/tax categories. All horizontal oil wells with a finished drilling date on or after October 1, 2002 will receive the “fourth tier” royalty/ tax rates and new incentive volumes.

Manitoba

In Manitoba, a holder of a lease or of an exploration reservation in respect of Crown oil and gas rights is required to pay royalties and a holder of freehold lands is required to pay freehold production taxes.

In Manitoba, Crown royalties pursuant to oil produced on Crown lands is calculated by means of a formula which attaches a multiplying factor depending on the classification of the oil. The oil is classified as either old oil, new oil, third tier oil or holiday oil, and the multiplying factor attached to each is 1.0, 0.55, 0.47 and 0.00 respectively. The Crown royalty volume incorporates the multiplying factor of the classification of oil by utilizing one of two formulas, depending on whether the monthly volume of oil in cubic meters produced from a spacing unit is: (1) 50 or less; or (2) more than 50. As a result of the holiday oil multiplying factor being 0.00, no Crown royalties are payable with respect to holiday oil.

As with Crown royalties, a similar calculation scheme exists for taxation of oil produced pursuant to freehold oil rights. These tax rates are also dependent upon the categorization of the oil, being either old oil, new oil, third tier oil or holiday oil. The tax rate on holiday oil, like the Crown royalty rate, is zero.

In Manitoba, Crown royalties to be paid by the holder of a lease or an exploration reservation in respect of Crown gas rights is the amount equal to 12 1/2% of the volume sold, calculated for each producing month to the nearest 0.001 thousand cubic meters.

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 to 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 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.

Environmental legislation in the Province of Alberta has been consolidated into the Environmental Protection and Enhancement Act (Alberta) (the “APEA”), which came into force on September 1, 1993 and the Oil and Gas Conservation Act (Alberta) (the “OGCA”). The APEA and OGCA impose stricter environmental standards, require more stringent compliance, reporting and monitoring obligations and significantly increase penalties. Canetic is committed to meeting its responsibilities to protect the environment wherever it operates and anticipates making increased expenditures of both a capital and an expense nature as a result of the increasingly stringent laws relating to the protection of the environment. Canetic will be taking such steps as required to ensure compliance with the APEA and similar legislation in other jurisdictions in which it operates. Canetic believes that it is in material compliance with applicable environmental laws and regulations. Canetic also believes that it is reasonably likely that the trend towards stricter standards in environmental legislation and regulation will continue.

British Columbia’s Environmental Assessment Act became effective June 30, 1995. This legislation rolls the previous processes for the review of major energy projects into a single environmental assessment process with public participation in the environmental review process.

In December, 2002, the Government of Canada ratified the Kyoto Protocol (“Protocol”). The Protocol calls for Canada to reduce its greenhouse gas emissions to 6% below 1990 “business-as-usual” levels between 2008 and 2012. Given revised estimates of Canada’s normal emissions levels, this target translates into an approximately 40% gross reduction in Canada’s current emissions. In April, 2005, Environment Canada released “Project Green”, a working paper giving early indications of how implementation was to be achieved. Large Final Emitters (“LFEs”), being 700 of Canada’s largest emitters, will receive a specific reduction target of 45 megatonnes, and will have the opportunity to purchase domestic offset and technology credits. The exact mechanism for operating in the domestic credit market has yet to be revealed, and the prospect of non-LFE enterprise participating in that market to any great extent is uncertain. Various incentive funds have also been established to provide seed funding for the purchase of experimental technologies, encourage investment in alternative energy sources, and acquire credits from the domestic and international markets for re-sale to Canadian enterprise.

Environment Canada, in August, 2005, released consultation papers for the management of a system of greenhouse gas offsets in the form of tradable and bankable credits. The credits are created by enterprise, individuals, or municipal government through the implementation of projects registered with the to-be-created offset authority. Standards for quantifying greenhouse gas reductions were also proposed in the consultation paper.

Proposed Changes to Well Spacing Application Process

Following an internal review of the well spacing process the EUB proposed four changes as part of an ongoing commitment to continuous improvements to the EUB’s regulations and processes. Stakeholders had an opportunity to provide comments on the proposed changes until April 22, 2005. The proposed changes have not officially become regulations and are still in their extended consultation period. They deal with changes to the notification process, higher baseline well densities, application processing paths and process automation.

In terms of notification it will require industry pre-application notification to potentially affected subsurface parties only. There will also be higher baseline well densities in that part of Alberta east of the 5^th Meridian and south of Township 53 in the Mannville and shallower formations. For gas wells there will be: (i) maximum 4 wells per pool per section above the Mannville group; and (ii) maximum 2 wells per pool per section for the Mannville group; and (iii) a standard buffer zone will be 300 meters on the south and west sides of the section. For oil wells there will be: (i) maximum 2 wells per pool per quarter section for the Mannville group; and (ii) standard buffer zone will be 200 meters on the south and east sides of the quarter section.

Application processing paths will adopt an application process model with three risk-based paths – routine, standard and non-routine – that would reflect the complexity of different conditions of the reservoir. There will also be streamlining of the processes by providing enhanced electronic application submission forms, automated well spacing orders, and Web-based well spacing information.

Trends

There are a number of trends that have been developing in the oil and gas industry during the past several years that appear to be shaping the near future of the business.

The first trend is the volatility of commodity prices. Natural gas is a commodity influenced by factors within North America. The continued tight supply demand balance for natural gas is causing significant elasticity in pricing. Despite record drilling activity, a strong economy, weather, fuel switching and demand for electrical generation there still exists a tight supply causing prices to remain high.

Crude oil is influenced by the world economy and OPEC’s ability to adjust supply to world demand. Recently crude oil prices have been kept high by political events causing disruptions in the supply of oil, and concern over potential supply disruptions triggered by unrest in the Middle East. Political events trigger large fluctuations in price levels.

The impact on the oil and gas industry from commodity price volatility is significant. During periods of high prices, producers generate sufficient cash flows to conduct active exploration programs without external capital. Increased commodity prices frequently translate into very busy periods for service suppliers triggering premium costs for their services. The price of land and properties similarly increases during these periods. During low commodity price periods, acquisition costs drop, as do internally generated funds to spend on exploration and development activities. With decreased demand, the prices charged by the various service suppliers also decline.

A second trend within the Canadian oil and gas industry is recent growth in the number of private and small junior oil and gas companies starting up business. These companies often have experienced management teams from previous industry organizations that have disappeared as a part of the ongoing industry consolidation. Many are able to raise capital and recruit well qualified personnel.

A third trend currently affecting the oil and gas industry is the impact on capital markets caused by investor uncertainty in the North American economy. The capital market volatility in Canada has also been affected by uncertainties surrounding the economic impact that the Protocol will have on the sector. Generally during the past year, the economic recovery combined with increased commodity prices has caused an increase in new equity financings in the oil and gas industry. Canetic must compete with the numerous new companies and their new management teams and development plans in its access to capital. The competitive nature of the oil and gas industry will cause opportunities for equity financings to be selective. Some companies will have to rely on internally generated funds to conduct their exploration and developmental programs.

ADDITIONAL INFORMATION RESPECTING CANETIC RESOURCES 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 are 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 rank among themselves equally and ratably without discrimination, preference or priority. Each Unit is transferable, is not 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 also, “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.

As at March 24, 2006, approximately 201.0 million Units were outstanding, 3.0 million Units were reserved for issuance on conversion of the Convertible Debentures (as defined herein) and approximately 10.0 million Units were remaining available for future issuance pursuant to the Unit Award Incentive Plan (subject to increase in accordance with such plan). See also, “Additional Information Respecting Canetic Resources Inc. – Share Capital of Canetic Resources Inc.” 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 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 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.

No Special Voting Units are issued and outstanding.

Convertible Debentures of the Trust

The Trust has four series of convertible debentures outstanding, the 8% Debentures, the 11% Debentures, the 6.5% Debentures and the 9.4% Debentures (collectively, the “Convertible Debentures”). The following is a summary of the material attributes and characteristics of the Convertible Debentures.

The 8% Debentures were originally issued in the aggregate principal amount of $75 million and approximately $10.3 million principal amount was outstanding at March 24, 2006. The 8% Debentures mature on August 31, 2009.

The 11% Debentures were originally issued in the aggregate principal amount of $45 million and approximately $2.0 million principal amount was outstanding at March 24, 2006. The 11% Debentures mature on December 31, 2007.

The 6.5% Debentures were originally issued in the aggregate principal amount of $60 million and approximately $34.3 million principal amount was outstanding at March 24, 2006. The 6.5% Debentures mature on July 31, 2010.

The 9.4% Debentures were originally issued in the aggregate principal amount of $50 million and approximately $7.1 million principal amount were outstanding at March 24, 2006. The 9.4% Debentures mature on July 31, 2008.

Terms 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 6.5% Debentures bear interest from the date of issue at 6.5% per annum, which is payable semi-annually in arrears on January 31 and July 31 in each year. The 9.4% Debentures bear interest from the date of issue at 9.4% per annum, which is payable semi-annually in arrears on January 31 and July 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 Interest 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 indentures governing the Convertible Debentures 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 currently 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 Canetic for redemption of the 8% Debentures, at a conversion price of $15.56 per Unit, being a conversion rate of approximately 64.27 Units for each $1,000 principal amount of 8% Debentures.

The 11% Debentures are currently 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 Canetic for redemption of the 11% Debentures, at a conversion price of $11.24 per Unit, being a conversion rate of approximately 88.97 Units for each $1,000 principal amount of 11% Debentures.

The 6.5% Debentures are currently convertible at the holder’s option into fully paid and non-assessable Units at any time prior to the close of business on the earlier of July 31, 2010 and the business day immediately preceding the date specified by Canetic for redemption of the 6.5% Debentures, at a conversion price of $18.96 per Unit, being a conversion rate of approximately 52.74 Units for each $1,000 principal amount of 6.5% Debentures.

The 9.4% Debentures are currently convertible at the holder’s option into fully paid and non-assessable Units at any time prior to the close of business on the earlier of July 31, 2008 and the business day immediately preceding the date specified by Canetic for redemption of the 9.4% Debentures, at a conversion price of $16.02 per Unit, being a conversion rate of approximately 62.42 Units for each $1,000 principal amount of 9.4% 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.

Redemption and Purchase

The 8% Debentures are not redeemable on or before August 31, 2007. After August 31, 2007 and prior to maturity, the 8% 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.

The 6.5% Debentures are not redeemable on or before July 31, 2008. The Trust may, on not more than 60 days and not less than 30 days prior notice, redeem the 6.5% Debentures at a redemption price of $1,050 per 6.5% Debenture after July 31, 2008, and on or before July 31, 2009, and at a price of $1,025 per Debenture after July 31, 2009 and before July 31, 2010 (each a “6.5% Redemption Price”), plus accrued and unpaid interest thereon, if any.

The 9.4% Debentures are not redeemable on or before July 31, 2006. The Trust may, on not more than 60 days and not less than 30 days prior notice, redeem the 9.4% Debentures at a redemption price of $1,050 per 9.4% Debenture after July 31, 2006, and on or before July 31, 2007, and at a price of $1,025 per Debenture after July 31, 2007 and before July 31, 2008 (each a “9.4% Redemption Price”), 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, or less than all of the 6.5% Debentures or 9.4% Debentures, as the case may be, the 8% Debentures or 11% Debentures, as the case may be, to be redeemed or the 6.5% Debentures or the 9.4% Debentures, as the case may be, to be redeemed, will be selected by the trustee appointed under the applicable Convertible Debenture indenture (the “Debenture Trustee”) on a pro rata basis or in such other manner as the 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 Debentures 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 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 the 6.5% Debentures) and subject to applicable regulatory approval, elect to satisfy its obligation to pay the applicable 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 Convertible 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 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, by 95% of the Current Market Price of the Units 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 Convertible 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 Convertible 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 Convertible Debenture indentures 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 Convertible 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 respect of any of the Convertible Debentures or any unpaid interest accrued thereon. The Convertible 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 Convertible 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 Control of 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, the 11% Debentures, the 6.5% Debentures or the 9.4% 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, the 11% Debentures, the 6.5% Debentures or the 9.4% Debentures, as applicable, 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 Convertible 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 Convertible Debenture indenture (the “Unit Interest Payment Election”). The Convertible 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 applicable 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 of Default

The Convertible 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 Convertible Debenture Indentures and continuance of such default for a period of 30 days after 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 Convertible Debenture indentures contain provisions to the effect that if an offer is made for the 8% Debentures or the 11% Debentures or the 6.5% Debentures or the 9.4% 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 Convertible 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 Convertible Debenture indentures. For that purpose, among others, the Convertible 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 Convertible 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 Debenture of the Trust exceeds 25% of the Total Market Capitalization of the Trust immediately after the issuance of such additional Convertible Debenture. “Total Market Capitalization” is defined in the Convertible Debenture indentures as the total principal amount of all issued and outstanding Convertible 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

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 (40% in the case of the 6.5% Convertible Debentures) and, 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 holder of 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.

Book-Entry System for Convertible Debentures

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

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 may determine.

Cash Distributions

Cash distributions are made on or about the 15th day of each month to Unitholders of record on the immediately preceding distribution record date. The Trust currently distributes $0.23 per Unit per month. It is anticipated that this distribution policy will result in a 2006 payout ratio of approximately 60% to 65% based on a commodity price forecast of US$62 WTI for oil and C$8.25 AECO for natural gas. Future distributions and the actual payout ratio will be subject to the discretion of the Board of Directors and may vary depending on, among other things, the current and anticipated commodity price environment. See also, “Risk Factors”.

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 Canetic 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 the Trust distributing Redemption Notes having an aggregate principal amount equal to the aggregate Market Redemption Price of the Units tendered for redemption.

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 Canetic 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 Canetic 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. Redemption Notes that may be distributed to Unitholders in connection with a redemption will not be listed on any stock exchange and no market is expected to develop in such Redemption Notes. Redemption Notes will not be qualified investments for trusts governed by registered retirement savings plans, registered retirement income funds and deferred profit sharing plans.

Restrictions on Non Resident Ownership

However, there is currently an exception to the non-resident ownership restriction in paragraph 132(7)(a) of the Tax Act where not more than 10% of the trust’s property has at any time consisted of “taxable Canadian property”.

In accordance with the Trust Indenture, in order to ensure the maintenance of the Trust’s “mutual fund trust” status Canetic will: (i) prior to the completion of any transaction involving the acquisition by the Trust of any Subsequent Investment; (ii) prior to any material modification to the Trust Fund (as defined in the Trust Indenture) other than as contemplated by subclause (i); (iii) promptly following (a) any proposed amendment to paragraph 132(7)(a) of the Tax Act (which provision relates to the level of “taxable Canadian property”), (b) any other proposed amendment to the Tax Act which impacts on paragraph 132(7)(a) of the Tax Act or otherwise imposes restrictions on non-resident ownership of units of a mutual fund trust or (c) the publication of any administrative bulletin or other notice of interpretation relating to the interpretation or application of such paragraph; or (iv) otherwise at any time when requested by the Trustee, Canetic will obtain an opinion of counsel confirming whether the Trust is, at the date thereof and following such transaction or event (which in the case of (iii) shall mean the coming into effect of the amendment or change of interpretation), still qualifies as a mutual fund trust under the Tax Act.

If at any time the Board of Directors determines, in its sole discretion, or becomes aware that the Trust’s ability to continue to rely on paragraph 132(7)(a) of the Tax Act (or any successor provision thereto) for purposes of qualifying as a “mutual fund trust” thereunder is in jeopardy, then forthwith after such determination it shall be the sole responsibility of Canetic to monitor the holdings by Non-Residents and Canetic will take such steps as are necessary or desirable to ensure that the Trust is not maintained primarily for the benefit of Non-Residents or that the Trust is otherwise able to continue to qualify as a “mutual fund trust” for the purposes of the Tax Act.

Canetic may, at any time and from time to time, in its sole discretion, request that the Trustee make reasonable efforts, as practicable in the circumstances, to obtain declarations as to beneficial ownership, perform residency searches of Unitholders and beneficial Canetic mailing address lists, and take such other steps specified by Canetic, at the cost of the Trust, to determine or estimate as best possible the residence of the beneficial owners of the Units.

If at any time the Board of Directors, in its sole discretion, determines that it is in the best interest of the Trust, Canetic, notwithstanding the ability of the Trust to continue to rely on subsection 132(7)(a) of the Tax Act for the purpose of qualifying as a “mutual fund trust” under the Tax Act, may (i) require the Trustee to refuse to accept a subscription for Units from, or issue or register a transfer of Units to, a person unless the person provides a declaration to Canetic that the Units to be issued or transferred to such person will not when issued or transferred be beneficially owned by a Non-Resident; (ii) to the extent practicable in the circumstances, send a notice to registered holders of Units which are beneficially owned by Non-Residents, chosen in inverse order to the order of acquisition or registration of such Units beneficially owned by Non-Residents or in such other manner as Canetic may consider equitable and practicable, requiring them to sell their Units which are beneficially owned by Non-Residents or a specified portion thereof within a specific period of not less than 60 days. If the Unitholders receiving such notice have not sold the specified number of such Units or provided Canetic with satisfactory evidence that such Units are not beneficially owned by Non-Residents within such period, Canetic may, on behalf of such registered Unitholder, sell such Units and, in the interim, suspend the voting and distribution rights attached to such Units and 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 may 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 so disposed of and their rights shall be limited to receiving the net proceeds of sale, and any distribution in respect thereof deposited as aforesaid, net of applicable taxes and costs of sale, upon surrender of the certificates representing such Units; (iii) delist the Units from any non-Canadian stock exchange; and (iv) take such other actions as the Board of Directors determines, in its sole discretion, are appropriate in the circumstances that will reduce or limit the number of Units held by Non-Residents to ensure that Canetic is not maintained primarily for the benefit of Non-Residents.

Notwithstanding any other provision of the Trust Indenture, Non-Resident Unitholders, whether registered holders or beneficial holders of Trust Units, are not be entitled to vote in respect of any Special Resolutions to amend the provisions of the Trust Indenture relating to restrictions on Non Resident ownership.

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 and the appointment of

the auditors of the Trust. At every second meeting of Unitholders, Unitholders will be asked to re-appoint, or appoint the successor to, the Trustee.

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 20% 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 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”). 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 initial term of the Trustee’s appointment is until the second annual meeting of Unitholders. The Unitholders shall, at the second annual meeting of the Unitholders, re-appoint, or appoint a successor to the Trustee for an additional two year term, and thereafter, the Unitholders shall reappoint or appoint a successor to the Trustee at the annual meeting of Unitholders two years following the reappointment or appointment of the successor to the Trustee. The Trustee may resign on giving not less than 60 days’ notice in writing to Canetic . The Trustee may also be removed by Special Resolution of the Unitholders. Such resignation or removal shall not become effective until (a) the appointment of, and acceptance of such appointment by, a new Trustee in the place of the resigning Trustee or the Trustee to be removed, and (b) a legal and valid assumption by the new Trustee of all obligations of the Trustee related thereto in the same capacities as the resigning Trustee or the Trustee to be removed.

Delegation of Authority, Administration and Trust Governance

The Board of Directors has been generally delegated the significant management decisions of the Trust and Canetic has been retained to administer the Trust on behalf of the Trustee. In particular, the Trustee has delegated to Canetic 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

Canetic currently has a board of directors consisting of nine individuals. Unitholders are entitled to elect the board of directors of Canetic. See also, “Additional Information Respecting Canetic Resources Inc.”.

Decision Making

The Board of Directors supervises the management of the business and affairs of Canetic, including the business and affairs of the Trust delegated to Canetic. Pursuant to the Administration Agreement, the Trustee has delegated certain matters to the Board of Directors including all decisions relating to: (i) issuance of additional Units; and (ii) the determination of the amount of distributable cash.

Liability of the Trustee

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 Trust Fund (as defined in the Trust Indenture), arising from the exercise by the Trustee of any powers, authorities or discretion conferred under the Trust Indenture, including, without limitation, entering into the Administration Agreement and relying on Canetic thereunder, 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 Trust Fund incurred by reason of the sale of any asset, any inaccuracy in any evaluation provided by any appropriately qualified person, any reliance on any such evaluation, any action or failure to act of Canetic, or any other person to whom the Trustee has, with the consent of Canetic, delegated any of its duties under the Administration Agreement, 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 Canetic to perform its duties under or delegated to it under the Trust Indenture or any other contract), including anything done or permitted to be done pursuant to, or any error or omission relating to, the rights, powers, responsibilities and duties conferred upon, granted, allocated and delegated to Canetic under the Trust Indenture or under the Administration Agreement, or the act of agreeing to the conferring upon, granting, allocating and delegating any such rights, powers, responsibilities and duties to Canetic in accordance with the terms of the Trust Indenture or under the Administration Agreement, unless such liabilities arise out of the negligence, wilful default or fraud of the Trustee or any of its directors, officers, employees, shareholders, or agents. If the Trustee has retained an appropriate expert or adviser or legal counsel with respect to any matter connected with its duties under the Trust Indenture or any other contract, the Trustee may act or refuse to act based on the advice of such expert, adviser or legal counsel, and notwithstanding any other provision of the Trust Indenture, 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 Trust Fund.

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) amending, modifying or changing any provisions of the Trust Indenture that are necessary or desirable in the opinion of the Canetic as a result of amendments to the Tax Act, the regulations thereunder or the interpretation thereof including, without limitation, amendments or changes relating to eligibility for investment and the requirements to maintain the Trust’s status as a “unit trust” and a “mutual fund trust” for purposes of the Tax Act;

(e) 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;

(f) providing for, or amending the provisions of the Trust Indenture for, the electronic delivery by the Trust to Unitholders of documents relating to the Trust (including annual and quarterly reports, including financial statements, notices of Unitholder meetings and information circulars and proxy related materials) at such time as applicable securities laws have been amended to permit such electronic delivery in place of normal delivery procedures, provided that such amendments to the Trust Indenture are not contrary to or do not conflict with such laws;

(g) 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;

(h) making any modification in the form of unit certificates to conform with the provisions of the Trust Indenture, or any other modifications, provided the rights of the Trustee and of the Unitholders are not prejudiced thereby; and

(i) changing the situs of the Trust or the governing laws of the Trust, which, in the opinion of the Trustee, are, necessary or desirable in order to provide Unitholders with the benefit of any legislation limiting their liability.

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.

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 are 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 of applicable securities legislation.

Management of the Trust

Pursuant to the provisions of the Administration Agreement, Canetic provides certain management, administrative and support services to the Trust, including those necessary: (a) to ensure compliance by the Trust with continuous 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 is required to approve all matters referred to in items (d), (e) and (f) above.

ADDITIONAL INFORMATION RESPECTING CANETIC RESOURCES INC.

Management of Canetic

The name, municipality of residence, principal occupation for the prior five years and position, of each of the persons who is a director or officer of Canetic is as follows:

Name and Municipality of Residence	Position with Canetic	Principal Occupation During the Past Five Years

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 AEI, a predecessor of Canetic, and prior thereto, Chairman of Danoil, also a predecessor of Canetic. Mr. Brawn has 48 years experience in the oil and gas industry. He is also a Director of ATB Financial, a provincially owned financial institution; Parkland Industries Ltd., a retail oil marketing 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.

J. Paul Charron, B.Comm, C.A. Calgary, Alberta	President, Chief Executive Officer and Director	President and Chief Executive Officer of Canetic since January 5, 2006. President and Chief Executive Officer of AEI 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.

Paul Colborne(2)(5) Calgary, Alberta	Director	Chairman of the Board and Chief Executive Officer of TriStar since January 5, 2006. President and Chief Executive Officer of SEL, a predecessor of Canetic, from January 2005 to December 2005. From September 2003 to January 2005, President and Chief Executive Officer of StarPoint Energy Ltd, a predecessor of Canetic. From June 2001 to September 2003, President, Chief Executive Officer and a director of Crescent Point Energy Ltd. From 1993 to February 2001, President and Chief Executive Officer of Startech Energy Inc.

W. Peter Comber, MBA, C.A. (1)(3) Toronto, Ontario	Director	Managing Director of Barrantagh Investment Management Inc. (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 AEI in January 2003.

Daryl Gilbert, P. Eng. (1)(2)(5) Calgary, Alberta	Director	Businessman from January 2005 and prior thereto President and Chief Executive Officer GLJ Petroleum Consultants Ltd. (formerly 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. and Chamaelo Exploration Ltd. (public oil and gas companies).

Name and Municipality of Residence	Position with Canetic	Principal Occupation During the Past Five Years

Murray M. Frame, B. Sc. (Honours) (2)(4)(5) Calgary, Alberta	Director	Chairman and Chief Executive Officer of Canoil Inc. (a private oil and gas company) since 2002. Prior thereto President and Chief Executive Officer of Canoil Energy Corporation (a private oil and gas company) from 1996-2001 and prior thereto held positions of Vice-President Exploration, Executive Vice-President and Chief Operating Officer, President and Chief Operating Officer of Inverness Petroleum Ltd. (a public oil and gas company) from 1981 to 1996. Mr. Frame has 32 years of experience in the oil and gas industry.

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 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., Calgary Technologies Inc. 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.

Jack C. Lee, B.A., B.Comm(1)(2)(3)(4)(5) Calgary, Alberta	Chairman of the Board and Director	Corporate director since October 1, 2002, President and Chief Executive Officer of AEI from April 20, 2001 until October 1, 2002 and prior thereto President and Chief Executive Officer of Danoil Energy Ltd. 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. (private oil and gas company) Mr. Lee is also a Director of Darian Resources Ltd. (private oil and gas company).

R. Gregory Rich, P.Eng.(3)(4) 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. (a 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.

David J. Broshko, B. Comm, C.A. Calgary, Alberta	Vice President, Finance and Chief Financial Officer	Chief Financial Officer of Canetic since January 5, 2006. Chief Financial Officer of AEI since May 5, 2003. Prior thereto Chief Financial Officer of Paramount Resources Ltd. (oil and gas company).

Richard J. Tiede, P.Eng. Calgary, Alberta	Vice President, Business Development	Vice President, Business Development of Canetic since January 5, 2006. Vice President, Business Development of AEI since October 1, 2002. President and Chief Operating Officer of Landover Energy Inc. (oil and gas company) from January 2000 to June 2002. Manager of Engineering, Vice President, Engineering and Chief Engineer of Northrock Resources Ltd. (oil and gas company) from December 1993 until January 2000.

Mark P. Fitzgerald, MBA, P.Eng. Calgary, Alberta	Vice President, Operations	Vice President, Operations of Canetic since January 5, 2006. Vice President, Operations of AEI since February 15, 2005. Formerly Vice President, Engineering of AEI since April 1, 2004 and Manager, Western District of AEI 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).

Name and Municipality of Residence	Position with Canetic	Principal Occupation During the Past Five Years

Brian D. Evans, BA, LLB Calgary, Alberta	Vice President, General Counsel & Secretary	Vice President, General Counsel and Security of Canetic since January 5, 2006. Vice President, General Counsel & Secretary of AEI since April 2005. Prior to joining AEI Mr. Evans practiced law with Burnet, Duckworth & Palmer LLP where he advised clients, including Acclaim, in the areas of mergers and acquisitions and energy law. Prior thereto he practiced oil & gas law with Evans Higa Burgess LLP between October 1992 and April 2004.

Wes Morningstar, P. Geol. Calgary, Alberta	Vice President, Exploitation	Vice President, Exploitation of Canetic since January 5, 2006. Vice President, Exploitation of AEI since May, 2005. Formerly Vice-President, Exploration and Development of AEI since August 2003. Manager, Geology and Geophysics of AEI 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. (an oil and gas company) from June 1998 to June 2001.

Keith Rockley Calgary, Alberta	Vice President, Human Resources and Corporate Administration	Vice President, Human Resources and Corporate Administration of Canetic since January 5, 2006. Vice-President Human Resources and Corporate Administration of AEI since November 2005. President of Human Resource Solutions Inc., a private consulting business, from April 2005 to October 2005. Manager, Human Resources, Husky Energy Inc. from August 2000 to March 2005 and Manager, Human Resources and Corporate Administration, Renaissance Energy Ltd. from January 1996 to July 2000.

Don Robson Calgary, Alberta	Vice President, Land	Vice President, Land of Canetic since January 5, 2006. Vice President, Land of AEI since November 2005. Manager Land Negotiations and Director of Land of AEI from September 2004 to November 2005. Land Manager Energy North Inc. from February 2001 to September 2004 and Land Manager, Renaissance Energy Ltd. from January 1986 to December 2000.

Dave Sterna Calgary, Alberta	Vice President, Corporate Planning and Marketing	Vice President, Corporate Planning and Marketing of Canetic since January 5, 2006. Vice President, Corporate Planning and Marketing of AEI since November 2005. Prior thereto Director of Marketing for AEI since September 2004. Director of Marketing for Calpine Canada from November 2001 to October 2004 and Manager of Risk Management and Liquids Marketing for Encal Energy Ltd. from April 1998 to November 2001.

Note:

(1) Member of the Audit Committee (W. Peter Comber, Chair).

(2) Member of the Reserves Committee (Daryl Gilbert, Chair).

(3) Member of the Human Resources and Compensation Committee (Nancy M. Laird, Chair).

(4) Member of the Nominating and Corporate Governance Committee (R. Gregory Rich, Chair).

(5) Member of the Health, Safety and Environment Committee (Murray M. Frame, Chair).

(6) Mr. Gilbert is a director of Global 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.

As at March 24, 2006, number of Units beneficially owned, directly or indirectly, by all of the directors and officers of Canetic is approximately 2,845,194 million Units (approximately 1.4% of the issued and outstanding Units).

Share Capital of Canetic

The authorized capital of Canetic consists of an unlimited number of Canetic Common Shares, an unlimited number of non-voting common shares 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 Canetic Common Share entitles its holder to receive notice of and to attend all meetings of shareholders of Canetic and to one vote at such meetings. The holders of Canetic Common Shares are, at the discretion of the Board of Directors and subject to the rights of holders of the exchangeable shares and applicable legal restrictions, entitled to receive any dividends or other distributions declared by the Board of Directors on the Canetic Common Shares. The holders of Canetic Common Shares are, subject to the rights of holders of the exchangeable shares, entitled to share equally in any distribution of the assets of Canetic upon the liquidation, dissolution or winding-up of Canetic or other distribution of its assets among its shareholders for the purpose of winding-up its affairs. All of the issued and outstanding Canetic Common Shares are owned by the Trust.

Non-voting Common Shares

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

Exchangeable Shares

The exchangeable shares 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 Canetic. The Board of Directors has the authority to fix the number and particular rights, privileges, restrictions and conditions attaching to each series of the exchangeable shares. No exchangeable shares have been issued.

AUDIT COMMITTEE INFORMATION

The full text of the audit committee mandate is included in Appendix C of this Annual Information Form.

Composition of the Audit Committee

The audit committee consists of four members, all of whom are independent and financially literate in accordance with the definitions in Multilateral Instrument 52-110 Audit Committees. The relevant education and experience of each audit committee member is outlined below:

Robert G. Brawn

Mr. Brawn has a degree in Chemical Engineering and has been employed in the oil industry for 48 years. He has been president and or chairman of Turbo Resources Ltd., Merland Exploration Ltd., Bankeno Mines Ltd., OMV Canada Ltd (Canadian subsidiary of the Austrian National Oil Company), Danoil Energy Ltd. and AEI (predecessor companies to Canetic) and he is presently Chairman of Grande Cache Coal Corporation. All of these companies with the exception of OMV have been Canadian listed public companies. Mr. Brawn currently serves as a director of the following listed companies: Zapata Energy Ltd, Parkland Income Trust, ATB Financial (provincially owned bank), numerous private corporations and has or is currently serving on the audit committee of Parkland, Zapata, Canetic, Grande Cache, the Calgary Airport Authority. He is also formerly a director and was on the audit committees of Canadian Foremost Industries (Machinery manufacturer), Forzani Group Ltd. (retailer), Churchill Corporation (Engineering/construction contractor) and United Inc. (property developer). He has also been Chairman / President of the Calgary Chamber of Commerce, Van Horne Institute (transportation policy), Calgary Economic Development Authority, Independent Petroleum Association of Canada, Springbank Park for all Seasons and is a member of the World Business Organization and the Alberta Economic Development Authority.

W. Peter Comber (Audit Committee Chair)

Mr. Comber holds a Bachelor of Arts degree from the University of Toronto, a Masters of Business Administration from York University and is a Chartered Accountant. Mr. Comber has been engaged in various aspects of the financial services industry since 1965, first as a chartered accountant, then in corporate finance in Toronto and Calgary and then in investment management, as an investment counselor. Since August 1999 Mr. Comber has been managing director of Barrantagh Investment Management Inc., investment counselors based in Toronto, Ontario. From May 1993 to August 1999, Mr. Comber was the President of Newtonhouse Investment Management Ltd., investment counselors located in Toronto Ontario. Between June 1989 and December 31, 1991, Mr. Comber was Senior Vice-President of Thornmark Capital Corporation, an investment holding company, and principal officer of Thornmark Capital Funding Corporation, merchant bank. Prior to June 1989, Mr. Comber was Senior Vice-President and Managing Director of Prudential-Bache Securities Canada Limited, an investment dealer in Toronto, Ontario. Mr. Comber is a director of Nuvista Energy Ltd., Valiant Energy Inc. and Clear Energy Inc. Mr. Comber serves as chairman of the audit committee for all three of the aforementioned companies. Over the course of his career, he has acquired competence in the audit and accounting issues facing public companies and considerable knowledge of financial reporting procedures and controls.

Daryl Gilbert

Mr. Gilbert graduated from the University of Manitoba in 1973 with a Bachelor of Science Degree in Civil Engineering. Upon graduation he joined the Alberta Energy Resources Conservation Board where he received his training in Petroleum Engineering and related regulatory processes. In 1976 he joined Great Northern Oil Ltd. where he managed various oil and gas exploitation projects. Mr. Gilbert entered the field of independent consulting in 1979 when he joined the predecessor oil and gas engineering and geological firm which became Gilbert Laustsen Jung Associates Ltd. He became a Principal Officer of the firm in 1988 and was appointed President and Chief Executive Officer in 1994 and served in both capacities until his retirement in early 2005. The firm provided professional services to the Canadian and International Oil and Gas Industry including detailed reservoir and economic analyses, project and corporate evaluations, fair market value appraisals, merger and acquisition advice and expert witness testimony. Mr. Gilbert currently serves as a Director of AltaGas Income Trust (Chairman of the Audit Committee), Canetic Resources Trust (Chairman of the Reserves Committee), Kereco Energy Ltd., Chamaelo Exploration Ltd (Chairman of the Reserves Committee) and Globel Direct Inc. as well as several private companies. Mr. Gilbert is currently a member of the Association of Petroleum Engineers, Geologists and Geophysicists of Alberta, the Canadian Institute of Mining and Metallurgy and the Society of Petroleum Evaluation Engineers.

Jack C. Lee

Mr. Lee, Chairman of Canetic, holds a Bachelor of Arts and a Bachelor of Commerce degree from the University of Saskatchewan. Mr. Lee, has been a director of Canetic since its formation in November 2005. He was a director, President and CEO of AEI (a predecessor company of Canetic) from April 2001 until October 2002. He served as AEI’s Chairman from May 2003 until January 2006. He was a director, President and CEO of Danoil Energy Ltd., predecessor to Acclaim from 1997 until 2001.. He was a director, Chairman and CEO of Independent Energy Inc from 1992 until 1996. He was a shareholder and Vice President of Sprott Securities Ltd. from 1993 to 1995. He was a director, President/CEO of Gane Energy Corporation, predecessor to Northstar Energy Corporation from 1980 to 1986.

Pre-Approval Policies and Procedures

Canetic has adopted procedures with respect to the pre-approval of audit and permitted non-audit services to be provided by Deloitte & Touche LLP. All audit and non-audit services must be approved in advance by the audit committee of the Board of Directors in the following manner. The audit committee has established a budget for the provision of a specified list of audit and permitted non-audit services that the audit committee believes to be typical, recurring or otherwise likely to be provided by Deloitte & Touche LLP. The budget generally covers the period between the adoption of the budget and the next meeting of the audit committee, but at the option of the audit committee it may cover a longer or shorter period. The list of services is sufficiently detailed as to the particular services to be provided to ensure that (i) the audit committee knows precisely what services it is being asked to pre-approve and (ii) it is not necessary for any member of management to make a judgment as to whether a proposed service fits within the pre-approved services.

External Auditor Service Fees

The following table provides information about the fees billed to Acclaim (a predecessor of the Trust) for professional services rendered by Deloitte & Touche LLP during fiscal 2005 and 2004:

($ thousands)	2005	2004

Audit Fees(1)	209	153
Audit-Related Fees(2)	192	259
Tax Fees(3)	456	132
All Other Fees(4)	80	56
Total	937	600

Notes:

(1) Audit fees consist of fees for the audit of the Acclaim’s annual financial statements or services that are normally provided in connection with statutory and regulatory filings or engagements.

(2) Audit-related fees consist of fees for assurance and related services that are reasonably related to the performance of the audit or review of Acclaim’s financial statements and are not reported as Audit Fees. During fiscal 2005 and 2004, the services provided in this category included due diligence reviews in connection with acquisitions and dispositions, research of accounting and audit-related issues, review of reserves disclosure and US GAPP reconciliations and prospectus work.

(3) Tax fees consist of fees for tax compliance services, tax advice and tax planning. During fiscal 2005 and 2004, the services provided in this category included assistance and advice in relation to the preparation of corporate income tax returns as well as assistance with CRA audits and modeling of Acclaim’s taxability.

(4) During fiscal 2005 and 2004, the services provided in this category primarily included property tax reviews.

MARKET FOR SECURITIES

The Units are listed for trading under the symbol “CNE.UN” on the TSX (since January 9, 2006) and the NYSE under the symbol “CNE” (since February 15, 2006) and the 11% Debentures, 8% Debentures, 6.5% Debentures and 9.4% Debentures are listed for trading on the TSX (since July 9, 2005) under the symbols “CNE.DB.D”, “CNE.DB.C”, CNE.DB.B” and “CNE.DB.A”, respectively.

The following table sets forth the closing price range and trading volumes of the Units as reported by the TSX (from January 9, 2006) and the NYSE (from February 15, 2006), respectively, for the periods indicated.

	Toronto Stock Exchange			New York Stock Exchange
Period	High (C$ )	Low (C$ )	Volume (000’s)	High (US$ )	Low (US$ )	Volume (000’s)

2006

January	24.60	23.12	16,629	—	—	—
February	24.63	20.82	18,810	21.14	18.72	3,196
March (to March 15)	23.25	21.86	7,852	20.28	18.91	2,957

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

	Toronto Stock Exchange
Period	High (C$ )	Low (C$ )	Volume (000’s)

2006

January	212.41	160.00	750
February	215.00	193.65	1,470
March (to March 15)	n./a	n/a	0

The following table sets forth the closing price range and trading volumes of the 8% Debentures (CNE.DB.C) as reported by the TSX for the periods indicated.

	Toronto Stock Exchange
Period	High (C$ )	Low (C$ )	Volume (000’s)

2006

January	156.42	145.00	7,320
February	156.37	139.00	7,520
March (to March 15)	145.00	143.00	7,690

The following table sets forth the closing price range and trading volumes of the 6.5% Debentures (CNE.DB.B) as reported by the TSX for the periods indicated.

	Toronto Stock Exchange
Period	High (C$ )	Low (C$ )	Volume (000’s)

2006

January	129.00	120.00	36,725
February	130.00	111.55	13,330
March (to March 15)	122.00	114.87	4,160

The following table sets forth the closing price range and trading volumes of the 9.4% Debentures (CNE.DB.A) as reported by the TSX for the periods indicated.

	Toronto Stock Exchange
Period	High (C$ )	Low (C$ )	Volume (000’s)

2006

January	151.75	143.00	3,970
February	153.00	137.09	4,880
March (to March 15)	145.00	137.22	750

DISTRIBUTIONS

Policy

The Trust makes cash distributions in amounts equal to 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, receive distributions in respect of repayments of principal made by Canetic to the Trust on the Canetic Notes. Canetic endeavors to retain approximately 35% to 40% of its cash flow over time to fund capital expenditures and to distribute the balance to the Trust. The actual percentage retained by Canetic is subject to the discretion of the Board of Directors 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 15th day of each month to Unitholders of record on the immediately preceding distribution record date. The Trust’s current policy is to distribute $0.23 per Unit per month ($2.76 per Unit per annum).

Distribution Record

The following table sets forth the per Unit amount of monthly cash distributions paid by the Trust since the completion of the Arrangement.

	Distribution Per Unit (1)
2006
January	$	0.23
February	$	0.23
March	$	0.23	(2)

Notes:

(1) 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.

(2) The Trust announced on March 15, 2006 that the next monthly distribution of distributable cash of $0.23 per Unit will be paid on April 13, 2006 to Unitholders of record on March 31, 2006.

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 Canetic Common Shares, the Canetic Notes and the Canetic NPIs. 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 Canetic NPIs. 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 the Arrangement and Other Acquisitions

Acclaim and StarPoint have completed a number of acquisitions and Canetic 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 including the Arrangement 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 Canetic’s ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of Canetic including the operations of Acclaim and StarPoint. 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, supplier, customer and employee relationships that may adversely affect the Trust’s ability to achieve the anticipated benefits of past and future acquisitions including the Arrangement.

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 Canetic Trust Engineering 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 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 are 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 practicable 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 risk 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 will regularly assess 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 also, “Risk Factors – Contingency”.

Continuing production from a property, and to some extent the marketing of production therefrom, are largely dependent upon the abilities 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 those 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.

Proposed Changes to Well Spacing Application Process

In terms of notification it will require industry pre-application notification to potentially affected subsurface parties only. There will also be higher baseline well densities in that part of Alberta east of the 5th Meridian and south of Township 53 in the Mannville and shallower formations. For gas wells there will be (i) maximum 4 wells per pool per section above the Mannville group; (ii) maximum 2 wells per pool per section for the Mannville group; and (iii) a standard buffer zone will be 300 metres on the south and west sides of the section. For oil wells there will be (i) maximum 2 wells per pool per quarter section for the Mannville group; and (ii) standard buffer zone will be 200 metres on the south and east sides of the quarter section.

Contingency

On December 12, 2004, a gas release occurred at an Acclaim operated well site west of Edmonton, Alberta. The well was not producing at the time of the incident and has not had an impact on production in the area.

At the time Acclaim carried 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 approximately $50 million including the cost of drilling two relief wells and subsequent abandonment and reclamation of the site. At December 31, 2005, costs approximating $50 million have been incurred of which $49.4 million has been paid to suppliers for services provided.

Insurance recoveries to date total $35 million. The Trust is currently finalizing all remaining claims with its insurers. See also, “Risk Factors – Operational Matters”.

Income Tax Matters - Canada

There can be no assurance that Canadian federal income tax laws and administrative policies respecting the treatment of mutual fund trusts will not be changed in a manner that adversely affects the holders of Units. If the Trust ceases to qualify as a “mutual fund trust” under the Tax Act, the income tax considerations described herein under the heading “Certain Canadian Federal Income Tax Considerations” would be materially and adversely different in certain respects.

Pursuant to the provisions of the Trust Indenture all taxable income earned by the Trust in a fiscal year not previously distributed in that fiscal year must be distributed to Unitholders of record on December 31. This excess income, if any, will be allocated to Unitholders of record at December 31 but the right to receive this income, if the amount is not determined and declared payable at December 31, will trade with the Units until determined and declared payable in accordance with the rules of the TSX. To the extent that a Unitholder trades Units in this period they will be allocated such income but will dispose of their right to receive such distribution.

On September 8, 2005 the Department of Finance (Canada) released a consultation paper on tax and other issues related to publicly-listed flow-through entities, such as income trusts and limited partnerships, and invited interested parties to make submissions prior to December 31, 2005. The stated focus of this consultation paper was to assess the tax and economic efficiencies of flow-through entities to determine if the current tax system is appropriate or should be modified. In addition, on September 19, 2005, the Minister of Finance (Canada) announced that he had requested that the CRA postpone providing advance income tax ruling respecting flow-through entity structures effective immediately, that the Department of Finance (Canada) was closely monitoring developments in the flow-through entity market with a view to proposing measures in relation to the consultations and that consideration would be given to what, if any, transitional measures were appropriate. On November 23, 2005, the Minister of Finance (Canada) announced that the public consultation process was ended and tabled in the House of Commons a Notice of Ways and Means Motion to implement a reduction in personal income tax on dividends with a view to establishing a better balance between the treatment of large corporations and that of income trusts. No measures were announced with respect to the taxation of flow-through entities and their investors. No assurance may be given that further review of the tax treatment of flow-through entities will not be undertaken or that Canadian federal income tax law and/or provincial income tax law respecting flow-through entities will not be changed in a manner that adversely affects the Trust and its Unitholders.

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 are currently high on an historical basis, but 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 reserves of the Trust as determined by independent evaluators.

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 Canetic’s lenders may also limit distributions to the Trust and by the Trust to Unitholders. Although Canetic believes its credit facilities will be sufficient for Canetic’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.

Canetic’s principal lenders will obtain guarantees and subordination agreements from all material 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 prohibit the Operating Entities from making payments to the Trust. The lenders may enforce the payment obligations of the Operating Entities under the loan agreement and guarantees and such obligations of the Operating Entities to the lenders will rank in priority to any payments by the Operating Entities to the Trust.

Structural Subordination of the Units

In the event of a bankruptcy, liquidation or reorganization of Canetic 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 Canetic and the other Operating Entities, before any assets are made available for distribution to the Trust (including pursuant to the Canetic Notes). The Units are therefore effectively junior to the bank indebtedness and most other liabilities (including trade payables) of Canetic and the other Operating Entities. Neither Canetic nor any of the other Operating Entities are 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 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 will be 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.

Depletion of Reserves

Like other income trusts, the Trust has certain unique attributes that differentiate it from conventional 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 were qualified investments at the time of acquisition, but subsequently have ceased to be 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. If an RESP’s registration is revoked, it will become subject to tax under Part I on its taxable income. If, however, an RESP holds property that is not a qualified investment and the registration of the RESP is not revoked, Part XI.1 tax will apply, as described above. In addition, if the Trust were to cease to qualify as a mutual fund trust:

The Trust would be taxed on certain types of income distributed to Unitholders, including income generated by the royalties and the net profits interests 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. Consequently, 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. 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 Redemption Notes. 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 Canetic 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 Canetic Notes, the Canetic NPIs 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 Canetic’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, in its capacity as such, shall incur or be subject to any liability in contract or in tort or of any other kind whatsoever to any person in connection with the Trust Fund (as defined in the Trust Indenture) or the obligations or the affairs of the Trust or with respect to any act performed by the Trustee or by any other person pursuant to the Trust Indenture or with respect to any act or omission of the Trustee or any other person in the performance or exercise, or purported performance or exercise, of any obligation, power, discretion or authority conferred upon the Trustee or such other person under the Trust Indenture or with respect to any transaction entered into by the Trustee or by any other person pursuant to the Trust Indenture. The Trust Indenture further provides that no Unitholder shall be liable to indemnify the Trustee or any such other person with respect to any such liability or liabilities incurred by the Trustee or by any such other person or persons or with respect to any taxes payable by the Trust or by the Trustee or by any other person on behalf of or in connection with the Trust. Notwithstanding the foregoing, the Trust Indenture also provides that to the extent that any Unitholders are found by a court of competent jurisdiction to be subject to any such liability, such liability shall be enforceable only against, and shall be satisfied only out of, the Trust Fund and the Trust, (to the extent of the Trust Fund) is liable to, and shall indemnify and save harmless any Unitholder against any costs, damages, liabilities, expenses, charges or losses suffered by any Unitholder from or arising as a result of such Unitholder not having any such limited liability.

The Trust Indenture provides that all contracts 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. Notwithstanding the terms of the Trust Indenture, Unitholders may not be protected from liabilities of the Trust to the same extent a shareholder is protected from the liabilities of a corporation. Personal liability may also arise in respect of claims against the Trust (to the extent that claims are not satisfied by 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 to Trust Unitholders of this nature arising is considered unlikely in view of the fact that the primary activity of the Trust is to hold securities, and all of the business operations is currently carried on by Canetic or the Operating Entities. The Income Trusts Liability Act (Alberta) came into force on July 1, 2004. The legislation provides that a

unitholder will not be, as a beneficiary, liable for any act, default, obligation or liability of the trustee that arises after the legislation came into force.

Restrictions on Non Resident Ownership

Generally, a trust cannot qualify as a “mutual fund trust” for the purposes of the Tax Act if it is established or is being maintained primarily for the benefit of non-residents. Although not without uncertainty, this is generally accepted to exist in most situations where Non-Resident holders own significantly in excess of 50% of the aggregate number of Units issued and outstanding. However, there is currently an exception to the non-resident ownership restriction in paragraph 132(7)(a) of the Tax Act where not more than 10% of the trust’s property has at any time consisted of “taxable Canadian property”.

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, the Canetic Notes, and the Canetic NPIs. Accordingly, the cash distributions to Unitholders will be dependent upon the ability of the Operating Entities to pay their interest obligations under the Canetic Notes, to declare and pay dividends on the Operating Entities’ common shares and to make payments under the Canetic NPIs.

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 Canetic 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 Canetic 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 also, “Business and Properties – Industry Conditions”.

INTEREST OF INSIDERS IN MATERIAL TRANSACTIONS

To the knowledge of the directors and executive officers of Canetic, other than in connection with the Arrangement as disclosed under the sections entitled “The Arrangement – Interests of Certain Persons or Companies in the Matters to be Acted Upon” and “Other Matters to be Considered at the Meetings – Approval of the TriStar Private Placement” in the Joint Information Circular and Proxy Statement of Acclaim and StarPoint dated November 18, 2005, which sections are incorporated herein by reference, there were no material interests, direct or indirect, of directors or senior officers of Canetic, nominees for director of Canetic, 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 2005 or in any proposed transaction which has materially affected or would materially affect the Trust or Canetic other than as disclosed herein.

INTEREST OF EXPERTS

Deloitte & Touche LLP, Chartered Accountants, are the Trust’s auditors and such firm has prepared an opinion with respect to the Trust’s consolidated financial statements as at and for the fiscal period ended December 31, 2005. Deloitte & Touche LLP is independent in accordance with the Rules of Professional Conduct as outlined by the Institute of Chartered Accountants of Alberta.

GLJ and Sproule prepared the Canetic Trust Engineering Report. As at the date hereof, neither GLJ or Sproule nor any of their directors or officers owns, directly or indirectly, any of the Units.

MATERIAL CONTRACTS

The only material contracts entered into by the Trust during the past two years, other than in the ordinary course of business, are as follows:

1. the Trust Indenture;

2. the Administration Agreement ;

3. the Trust Unit Incentive Plan;

4. the 8% Debenture Indenture;

5. the 11% Debenture Indenture;

6. the 6.5% Debenture Indenture; and

7. the 9.4% Debenture Indenture.

LEGAL PROCEEDINGS

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

AUDITORS, TRANSFER AGENT AND REGISTRAR

The auditors of the Trust are Deloitte & Touche LLP.

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

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 24, 2006 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, 2005.

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

Canetic Resources Trust

c/o Canetic Resources 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.canetictrust.com.

GLOSSARY OF TERMS

The following is a glossary of certain terms used in this Annual Information Form.

“000s” means thousands.

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

“Acclaim” means Acclaim Energy Trust, an unincorporated trust formed under the laws of the Province of Alberta.

“Acclaim Unitholder” means a holder from time to time of Acclaim Units.

“Acclaim Units” means the trust units of Acclaim.

“Administration Agreement” means the agreement between Canetic and the Trustee providing for the administration of the Trust.

“AEI” means Acclaim Energy Inc., a predecessor of Canetic amalgamated under the ABCA.

“AEPEA” means the Alberta Environmental Protection and Enhancement Act.

“Arrangement” means the arrangement involving Acclaim, AEI, StarPoint and SEL, under the provisions of Section 193 of the ABCA.

“Arrangement Agreement” means the arrangement agreement dated effective November 17, 2005 between Acclaim, AEI, StarPoint and SEL, and any amendments thereto.

“ARTC” means the Alberta Royalty Tax Credit.

“Board” or “Board of Directors” means the board of directors of Canetic.

“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.

“Canetic” means Canetic Resources Inc., a corporation amalgamated under the ABCA.

“Canetic Assets” means all of the assets of Canetic including the assets of Acclaim and StarPoint acquired by the Trust upon completion of the Arrangement.

“Canetic Notes” means the promissory notes of AEI, SEL and other affiliates of Acclaim and StarPoint acquired by the Trust pursuant to the Arrangement.

“Canetic NPIs” means the net profits interests granted under the NPI Agreements.

“Canetic Trust Engineering Report” means, collectively, the GLJ Report and the Sproule Report, with respect to the oil, NGL and natural gas interests held by the Trust and prepared by GLJ and Sproule effective December 31, 2005.

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

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

“Chevron Texaco Acquisition” means the acquisition of the Chevron Texaco Properties by AEI as more particularly described under the heading “Information Concerning Canetic Resources Trust – Significant Transactions and Recent Developments”.

“Chevron Texaco Properties” means the interests in oil and natural gas reserves and associated facilities located in Alberta, British Columbia, Saskatchewan and Manitoba acquired by AEI pursuant to the Chevron Texaco Acquisition as more particularly described under the heading “Information Concerning Canetic Resources Trust – Significant Transactions and Recent Developments”.

“COGE Handbook” means the Canadian Oil and Gas Evaluation Handbook prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum.

“Company Interest Reserves” means Canetic’s Gross Reserves plus its royalty interest Reserves.

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

(a) Canetic’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 Canetic 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, the 11% Debentures, the 6.5% Debentures and the 9.4% Debentures.

“CRA” means the Canada Revenue Agency.

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

“Danoil Merger” means the transaction described under the heading “Information Concerning Canetic Resources Trust – Significant Transactions and Recent Developments”.

“6.5% Debenture Indenture” means the trust indenture governing the 6.5% Debentures.

“6.5% Debentures” means the 6.5% convertible, extendible, unsecured, subordinated debentures issued on May 26, 2005 pursuant to the 6.5% Debenture Indenture.

“8% Debenture Indenture” means the trust indenture governing the 8% Debentures.

“8% Debentures” means the 8% convertible, extendible, unsecured, subordinated debentures issued on June 15, 2004 pursuant to the 8% Debenture Indenture.

“9.4% Debenture Indenture” means the trust indenture governing the 9.4% Debentures.

“9.4% Debentures” means the 9.4% convertible, extendible, unsecured, subordinated debentures issued on July 3, 2003 pursuant to the 9.4% Debenture Indenture.

“11% Debenture Indenture” means the trust indenture governing the 11% Debentures.

“11% Debentures” means the 11% convertible, extendible, unsecured, subordinated debentures issued on December 17, 2002 pursuant to the 11% Debenture Indenture.

“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 assemblies;

(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 assemblies;

(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.

“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.

“Distributable Cash” means all amounts available for distribution during any applicable period to holders of Units.

“Distribution” means a distribution paid by the Trust in respect of the Units, whether of cash, Units or other securities or other property, expressed as an amount per Unit.

“Distribution Payment Date” means any date that Distributable Cash is distributed to Unitholders, generally being the 15^th day of the calendar month following any Distribution Record Date (or if such day is not a Business Day, on the next Business Day thereafter).

“Distribution Record Date” means the last day of each calendar month or such other date as may be determined from time to time by the Board of Directors, except that December 31^st shall in all cases be a Distribution Record Date.

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

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

(b) forecast prices and costs.

“Elk Point” means Elk Point Resources Inc., a predecessor corporation of Canetic, incorporated under the CBCA.

“Elk Point Arrangement” means the business combination involving Acclaim, AEI, 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, Acclaim indirectly acquired all of the issued and outstanding common shares of Elk Point and Burmis Energy Inc. acquired the United States assets and certain minor Alberta properties of Elk Point and the shares of Burmis Energy Inc. were distributed to the former holders of common shares of Elk Point.

“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 Canetic, incorporated under the ABCA and acquired by Canetic on December 19, 2003 pursuant to the Exodus Acquisition.

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

“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;

(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.

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

(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 Canetic 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;

(d) applying to the future pre-tax net cash flows relating to Canetic’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 Canetic as more particularly described under the heading “Information Concerning Canetic Resources Trust – Significant Transactions and Recent Developments”.

“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 Canetic pursuant to the Gilby/Willesden Green Acquisition as more particularly described under the heading “Information Concerning Canetic Resources y Trust – Significant Transactions and Recent Developments”.

“GLJ” means GLJ Petroleum Consultants Ltd.

“GLJ Report” means the report of GLJ dated March 1, 2006 and effective as of December 31, 2005, evaluating the oil and natural gas reserves and future net production revenues attributable to certain of the properties of Canetic.

“Gross” means:

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

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

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

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

“Ketch Energy Arrangement” means the business combination involving Acclaim, AEI, 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, Acclaim 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 ExploreCo Assets” means certain growth assets of Ketch Energy acquired by Ketch Resources Ltd. from Ketch Energy as part of the Ketch Energy Arrangement.

“Market Redemption Price” means the price per Unit equal to the lesser of: (i) 95% of the “market price”, as calculated under Trust Indenture, of the Units on the principal market on which the Units are tendered to the Trust for redemption; (ii) 95% of the “closing market price”, as calculated under Trust Indenture, on the principal market on which the Units are quoted for trading on the date that the Units are so tendered for redemption; and (iii) 95% of the closing market price of the Trust Units on the date of redemption.

“NAFTA” means the North American Free Trade Agreement.

“NEB” means the National Energy Board.

“Net” means:

(a) in relation to Canetic’s interest in production or reserves, Canetic’s working interest (operating and non-operating) share after deduction of royalty obligations, plus Canetic’s royalty interest in production or reserves.

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

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

“NI 51-101” means National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities.

“Nevis” means Nevis Ltd., a predecessor corporation of Canetic, incorporated under the ABCA.

“NG Acquisition” means the acquisition of the NG Properties by Canetic as more particularly described under the heading “Information Concerning Canetic Resources Trust – Significant Transactions and Recent Developments”.

“NG Properties” means the interests in oil and natural gas reserves and associated facilities located in Alberta and British Columbia acquired by Canetic pursuant to the NG Acquisition as more particularly described under the heading “Information Concerning Canetic Resources Trust – Significant Transactions and Recent Developments”.

“Non-Resident” means: (i) a person who is not a resident of Canada for the purposes of the Tax Act; or (ii) a partnership that is not a Canadian partnership for the purposes of the Tax Act.

“NPI Agreements” means the net profits interest agreements between Acclaim and certain Acclaim affiliates operating entities and between StarPoint and certain StarPoint affiliates acquired by the Trust pursuant to the Arrangement.

“NYSE” means the New York Stock Exchange.

“Operating Entities” means Canetic, AEI, SEL, 1198330 Alberta Ltd., ACT, SCT, 960347 Alberta Ltd., Canetic Resources Partnership, Canetic Energy Partnership, 1149708 Alberta Ltd., Trend Energy Inc., Canetic SE Partnership, APF Energy Trust, Canetic Saskatchewan Trust, Canetic (Sask.) Limited Partnership, Canetic SR Partnership, 1167639 Alberta Ltd., 990009 Alberta Inc., Tika Energy Inc. and Upton Resources U.S.A. Inc.

“Operating Entities Securities” means the Canetic Notes, the Canetic NPIs, the common shares of Canetic and any other securities of the Operating Entities held by the Trust.

“Oil and Natural Gas Properties” or “Properties” means the working, royalty or other interests of Canetic or any affiliate of the Trust from time to time in any petroleum and natural gas rights, tangibles and miscellaneous interests, including properties which may be acquired by any affiliates of Canetic at a future date including pursuant to the Arrangement.

“Permitted Investments” means: (i) loan advances to any affiliate of the Trust including Canetic; (ii) interest bearing accounts of certain financial institutions, including Canadian chartered banks and the Trustee and any affiliate of the Trustee; (iii) obligations issued or guaranteed by the Government of Canada or any province of Canada or any agency or instrumentality thereof; (iv) term deposits, guaranteed investment certificates of deposit or bankers’ acceptances of or guaranteed or accepted by any Canadian chartered bank or other financial institution (including the Trust and any affiliate of the Trust), the short term debt or deposits of which have been rated at least A by Standard & Poor’s Corporation or the equivalent by Moody’s Investors Service, Inc. or Dominion Bond Rating Service Limited; and (v) commercial paper rated at least A by Standard & Poor’s Corporation or the equivalent by Moody’s Investor Services, Inc. or Dominion Bond Rating Service Limited.

“Person” means any individual, partnership, association, body corporate, trustee, executor, administrator, legal representative, government, regulatory authority or other entity.

“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

“Redemption Notes” means unsecured subordinated promissory notes issued in series, or otherwise, by Canetic pursuant to a note indenture and issued to redeeming Unitholders in principal amounts equal to the Market Redemption Price of the Units to be redeemed in consideration of a cash payment or by reducing any indebtedness of Canetic to the Trust and having substantially the terms and conditions as more particularly described in this Annual Information Form.

“SEDAR” means the System for Electronic Document Analysis and Retrieval.

“SEL” means StarPoint Energy Ltd., a corporation amalgamated under the ABCA.

“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 Resolution” means a resolution proposed to be passed as a special resolution at a meeting of Unitholders (including an adjourned meeting) duly convened for the purpose and held in accordance with the provisions of the Trust Indenture at which two or more holders of at least 5% of the aggregate number of Units then outstanding are present in person or by proxy and passed by the affirmative votes of the holders of not less than 66²/₃% of the Units (including the Special Voting Units) represented at the meeting and voted on a poll upon such resolution.

“Special Voting Unit” means the special voting units of the Trust entitling the holders thereof to attend meetings of Unitholders and to such number of votes at meetings of Unitholders as may be prescribed by the Board in the resolution authorizing the issuance of any such Special Voting Units.

“Sproule” means Sproule Associates Limited.

“Sproule Report” means the reports of Sproule dated February 23, 2006, February 24, 2006 and February 27, 2006 and effective December 31, 2005, evaluating the crude oil and natural gas reserves and future net production revenues attributable to certain properties of Canetic.

“StarPoint” means StarPoint Energy Trust, a trust organized under the laws of the Province of Alberta.

“StarPoint Unitholder” means a holder from time to time of StarPoint Units.

“StarPoint Units” means the trust units of StarPoint.

“Subsequent Investment” means those investments that the Trust is permitted to make pursuant to Trust Indenture.

“Subsidiary” means, with respect to any Person, a subsidiary (as that term is defined in the ABCA (for such purposes, if such Person is not a corporation, as if such Person were a corporation)) of such Person and includes any limited partnership, joint venture, trust, limited liability company, unlimited liability company or other entity, whether or not having legal status, that would constitute a subsidiary (as described above) if such entity were a corporation.

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

“TSX” means the Toronto Stock Exchange.

“TriStar” means TriStar Oil & Gas Ltd., a corporation incorporated under the ABCA.

“TriStar Arrangement Warrants” means the share purchase issued to Acclaim Securityholders and StarPoint Securityholders pursuant to the Arrangement, each of which entitled the holder to acquire one (1) TriStar Common Share at an exercise price of $2.75 per whole TriStar Common Share until 4:30 p.m. (Calgary time) on or before but not after February 6, 2006.

“TriStar Assets” means the assets transferred by Acclaim and StarPoint or certain subsidiaries thereof to TriStar, directly or indirectly, pursuant to the Arrangement.

“Trust” means Canetic Resources Trust, a trust established under the laws of the Province of Alberta pursuant to the Trust Indenture.

“Trust Indenture” means the trust indenture dated as of November 16, 2005 among the Trustee, the settlor of the Trust and Canetic, as amended from time to time.

“Trust Unit Award Incentive Plan” means the unit award incentive plan of the Trust.

“Trustee” means Computershare Trust Company of Canada, the initial trustee of the Trust, or such other trustee, from time to time of the Trust.

“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.

“Unit” means a trust unit of the Trust.

“United States” or “U.S.” means the United States, as defined in Rule 902(l) under Regulation S.

“United States Securityholders” or “United States Securityholder” means any Securityholder who is, at the Effective Time, either in the United States or a U.S. Person.

“Unitholder” means a holder of Units.

CONVENTIONS

Certain terms used herein are defined in the “Glossary of Terms”. Certain other terms used herein but not defined herein are defined in NI 51-101 and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101.

Unless otherwise indicated, references herein to “$” or “dollars” are to Canadian dollars.

All financial information herein has been presented in Canadian dollars in accordance with Canadian GAAP.

ABBREVIATIONS

Oil and Natural Gas Liquids

Bbl		barrel
Bbls		barrels
MBbls		thousand barrels
MMBbls		million barrels
Bbls/d		barrels per day
BOPD		barrels of oil per day
NGL		natural gas liquids

Natural Gas

Mcf		thousand cubic feet
MMcf		million cubic feet
Mcf/d		thousand cubic feet per day
MMcf/d		million cubic feet per day
Mmbtu		million British thermal units
Bcf		billion cubic feet
GJ		gigajoule

Other

AECO EnCana Corporation’s natural gas storage facility located at Suffield, Alberta.

API American Petroleum Institute

°API an indication of the specific gravity of crude oil measured on the API gravity scale.

Boe barrel of oil equivalent of natural gas and crude oil on the basis of 1 Boe for 6 Mcf of natural gas

Boe/d barrel of oil equivalent per day

C$ Canadian dollars

m³ cubic metres

M$ thousands of dollars

MBoe 1,000 barrels of oil equivalent

MMBoe million barrels of oil equivalent

MM million

US$ United States dollars

WTI West Texas Intermediate, the reference price paid in United States dollars at Cushing, Oklahoma for crude oil of standard grade

CONVERSIONS

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 oil	6.290
Feet	Metres	0.305
Metres	Feet	3.281
Miles	Kilometres	1.609
Kilometres	Miles	0.621
Acres	Hectares	0.405
Hectares	Acres	2.471

APPENDIX “A”

REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION

Management of Canetic Resources Inc. (“Canetic”) are responsible for the preparation and disclosure of information with respect to Canetic’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, 2005 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, 2005 using constant prices and costs; and

(ii) the related estimated future net revenue.

Independent qualified reserves evaluators have evaluated Canetic’s reserves data. The report of the independent qualified reserves evaluators is presented below.

The Reserves Committee of the Board of Directors of Canetic has

(a) reviewed Canetic’s procedures for providing information to the independent qualified reserves evaluators;

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

The Reserves Committee of the Board of Directors has reviewed Canetic’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 evaluators on the reserves data; and

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) “Daryl Gilbert”			(signed) “Jack C. Lee”
Daryl Gilbert			Jack C. Lee
Director and Chairman of the Reserves Committee			Chairman and Member of the Reserves Committee
March 9, 2006

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APPENDIX “B”

REPORT ON RESERVES DATA

To the board of directors of Canetic Resources Inc. (the “Company”):

1. We have evaluated the Company’s reserves data as at December 31, 2005. The reserves data consist of the following:

(a) (i) proved and proved plus probable oil and gas reserves estimated as at December 31, 2005 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, 2005, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company’s board of directors:

Independent Qualified
Reserves Evaluator or

Description and
Preparation Date

Location of
Reserves
(County or
Foreign
Geographic

Net Present Value of Future Net Revenue
(before income taxes, 10% discount rate)

Auditor

of Report

Area)

Audited

Evaluated

Reviewed

Total

($M)

GLJ Petroleum Consultants Ltd.

Acclaim Energy Trust, Reserves Assessment and Evaluation of Canadian Oil and Gas Properties effective December 31, 2005, prepared September 2005 to February, 2006.

Canada

1,764,508

GLJ Petroleum Consultants Ltd.

Canetic Resources Trust, Reserves Assessment and Evaluation of Canadian Oil and Gas Properties effective December 31, 2005, prepared September 2005 to February, 2006.

Canada

25,165

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Independent Qualified Reserves Evaluator or	Description and Preparation Date	Location of Reserves (County or Foreign Geographic	Net Present Value of Future Net Revenue (before income taxes, 10% discount rate)
Auditor	of Report	Area)	Audited	Evaluated		Reviewed	Total
				($M)			($M)

GLJ Petroleum Consultants Ltd.	Canetic Resources Trust, Reserves Assessment and Evaluation of Canadian Oil and Gas Properties effective December 31, 2005, prepared September 2005 to February, 2006.	Canada	0	$	18,439	0	$	18,439

Sproule Associates Ltd.	Evaluation of the P&NG Reserves in Certain Properties of StarPoint Energy Trust for Canetic Resources Trust, as of December 31, 2005, prepared September 2005 to February 2006.	Canada and United States	0	$	1,799,585	0	$	1,799,585

Sproule Associates Ltd.	Evaluation of the P&NG Reserves in Certain Properties of Canetic Resources Inc., as of December 31, 2005, prepared December 2005 to February 2006	Canada	0	$	110,814	0	$	110,814

Sproule Associates Ltd.	Evaluation of the Coalbed Methane Reserves of Tika Energy Inc. for Canetic Energy Trust, as of December 31, 2005, prepared November 2005 to February 2006.	United States	0	$	68,331	0	$	68,331

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) “GLJ Petroleum Consultants Ltd.”		(signed) “Sproule Associates Ltd.”

	GLJ Petroleum Consultants Ltd. Calgary, Alberta March 2006		Sproule Associates Ltd. Calgary, Alberta February 2006

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APPENDIX “C”

TERMS OF REFERENCE FOR THE AUDIT COMMITTEE

The term “Trust” refers to Canetic Resources Trust, the term “Corporation” refers to Canetic Resources Inc., the term “Canetic” refers collectively to the Trust, the Corporation and their subsidiaries, the term “Board” or “Board of Directors” refers to the board of directors of the Corporation, the term “Committee” refers to the Audit Committee of the Board, and the term “Chair” refers to the chair of the Board.

A. PURPOSE

1. The primary function of the Committee is to assist the Board in fulfilling its oversight responsibilities, in the Corporation’s capacity as administrator of the Trust, relating to the Trust’s financial reporting including the integrity of the Trust’s financial statements, the Trust’s financial reporting process and systems of internal controls, the compliance by the Trust with legal and regulatory requirements and the qualifications, performance and independence of the Trust’s external auditors and internal audit function (if any).

The Committee discharges this responsibility by, among other things, reviewing and overseeing:

(a) the financial information that will be provided to the unitholders of the Trust and others;

(b) the systems of internal controls that management and the Board have established;

(c) the qualifications and independence of the Trust’s external auditors (who shall report directly to the Committee); and

(d) all audit processes.

2. Primary responsibility for the financial reporting, information systems, risk management and internal controls of the Trust is vested in management and is overseen by the Board. While the Committee has the responsibilities and powers set forth in these terms of reference, it is not the duty of the Committee to plan or conduct audits or to determine that the Trust’s financial statements are complete and accurate and are in accordance with generally accepted accounting principles and applicable rules and regulations. These are the responsibilities of management and the external auditors. Nor is it the duty of the Committee to conduct investigations or to assure compliance with laws and regulations. The Committee, its chair (the “Committee Chair”) and any Committee members identified as having accounting or related financial expertise or being financially literate are members of the Board, appointed to the Committee to provide broad oversight of the financial, risk and control related activities of the Trust, and are specifically not accountable or responsible for the day-to-day operation or performance of such activities. Although the designation of a Committee member as having accounting or related financial expertise or being financially literate for disclosure purposes or otherwise is based on that individual’s education and experience, which that individual will bring to bear in carrying out his or her duties on the Committee, such designation does not impose on such person any duties, obligations or liability that are greater than the duties, obligations or liability imposed on such person as a member of the Committee and the Board in the absence of such designation. Rather, the role of a Committee member who is identified as having accounting or related financial expertise or being financially literate, like the role of all Committee members, is to oversee the process, not to certify or guarantee the internal or external audit of the Trust’s financial information or public disclosure.

B. COMPOSITION AND OPERATIONS

1. The Committee shall be composed of three directors or such greater number as the Board may from time to time determine. The Committee shall only be comprised of independent directors in accordance with the definition of “independent” directors from time to time under the requirements or guidelines for audit committee service under applicable securities laws and the rules of any stock exchange on which the Units are listed for trading and a majority shall be resident Canadians. Currently such definitions are contained in National Instrument 52-110 of the Canadian

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Securities Administrators, Section 303A.02 of the Corporate Governance Rules of the New York Stock Exchange and Rule 10A-3(b)(1) of the U.S. Securities Exchange Act of 1934, as amended (the “Exchange Act”).

All members of the Committee must be financially literate, as the term “financially literate” is interpreted by the Board in its business judgment or as may be defined from time to time under the requirements or guidelines for audit committee service under securities laws and the rules of any stock exchange on which the Units are listed for trading, or must become financially literate within a reasonable period of time after his or her appointment to the Committee. “Financially literate” means the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of the issues that can reasonably be expected to be raised by the issuer’s financial statements.

The Committee shall have a Committee Chair, who is a full member of the Committee, and who is appointed by the Board. The Committee Chair shall have a casting vote in the event of a tie vote in the Committee. The Board Chair, if not otherwise appointed as a full member of the Committee, shall be an ex officio member of the Committee.

Committee members may enhance their familiarity with finance and accounting by participating in educational programs conducted by the Trust or an outside consultant. In addition, at least one member of the Committee must have accounting or related financial management expertise, as the Corporation’s Board of Directors interprets such qualification in its business judgment. At least one member of the Committee must be an “audit committee financial expert” as defined in the Exchange Act and its rules.

2. In connection with the election of the members of the Committee, the Board will determine whether any proposed nominee for the Committee serves on the audit committees of more than three public companies. To the extent that any proposed nominee of the Corporation serves on the audit committees of more than three public companies, the Board will make a determination as to whether such simultaneous services would impair the ability of such member to effectively serve on the Committee and will disclose such determination in the Trust’s annual information circular and annual report on Form 40-F filed with the Securities and Exchange Commission.

3. The external auditors shall be advised of the names of the Committee members and when appropriate will receive notice of and be invited to attend meetings of the Committee, and to be heard at those meetings on matters relating to the auditors’ duties.

4. The Committee shall meet with the external auditors as it deems appropriate to consider any matter that the Committee or auditors determine should be brought to the attention of the Board or Unitholders.

5. The Committee shall meet at least four times each year.

6. The Committee has access to Canetic’s senior management and documents as required to fulfill its responsibilities and is provided with the resources necessary to carry out its responsibilities.

7. The Committee provides open avenues of communication among management, employees, the external auditors and the Board.

8. The secretary to the Committee (the “Committee Secretary”) shall be either the Corporate Secretary of the Corporation or his/her delegate.

9. Notice of the time and place of every meeting may be given orally, in writing, by facsimile or email or by other electronic means to each member of the Committee at least 48 hours prior to the time fixed for such meeting. A member may, in any manner, waive notice of the meeting. Attendance of a member at a meeting shall constitute waiver of notice.

10. A majority of the voting membership of the Committee present in person or by telephone or other electronic telecommunication device shall constitute a quorum.

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11. The Chief Executive Officer (“CEO”), Board Chair and Chief Financial Officer (“CFO”)of the Corporation will be available to attend Committee meetings or portions thereof as requested by the Committee.

The external auditors would meet at least twice annually with the Committee and would be expected to be available to attend meetings or portions thereof as requested by the Committee.

The Committee may, by specific invitation, have other resource persons in attendance to assist in the discussion and consideration of matters relating to the Committee.

The Committee shall have the right to determine who shall and who shall not be present at any time during a meeting of the Committee.

12. The Committee shall report to the Board any issues that arise with respect to the quality or integrity of the Trust’s financial statements, the Trust’s compliance with legal or regulatory requirements, or the performance or independence of the Trust’s external auditors or internal audit function (if any).

13. Minutes of Committee meetings shall be approved by the Committee Chair and maintained with the Corporation’s records by the Committee Secretary or designate. Minutes of Committee meetings shall be made available to all Board members.

14. The Committee may retain independent legal, accounting, financial or other consultants or advisors to advise the Committee at the Corporation’s expense and shall have sole authority to retain and terminate any such consultants or advisors and to approve any such consultant’s or advisor’s retention terms. Without limitation of the foregoing, the Corporation will provide the Committee with appropriate funding, as determined by the Committee, for payment of compensation of the external auditors (or any other accounting firm engaged for the purpose of preparing or issuing an audit report or performing other audit, review or attest services), compensation to any consultants or advisors referred to in this paragraph M and the ordinary administrative expenses of the Committee that are necessary or appropriate in carrying out its duties.

15. Absent actual knowledge to the contrary (which shall be promptly reported to the Board), each member of the Committee shall be entitled to rely on (i) the integrity of those persons or organizations within and outside the Trust and the Corporation from which the Committee receives information, (ii) the accuracy of the financial and other information provided to the Committee by such persons or organizations, and (iii) representations made by management and the external auditors, as to any information, internal audit and other non-audit services provided by the external auditors to the Trust, the Corporation and their respective subsidiaries.

16. The Committee may delegate from to time to any person or committee of persons any of the Committee’s responsibilities that are permitted to be delegated to such person or committee in accordance with applicable laws, regulations and stock exchange requirements.

C. DUTIES AND RESPONSIBILITIES

Subject to the powers and duties of the Board, the Committee will perform the following duties:

1. Financial Statements and Other Financial Information

The Committee will review and recommend for approval to the Board financial information that will be made publicly available. This includes:

(a) review (including by meeting with management and the external auditors) and recommend to the Board approval of the Trust’s annual financial statements (including the notes), management’s discussion and analysis (“MD&A”) relating to such financial statements and associated press release, and report to the Board before the statements are approved by the Board;

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(b) review (including by meeting with management and the external auditors) and approve for release or recommend to the Board for approval the Trust’s interim quarterly financial statements (including the notes), the MD&A relating to such financial statements and associated press release;

(c) review and approve for release all earnings or distributable cash press releases, press releases containing other financial information and any earnings, distributable cash or other financial performance guidance provided to analysts or rating agencies;

(d) review and recommend to the Board for approval the financial content of the annual report and any financial reports required by government or regulatory authorities;

(e) review the financial content of the annual information form and any disclosure relating to the Committee or the external auditors and their services included in the annual information form or proxy materials of the Trust or in any prospectus, private placement offering memorandum or similar securities offering document;

(f) review any management report that accompanies published financial statements (to the extent such a report discusses the financial position or operating results) for consistency of disclosure with the financial statements themselves;

(g) review and resolve disagreements between management and the external auditors regarding financial reporting or the application of any accounting principles or practices; and

(h) meet separately, periodically, with management, with internal auditors (or other personnel responsible for the internal audit function), if any, and with the external auditors including reviewing with the external auditors any audit problems or difficulties and management’s response.

Review and discuss:

(i) the appropriateness of accounting policies and financial reporting practices used by the Trust;

(j) any significant proposed changes in financial reporting and accounting policies and practices to be adopted by the Trust;

(k) any new or pending developments in accounting and reporting standards that may affect the Trust;

(l) management’s key estimates and judgments that may be material to financial reporting;

(m) with the CEO, the CFO and the external auditors, the matters required to be reviewed with those persons in connection with any certificates required by applicable laws, regulations or stock exchange requirements to be provided by the CEO and CFO;

(n) major issues regarding accounting principles and financial statement presentations, including any significant changes in the Trust’s selection or application of accounting principles;

(o) major issues as to the adequacy of the Trust’s internal controls and any special audit steps adopted in light of material control deficiencies;

(p) analyses prepared by management and/or the external auditors setting forth significant financial reporting issues and judgments made in connection with the preparation of the financial statements, including analyses of the effects of alternative GAAP methods on the financial statements;

(q) the effect of regulatory and accounting initiatives, as well as off-balance sheet structures, on the Trust’s financial statements;

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(r) the type and presentation of information to be included in earnings press releases, paying particular attention to any use of “pro forma” or “adjusted” non-GAAP information; and

(s) any other matters required to be reviewed under applicable legal, regulatory or stock exchange requirements.

2. Risk Management, Internal Control and Information Systems

The Committee will review and obtain reasonable assurance that the risk management, internal control and information systems are operating effectively to produce accurate, appropriate and timely management and financial information. This includes:

(a) review the Trust’s and the Corporation’s risk management controls and policies;

(b) obtain reasonable assurance that the information systems are reliable and the systems of internal controls are properly designed and effectively implemented through discussions with and reports from management and the external auditors;

(c) review management steps to implement and maintain appropriate internal control procedures including a review of policies;

(d) satisfy itself that adequate procedures are in place for the review of the Trust’s public disclosure of financial information extracted or derived from the Trust’s financial statements and periodically assess the adequacy of those procedures;

(e) review the adequacy of security of information, information systems and recovery plans;

(f) monitor compliance with statutory and regulatory obligations;

(g) review the appointment of the CFO; and

(h) review the adequacy of accounting and finance resources.

3. External Audit

The Committee will review and oversee the planning and results of external audit activities including the appointment, compensation, retention and oversight of the work of the external auditors and the ongoing relationship with the external auditors who shall report directly to the Committee. This includes:

(a) review and recommend, for Unitholder approval, engagement of the external auditors including, as part of such review and recommendation, an evaluation of the external auditors’ qualifications, independence and performance;

(b) review and approve the annual external audit plan, including but not limited to the following:

(i) engagement letter;

(ii) objectives and scope of the external audit work;

(iii) procedures for quarterly review of financial statements;

(iv) materiality limit;

(v) areas of audit risk;

(vi) staffing;

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(vii) timetable; and

(viii) fees.

(c) meet with the external auditors to discuss the Trust’s quarterly and annual financial statements and other financial disclosures including the management’s discussion and analysis and the auditors’ audit or review engagement reports, as applicable, including the appropriateness of accounting policies and underlying estimates;

(d) review with the external auditors and advise the Board with respect to the planning, conduct and reporting of the annual audit, including but not limited to:

(i) any difficulties encountered, or restriction imposed by management, during the annual audit;

(ii) any significant accounting or financial reporting issue or disagreement with management;

(iii) the auditors’ evaluation of the Trust’s and Canetic’s systems of internal controls, procedures and documentation;

(iv) the post audit or management letter containing any findings or recommendation of the external auditors, including management’s response thereto and the subsequent follow-up to any identified internal control weaknesses;

(v) any other matters the external auditors bring to the Committee’s attention; and

(vi) assess the performance and consider the annual appointment of external auditors for recommendation to the Board;

(e) review the auditors’ report on all material subsidiaries;

(f) review and receive assurances on the independence of the external auditors;

(g) evaluate the performance of the lead partner of the external auditors;

(h) ensure the rotation of partners on the audit engagement team in accordance with applicable law. Consider whether, in order to ensure continuing external auditor independence, it is appropriate to adopt a policy of rotating the external audit firm on a regular basis;

(i) review the non-audit services to be provided by the external auditors’ firm or its affiliates (including estimated fees), and consider the impact on the independence of the external audit, all of which services shall be subject to pre-approval by the Committee;

(j) approve in advance all audit and permitted non-audit services to be provided to the Trust or any of its affiliates by the external auditors or any of their affiliates, subject to any de minimus exception provided by applicable law; the Committee may delegate to one or more designated members of the Committee the authority to grant pre-approvals required by this paragraph, provided that the decision of any such subcommittee to grant pre-approval must be presented to the full Committee at its next scheduled meeting;

(k) the Committee may establish policies and procedures for the pre-approval of audit and permitted non-audited services by the Corporation in its capacity as administrator of the Trust, so long as such policies and procedures are detailed as to the particular service, the Committee is informed of each service, and the policies and procedures do not include delegation of the Committee’s responsibilities under applicable laws and regulations to management;

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(l) if the Committee approves an audit service within the scope of the engagement of the external auditor, such audit service shall be deemed to have been pre-approved for purposes of the previous paragraph;

(m) review the disclosure with respect to its pre-approval of any audit and non-audit services provided by the external auditors;

(n) at least annually, obtaining and reviewing a report by the external auditors describing the auditor’s internal quality-control procedures, any material issues raised by the most recent internal quality-control review, or peer review, of the auditor or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, respecting one or more independent audits carried out by the firm, and any steps to deal with any such issues, and (to assess the external auditors’ independence) all relationships between the independent auditor and Canetic;

(o) at least annually, obtaining and reviewing a report by the external auditors describing (1) all critical accounting policies and practices used by the Trust, (2) all alternative accounting treatments of financial information within generally accepted accounting principles related to material items that have been discussed with management, including the ramifications of the use of such alternative treatments and disclosures and the treatment preferred by the external auditors, and (3) other material written communications between the external auditors and management of the Trust;

(p) obtain assurance from the external auditors that disclosure to the Committee is not required pursuant to the provisions of the Exchange Act regarding the discovery of illegal acts by the external auditors; and

(q) meet periodically, and at least annually, with the external auditors without management present.

4. Other

(a) review insurance coverage of significant business risks and uncertainties including Directors and Officers coverage;

(b) review material litigation and its impact on financial reporting;

(d) review the “Level of Authority Document” and provide recommendations to the Board;

(e) review fees paid to outside professional consultants, i.e. lawyers, accountants, other than consultants placed in operations in lieu of full time staff;

(f) ensure that there are no outstanding loans to directors, officers, employees or consultants of the Corporation;

(g) review policies and procedures for the review and approval of officers expenses and perquisites;

(h) establish procedures for the receipt, retention and treatment of complaints received by the Trust and Canetic regarding accounting, internal accounting controls or auditing matters and the confidential, anonymous submission by employees of concerns regarding questionable accounting or auditing matters;

(i) review and approve all hiring of employees and former employees of the present or former external auditors of the Trust or the Corporation and review and approve the Trust’s and Canetic’s policies with respect thereto;

(j) review the Committee’s terms of reference annually and make recommendations to the Board as required; and

(k) review all related party transactions between the Trust or Canetic and any officers or directors.

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D. ACCOUNTABILITY

The Committee shall report its activities and proceedings to the Board by distributing the minutes of its meetings or by oral or written report at the next Board meeting.

The Committee’s performance shall be evaluated annually pursuant to the assessment process established by the Nominating and Corporate Governance Committee and the Board.

E. STANDARDS OF LIABILITY

Nothing contained in these terms of reference is intended to expand applicable standards of liability under statutory, regulatory or other legal requirements for the Board or members of the Committee. The purposes and responsibilities outlined in these terms of reference are meant to serve as guidelines rather than inflexible rules and the Committee may adopt such additional procedures and standards as it deems necessary from time to time to fulfill its responsibilities.

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