**Exhibit 99.1**

**CANETIC RESOURCES TRUST**

**ANNUAL INFORMATION FORM**

**For theyear ended December 31, 2006**

**March 23,2007**

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**TABLE OF CONTENTS**
|                                                                                                          | ** ** | **Page** | ** ** |
|----------------------------------------------------------------------------------------------------------|------------|----------|------------|
| CANETIC  RESOURCES TRUST                                                                                 |       | 4        |       |
| BUSINESS  AND PROPERTIES                                                                                 |       | 6        |       |
| STATEMENT  OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION                                            |       | 18       |       |
| ADDITIONAL  INFORMATION RESPECTING CANETIC RESOURCES TRUST                                               |       | 36       |       |
| ADDITIONAL  INFORMATION RESPECTING CANETIC RESOURCES INC.                                                |       | 47       |       |
| AUDIT  COMMITTEE INFORMATION                                                                             |       | 50       |       |
| MARKET FOR SECURITIES                                                                                    |       | 52       |       |
| DISTRIBUTIONS                                                                                            |       | 54       |       |
| RISK  FACTORS                                                                                            |       | 55       |       |
| INTEREST  OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS                                              |       | 67       |       |
| INTEREST  OF EXPERTS                                                                                     |       | 67       |       |
| MATERIAL  CONTRACTS                                                                                      |       | 67       |       |
| LEGAL  PROCEEDINGS                                                                                       |       | 68       |       |
| AUDITORS,  TRANSFER AGENT AND REGISTRAR                                                                  |       | 68       |       |
| ADDITIONAL  INFORMATION                                                                                  |       | 68       |       |
| GLOSSARY  OF TERMS                                                                                       |       | 69       |       |
| ABBREVIATIONS                                                                                            |       | 76       |       |
| CONVERSIONS                                                                                              |       | 77       |       |
|                                                                                                     |       |     |       |
| APPENDIX “A” — REPORT  OF 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      |       |

 

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**SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS**

Certain statementscontained in this Annual Information Form constitute forward-looking statementsor information (collectively “**forward-looking statements**”)within the meaning of applicable securities laws.  All statements other than statements ofhistorical fact may be forward looking statements.  Statements relating to “reserves” or “resources”are deemed to be forward-looking statements as they involve the impliedassessment, based on certain estimates and assumptions, that the reserves andresources described can be profitably produced in the future.

The use of any of thewords “anticipate,” “continue,” “estimate,” “expect,” “may,” “will,” “project,”“could,” “should,” “believe,” “intend,” “propose,” “budget” and similarexpressions are intended to identify forward-looking statements.  These statements involve known and unknownrisks, uncertainties and other factors that may cause actual results or eventsto differ materially from those anticipated in such forward-lookingstatements.  We believe the expectationsreflected in the forward-looking statements are reasonable but no assurance canbe given that these expectations will prove to be correct and suchforward-looking statements are not guarantees of future performance and shouldnot be unduly relied upon.  Thesestatements speak only as of the date of this Annual Information Form.

In particular, thisAnnual Information Form contains forward-looking statements pertaining to thefollowing: business strategies; production volumes and capacity, processingcapacity; reserves volumes, operating and other costs, drilling plans;commodity prices; future cash distribution levels and taxability; payoutratios; capital spending including timing, allocation and amounts of capitalexpenditures and the sources of funding thereof; regulatory changes; hedgingand other risk management programs; anticipated tax obligations; supply anddemand for oil and natural gas; ability to raise capital; ability to add toreserves through acquisitions and development; treatment under governmentalregulatory regimes; acquisition plans; the impact of acquisitions and thetiming for achieving such impact; future tax treatment of income trusts such asthe Trust; the benefits of the Trust’s size and the size of its inventory; andliquidity and financial capacity.

The forward-lookingstatements contained in this Annual Information Form are based on a number ofexpectations and assumptions that may prove to be incorrect.  In addition to other assumptions identifiedin this Annual Information Form, assumptions have been made regarding, amongother things: that the Trust will continue to conduct its operations in amanner consistent with past operations; the continuance of existing (and incertain circumstances, proposed) tax and royalty regimes; the generalcontinuance of current industry conditions; the accuracy of the estimates ofthe Trust’s reserve volumes; the ability of Canetic to obtain equipment,services and supplies in a timely manner to carry out its activities; theability of Canetic to market oil and natural gas successfully; the timelyreceipt of required regulatory approvals; the ability of Canetic to obtainfinancing on acceptable terms; currency, exchange and interest rates; futureoil and gas prices and future cost assumptions. No assurance can be given that these factors, expectations andassumptions will prove to be correct.

The actual results coulddiffer materially from those anticipated in these forward-looking statements asa result of the risk factors set forth below and elsewhere in this AnnualInformation Form: volatility in market prices for oil and natural gas; risksand liabilities inherent in oil and natural gas including operations,exploration, development, exploitation, production, marketing andtransportation risks; uncertainties associated with estimating oil and naturalgas reserves; competition for, among other things, capital, acquisitions ofreserves, undeveloped lands and skilled personnel; incorrect assessments of thevalue of acquisitions; inability to complete acquisitions on commerciallyacceptable terms; inability to raise necessary capital on commerciallyacceptable terms or at all; geological, technical, drilling and processingproblems; risks and uncertainties involving geology of oil and gas deposits;unanticipated operating results or production declines; fluctuations in foreignexchange, currency or interest rates and stock market volatility; changes inlaws and regulations, changes including but not limited to those pertaining toincome tax, environmental and regulatory matters; failure to realize theanticipated benefits of acquisitions; health, safety and environmental risks;and the other factors described in Canetic’s public filings from time to time(including under “Risk Factors” in this Annual Information Form and under “RiskManagement” in Canetic’s Management’s Discussion & Analysis (MD&A))available in Canada at www.sedar.com and in the United States atwww.sec.gov.  They may also be obtainedby contacting our Investor Relations department at (403) 539-6300 or1-877-539-6300.  Readers are cautionedthat this list of risk factors should not be construed as exhaustive.

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The forward-lookingstatements contained in this Annual Information Form are expressly qualified bythis cautionary statement.  Caneticundertakes no obligation to publicly update or revise any forward-lookingstatements except as expressly required by applicable securities law.

**NON-GAAP MEASURES**

This Annual InformationForm, refers to certain financial measures that are not determined inaccordance with Canadian generally accepted accounting principles (“**GAAP**”).  Thesemeasures as presented do not have any standardized meaning prescribed by GAAPand therefore they may not be comparable with calculations of similar measuresfor other companies or trusts.

Management uses fundsflow from operations, which we define as net earnings plus non-cash itemsbefore deducting non-cash working capital and asset retirement costs incurredto analyze operating performance and leverage. Readers should refer to the “Funds Flow from Operations” section of theMD&A for a reconciliation of funds flow from operations.

We use the term net debt,which we define as long-term debt and working capital, to analyze liquidity andcapital resources.  Readers should referto the “Liquidity and Capital Resources” section of the MD&A for areconciliation of net debt.  We use theterm payout ratio, which we define as cash distributions to unitholders dividedby funds flow from operations, to analyze financial and operatingperformance.  Readers should refer to the“Cash Distributions” section of the MD&A for the calculation of payoutratio.

Management believes that,in conjunction with results presented in accordance with GAAP, these measuresassist in providing a more complete understanding of certain aspects of theTrust’s results of operations and financial performance.  Investors are cautioned however, that thesemeasures should not be construed as an alternative to measures determined inaccordance with GAAP as an indication of our performance.

**EFFECTIVE DATE OF INFORMATION**

**Exceptwhere otherwise indicated, the information in this Annual Information Form andin the Canetic Trust Engineering Report assumes that the Arrangement wascompleted on December 31, 2005, and assumes that the properties and assetsof the Operating Entities acquired pursuant to the Arrangement were acquired bythe Operating Entities on December 31, 2005. See also*“Canetic Resources Trust — The Arrangement”*.**

**CANETIC RESOURCES TRUST**

**General**

Canetic Resources Trust(the “**Trust**”) is an open-endunincorporated trust established under the laws of the Province of Albertapursuant to the Trust Indenture.  Theprincipal office of the Trust is located at 1900, 255 - 5th Avenue S.W., Calgary, Alberta, T2P 3G6.

The Trust owns, directlyor indirectly, all of the outstanding common shares of Canetic (“**Canetic Common Shares**”), all of theoutstanding Canetic Notes, the Canetic NPIs and securities of the otherOperating Entities.  Canetic is thecorporation resulting from the amalgamation of AEI, SEL and certain othersubsidiaries.

Canetic and the otherOperating Entities are actively involved in the acquisition, production,processing, transporting and marketing of crude oil, natural gas liquids andnatural gas primarily in Alberta, British Columbia, Saskatchewan, Manitoba,North Dakota, Montana and Wyoming.  TheTrust participates in the funds flow from such business through its direct andindirect ownership of the Operating Entities Securities.

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**OrganizationalStructure of Canetic Resources Trust**

The followingdiagram sets forth the simplified organizational structure of the Trust:

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**Notes:**

(1)                                  Unitholdersown 100% of the equity of the Trust.

(2)                                  Cashdistributions are made to Unitholders monthly based upon, among other things,the Trust’s funds flow from operations.

(3)                                  TheOperating Entities are direct or indirect wholly owned subsidiaries of theTrust.

(4)                                  TheTrust receives royalty, interest, dividends and other distributions on or inrespect of the Operating Entities Securities.

**The Arrangement**

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

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

·                  theholders of Acclaim Unitsexchanged each Acclaim Unit for 0.8333 of a Unit of Canetic;

·                  theholders of StarPoint Unitsexchanged each StarPoint Unit for one (1) Unit of Canetic;

·                  holdersof 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 0.1of a TriStar Common Share for each StarPoint Unit;

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·                  holdersof Acclaim Units received 0.0175 of a TriStar Arrangement Warrant for eachAcclaim Unit held and holders of StarPoint Units received 0.0210 of a TriStarArrangement Warrant for each StarPoint Unit held; and

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

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

**SummaryDescription of Business**

***Canetic Resources Trust***

The principal undertakingof the Trust is to indirectly acquire and hold, through Canetic and the otherOperating Entities, interests in petroleum and natural gas properties andassets related thereto.

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

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

The Trust’s distributionsare currently set at $0.19 per Unit per month. Future distributions and are subject to the discretion of the Board ofDirectors and may vary depending on, among other things, the current andanticipated commodity price environment. See also “*Risk Factors*.”

***Operating Entities***

Canetic, directly andthrough the other Operating Entities, is actively involved in the acquisition,development, exploitation, production, processing, upgrading and marketing ofcrude oil, natural gas liquids and natural gas primarily in Alberta, BritishColumbia, Saskatchewan, Manitoba, North Dakota, Montana and Wyoming.  See also “*Businessand Properties*”, “*Statement ofReserves Data and Other Oil and Gas Information*” and “*Additional Information Respecting Canetic ResourcesInc*.”.

**BUSINESS AND PROPERTIES**

Since January 5, 2006Canetic 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 andnatural gas primarily in Alberta, British Columbia, Saskatchewan, Manitoba,North Dakota, Montana and Wyoming. References in this section to Canetic include the other OperatingEntities unless the context otherwise requires.

**GeneralDevelopment of the Business**

Certain informationrelating to the oil and natural gas properties discussed in this AnnualInformation Form is limited to the period of time during which Canetic, Acclaimor StarPoint were the owners of such properties.  Any information relating to periods prior tothe effective date of such acquisitions is based upon publicly availableinformation or the records of Canetic, Acclaim or StarPoint, as the case maybe.  While Canetic has no reason tobelieve that such information is not accurate, Canetic can provide no assurancethat such information is accurate.

 

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The principal business ofCanetic is to acquire, explore for, develop and produce oil and natural gasreserves primarily in western Canada and the northern U.S.  Canetic focuses its efforts primarily onacquisition and subsequent exploitation opportunities, especially those thatare expected to offer a stable production base with the potential of upsidethrough development drilling and production optimization.  Canetic endeavors to maintain a high workinginterest in its core areas, which is expected to enable it to maximizeoperational flexibility and to better control the nature and timing of itsexpenditures.

**Acclaimand StarPoint Significant Transactions**

As the Trust was formedas a result of the combination of the business of Acclaim and StarPointpursuant to the Arrangement (see “*Canetic Resources Trust —The Arrangement*”), the following is a description of the significanttransactions in the development of Acclaim and StarPoint prior to theArrangement.

***AcclaimSignificant Transactions***

***Danoil Merger***

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

***Ketch Energy Arrangement***

On October 1, 2002, Acclaimcompleted the Ketch Energy Arrangement pursuant to which it indirectly acquiredall of the issued and outstanding common shares of Ketch Energy in exchange forapproximately 22.4 million Acclaim Units. Ketch Energy was a natural resource company focusing its efforts onexploring for, developing, acquiring and producing petroleum and natural gas inthe Western Canadian Sedimentary Basin. As part of the Ketch Energy Arrangement, the Ketch ExploreCo Assets weresold to Ketch Resources Ltd. and the common shares of Ketch Resources Ltd. weredistributed to the former holders of Ketch Energy common shares.  At the time of completion, the Ketch EnergyArrangement added production of approximately 9,700 Boe/d, 36,634 MBoe ofEstablished Reserves****and approximately247,000 net acres of undeveloped lands to Acclaim.

The completion of theKetch Energy Arrangement also resulted in the reconstitution of the managementand a number of the directors of AEI.

As a condition ofthe Ketch Energy Arrangement, AEI acquired all of the issued and outstandingshares of Acclaim Energy Management Inc., the former manager of AEI, inexchange for the issuance of 705,083 Acclaim Preferred Shares (subsequentlyexchanged for an equivalent number of Acclaim Exchangeable Shares) with theresult that the management agreement with Acclaim Energy Management Inc. wasterminated.

***Elk Point Arrangement***

On January 28, 2003,Acclaim completed the Elk Point Arrangement pursuant to which it acquired allof the issued and outstanding common shares of Elk Point in exchange forapproximately 10.52 million Acclaim Units and $10.9 million in cash.  Acclaim also assumed Elk Point’s net totaldebt in the approximate amount of $56 million. Elk Point was a natural resource company focusing its efforts on exploringfor, developing, acquiring and producing petroleum and natural gas in theWestern Canadian Sedimentary Basin and in the Powder River Basin of the UnitedStates.  As part of the Elk PointArrangement, the Burmis Assets were sold to Burmis Energy Inc. and the commonshares of Burmis Energy Inc. were distributed to the former holders of ElkPoint common shares.  The Burmis Assetswere comprised of oil and gas properties in the Powder River Basin of Wyomingand the San Joaquin Basin of California and certain minor Albertaproperties.  Completion of the Elk PointArrangement added producing oil and gas properties located principally in thewest central and Peace River Arch areas of Alberta producing approximately 

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6,200 Boe/d and 135,000net acres of undeveloped lands.  At thetime of the transaction, the Established Reserves associated with theseproperties were estimated to be approximately 18,500 MBoe.

***Gilby/Willesden GreenAcquisition***

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

The Gilby/Willesden GreenProperties include unit and non-unit interests in the Willesden Green and Gilbyareas of west central Alberta.  Theproperties are highly concentrated, 90% operated and adjacent to Acclaim’sexisting properties in its western region. The Gilby/Willesden Green Acquisition also includes working interests inthe Willesden Green and Gilby West natural gas plants and 100% ownership andoperatorship of several oil batteries in the area.

Production from theGilby/Willesden Green Properties at the time of acquisition was approximately3,550 Boe/d, comprised of 9.9 MMcf/d of natural gas and 1,900 Bbls/d of lightcrude oil and natural gas liquids.  TheEstablished Reserves attributable to the Gilby/Willesden Green Properties as atApril 1, 2003 were estimated to be approximately 8,422 MBbls of crude oil,31,728 MMcf of natural gas and 785 MBbls of natural gas liquids, for a total of14,495 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 ofapproximately $68.4 million.  Theeffective date of the NG Acquisition was July 1, 2003.

Production from the NGProperties at the time of acquisition was approximately 3,000 Boe/d, comprisedof 13.5 MMcf/d of natural gas and 750 Bbls/d of light crude oil and natural gasliquids.  Approximately 80% of theproduction associated with the NG Properties is located in AEI’s core operatingareas.  At July 31, 2003, theEstablished Reserves attributable to the NG Properties were estimated to beapproximately 2,507 MBbls of crude oil, 35,665 MMcf of natural gasand 671 MBbls of natural gas liquids, for a total of 9,122 MBoebefore deduction of royalties.

***Exodus Acquisition***

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

At the time ofacquisition, Exodus’s production was approximately 2,000 Boe/d and 90%operated.  Approximately 85% of theproduction was heavy oil and approximately 15% was comprised of natural gas andlight crude oil.  Exodus’s significantproperties included Greater Furness, located between Acclaim’s existing westernSaskatchewan heavy oil properties of Tangleflags and Baldwinton and properties atJoarcam, Beaverhill Lake and Killam in eastern Alberta.  Exodus’s Established Reserves at the time ofacquisition were estimated to be approximately 5.1 million Boe, comprisedof 4.2 million Bbls of heavy oil, 470,000 Bbls of light crude oil andnatural gas liquids and 2.9 Bcf of natural gas.

***Chevron TexacoAcquisition***

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

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Production fromthe Chevron Texaco Properties at the time of acquisition was approximately17,000 Boe/d including 34.0 MMcf/d of natural gas and 11,400 Bbls/d of lightcrude oil and natural gas liquids.  TheChevron Texaco Properties are complementary to Acclaim’s properties in central,western and northern Alberta, and also provided it with a position in longlife, high-quality production in western Manitoba.  The major operated properties in the ChevronTexaco Acquisition were Acheson (100% working interest) and Mitsue (28.1%working interest).  Non-operatedproperties included Kaybob (50% working interest) and Manitoba (40% workinginterest).  Proved and Probable Reservesattributable to the Chevron Texaco Properties at the time of acquisition, basedon a third party independent appraisal, were estimated at approximately 35.4million Boe, comprised of 18.9 million Bbls of light crude oil, 5.6 millionBbls of natural gas liquids and 65.3 Bcf of natural gas.

**StarPointSignificant Transactions**

***Creation ofStarPoint Energy Ltd.***

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

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

***Acquisition of Upton***

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

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

***E3 Plan of Arrangement andCreation of StarPoint Energy Trust***

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

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

***Acquisition ofSelkirk***

On January 28, 2005, StarPoint acquired all of theissued and outstanding shares of four private corporations for aggregate netcash 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 theDeep Basin area of Alberta, approximately 75 kilometers southwest of the cityof Grand Prairie.  Production wasprimarily from the Chinook formation at Red Rock, with minor volumes fromElmworth and Wapiti.  Selkirk had anaverage working interest of 38% in its Deep Basin assets.  At Red Rock, Selkirk’s interest was limitedto production from certain wellbores from the Chinook Formation.

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

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***The APF Plan ofArrangement***

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

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

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

***The EnCanaAcquisition***

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

The EnCana assets included properties located insouthern Alberta at Countess, Provost and Alderson.  Production from these assets for the threemonths ended March 31, 2005 was 6,890 Boe/d weighted 86% to oil and 14% to gasand natural gas liquids.

***The NexenAcquisition***

On August 9, 2005, StarPoint indirectly acquiredcertain assets from Nexen Inc. (“**Nexen**”) foraggregate cash consideration of $317.3 million.

The Nexen Assets are located in southeastSaskatchewan, approximately 210 kilometers southeast of Regina.  The properties feature a land base situatedalong 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 June30, 2005 was 6,350 Boe/d.  Oil productionfrom the assets is generally light sweet crude with a 38° API.  The acquired properties include Edenvale,Ingoldsby, Nottingham, Cantal and Queensdale.

**CaneticSignificant Transactions**

***Samson Acquisition***

On August 24, 2006, theTrust completed the indirect acquisition of the Hoadley and B.C. Properties fora purchase price of approximately $930 million, subject to customary closingadjustments.  The Hoadley and B.C.Properties consisted of oil, natural gas and natural gas liquids assets locatedin Alberta and northeastern British Columbia with production weighted approximately86% natural gas and 14% light oil and natural gas liquids, which as at July 1,2006 were producing approximately 81 MMcf of natural gas equivalent per day(13,500 boe/d), before deduction of royalties owed to others (comprised ofapproximately 70.0 MMcf/d of natural gas and 1,830 Bbls/d of oil and naturalgas liquids).  Approximately 80% of the production from the properties isoperated.  At the time of thetransaction, the Proved plus Probable Reserves associated with these propertieswere estimated to be approximately 40.1 MMBoe. Included in the Hoadley and B.C. Properties were approximately 333,600gross (230,000 net) acres of undeveloped land at an average 69% workinginterest.

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**Oiland Gas Properties**

The following is adescription of Canetic’s principal oil and natural gas properties.  Unless otherwise specified, productionestimates, gross and net acres and well count information are as at December31, 2006.  Reserve amounts are stated,before deduction of royalties as at December 31, 2006, based on escalating costand price assumptions as evaluated in the Canetic Trust EngineeringReport.  The estimates of reserves andfuture net revenue for individual properties may not reflect the sameconfidence level as estimates of reserves and future net revenue for allproperties due to the effects of aggregation.

Canetic’s operations areentirely land-based and are focused primarily in western Canada, concentratedin eightgeographic operating districts.  Caneticoperates approximately 80 percent of its production and has alarge opportunity profile for continued growth through its detailed technicalanalysis and operational expertise. Canetic has minor interests in the United States.

***Williston Basin District***

*The Williston Basin districtincludes properties located in southeast Saskatchewan, Manitoba, North Dakota,Montana and Wyoming.  In total 134 (67.1net) wells were drilled on these properties during 2006, including 72 (36.3net) oil and 62 (30.8 net) gas.*

*GreaterQueensdale, Saskatchewan*

The Greater Queensdaleassets are located in southeast Saskatchewan about 100-150 kilometers north andeast of Estevan.  This area includes theIngoldsby, Queensdale, Gainsborough, Cantal and Edenvale properties.

The main producing assetsof this area include portions of the Queensdale Frobisher-Alida Pool, AlidaWest Frobisher-Alida Pool (Edenvale), Cantal Frobisher-Alida Pool, NottinghamSouth Frobisher-Alida Pool, and the Ingoldsby Frobisher Alida Pool.  The light oil (30-38°API) is produced fromthe Frobisher-Alida beds at 1,000 to 1,400 meters in depth.  Substantially all of the production in whichCanetic has an interest is pipelined to company owned central facilitiesincluding oil, gas and water separation and treating equipment, crude oilpipeline connection, and salt water disposal facilities.  Canetic has a working interest in theNAL-operated Nottingham gas plant at 8-17-5-32 W1M and associated gas-gatheringsystem where the majority of the area’s conserved solution gas is processed.

*GreaterMidale, Saskatchewan*

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

The main producing assetsin 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 fromthe Midale and Frobisher beds at 1,200 to 1,400 meters in depth.  Substantially all of the production in whichCanetic has an interest is pipelined to central facilities owned by Caneticincluding oil, gas and water separation and treating equipment, a crude oilpipeline connection, and salt water disposal facilities.  Some batteries and treating facilities areconnected to solution gas gathering infrastructure, thereby resulting in smallquantities of solution gas sales.  Someproduction is produced to single well batteries where oil and water areseparated and trucked to Canetic owned batteries for processing and sale.

*Heward/Handsworth,Saskatchewan*

The Heward/Handsworthassets are located in southeast Saskatchewan about 100 kilometers north ofEstevan.  These properties include theHeward, Handsworth, Coyote Lake and Pheasant Rump properties.

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The main producingassets in this area include portions of the Heward Frobisher-Alida Pool,Hartaven Alida Pool, Melrose Frobisher-Alida Pool, Handsworth Alida Pool andPheasant Rump Alida Pool.  The medium tolight oil (26-32° API) is produced from the Frobisher-Alida beds at 1,000 to1,100 meters in depth.  Substantially allof the production in which Canetic has an interest is pipelined to companyowned central facilities including oil, gas and water separation and treatingequipment, a crude oil pipeline connection, and salt water disposalfacilities.  Some batteries and treatingfacilities are connected to solution gas gathering infrastructure, therebyresulting in small quantities of solution gas sales.  Some company production is produced to singlewell batteries where oil and water are separated and trucked to company ownedbatteries for processing and sale.

*NorthDakota and Montana, USA*

The properties located ineastern Montana and southwest North Dakota, USA are about 200-300 kilometerssouth of Estevan.  Canetic has workinginterests ranging from 19% to 100%.

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

Substantially all of theproduction in which Canetic has an interest is produced to single wellbatteries where oil, water and gas are separated; gas is consumed as well sitefuel or flared.  Oil and water aretrucked for sale and disposal respectively.

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

The Wyoming propertiesare located in the Powder River Basin, north of Casper.  The properties are comprised of 10,141 netacres of undeveloped land with an average working interest of 47%.  During 2006, 62 (30.8 net) development CBMwells were drilled on these properties. Assets at Big Bend, North Carson, Coal Gulch, and Kane target the BigGeorge, Anderson, Canyon/Cook, Wall/Pawnee and Wyodak coals at depths rangingfrom 100 to 700 meters.

***Southern District***

*TheSouthern district includes properties located in southern Alberta and southwestSaskatchewan.  In total 62 (31.0 net)wells were drilled on these properties during 2006, including 28 (20.3 net)oil, 31 (8.9 net) gas and 3 (1.8 net) dry and abandoned.*

*Countess,Alberta*

The Countess propertiesare located in southern Alberta, approximately 130 kilometers southeast ofCalgary.  The properties in this area havea working interest between 50 and 100% for the oil assets and 17.5 to 100% forthe gas assets.

These assets arecomprised of Mannville oil and shallow Medicine Hat/Milk River gas.  The gas wells are drilled at an average depthof 550 meters.  Canetic gas handlingfacilities at Countess are comprised of a compressor and processing facilityand several booster compressors.  Thecompression facilities boost the gas to sales pipeline operating pressures.

The majority ofthe Countess oil production is obtained from the Rosemary Lower Mannville Z andRR oil pools and the Duchess Lower Mannville X and VVV oil pools, which arecurrently under active waterflood schemes. The medium oil (26-33° API) is produced from Lower Mannville sandstonesat 1,100 to 1,200 meters in depth.

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

*Alderson,Alberta*

The Aldersonproperties are located in southern Alberta, approximately 190 kilometerssoutheast of Calgary.  The properties inthis area have an average operated working interest of 100%.

The majority ofthe Alderson production is obtained from the Suffield West Arcs D and LowerMannville D3D and E3E oil pools and several Alderson Lower Mannville oil pools,which are currently under active waterflood schemes.  The medium oil (27-31° API) is produced fromLower Mannville sandstones at 900 to 1,000 meters in depth and the Arcs Niskucarbonate formation at approximately 1,250 meters in depth.

Substantially all of theAlderson production is pipelined to one of four 100% working interest centralfacilities located at Suffield West and Alderson.  The central facilities will include oil, gasand 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 producedto single well batteries where oil and water is separated and trucked tovarious area facilities for processing and sale.

*Sibbald/Acadia,Alberta*

The Sibbald/Acadiaproperty is located approximately 260 kilometers east of Calgary.  Canetic has an average working interest of67%.  The facilities on the property inwhich Canetic has an interest consist of two multi-well oil batteries and onesingle well oil battery.

***Border PlainsDistrict***

*TheBorder Plains district includes properties located in east central Alberta andwest central Saskatchewan.  In total 27(13.6 net) wells were drilled on these properties during 2006, including 22(10.5 net) oil, 3 (1.1 net) gas, and 2 (2.0 net) disposal wells.*

*Provost,Alberta*

The Provost propertiesare located in eastern Alberta, approximately 260 kilometers southeast ofEdmonton.  The properties in this areahave an average operated working interest of approximately 100%.

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

The majority ofthe production is processed through a pipeline connected 100% working interestcentral facility located at Provost.  Thecentral facility includes oil, gas and water separation and treating equipment,a crude oil pipeline connection, salt water disposal facilities, and solutiongas gathering facilities.  Gas productionat Hayter is custom processed through a third party facility.

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*Furness,Saskatchewan*

The greaterFurness area is located in western Saskatchewan in Townships 48 and 49, Ranges26 through 28 W3M.  Furness was acquiredlate in 2003 pursuant to the acquisition of Exodus Energy Ltd. and is primarilya heavy oil field.  The primary producingzone of interest is the Sparky Sand, with additional production provided fromthe McLaren and General Petroleum Formations.

Canetic has a 75% workinginterest in a central oil battery that is connected to a sales oilpipeline.  The battery is located at14-08-048-27W3M and is capable of handling 1,600 Bbls/d of oil.

***South Central District***

*The South Central district includesproperties located in central Alberta. In total 33 (19.4 net) wells were drilled on these properties during2006, including 14 (8.2 net) oil, 16 (8.7 net) gas and 3 (2.5 net) dry andabandoned.*

*Acheson,Alberta*

The Acheson area is westof Edmonton and includes interests in the Acheson D-3a Unit, the Acheson LowerCretaceous Unit No. 1, the Acheson North D-2 Pool Unit and non-unitproduction.  Canetic’s overall workinginterest in the area is 99.7%.

Gas is processed at the100% working interest operated 5-2-53-26W4M Acheson gas plant, capable ofprocessing 24 MMcf/d of gas.  The oilfrom the 100% owned Acheson field is processed at the unit battery and fluidhandling facility located at the 5-2-53-26W4 site.

Acheson is amulti-zone area with production coming from the Leduc, Nisku, Detrital, BasalQuartz and Viking zones.  The LeducFormation is characterized by the development of numerous isolated reefcomplexes and a broad carbonate shelf, all of which developed on the CookingLake platform and is responsible for the majority of Acheson’s currentproduction.  The D-3a Pool started blowdown in June 2003 by the controlled production of reservoir and injectedhydrocarbons following the termination of an enhanced recovery scheme toincrease the recovery of original oil reserves.

*GoldenSpike, Alberta*

The Golden Spike area islocated approximately eight kilometers west of Edmonton.  Working interests in the area vary, with themajority of working interests ranging from 95 to 100%.  The vast majority of the wells and related facilitiesare Canetic operated, and much of the gas is transported to and processed atthe Acheson Gas Plant.  Gas reserves inthe area occur largely in the Lower Cretaceous Mannville, with oil reservesbeing identified in the Mannville, Wabamun and Leduc Formations.

*Corbett Creek, Alberta*

The Corbett Creek area islocated approximately 125 km northwest of the city of Edmonton.  Working interests vary from 40 to 100% in theMannville CBM play that has developed in the area over the past few years.  Canetic has both operated and non-operatedinterests in this play and participated with 3 joint venture partners in 2006in the drilling of 9 wells (3.9 net). Production is obtained by drilling single to multi leg horizontalstargeting a 2 to 3 meter thick coal at approximately 975 mTVD.  Horizontal legs can be over 1500 meters inlength.

***North Central District***

*TheNorth Central district includes properties located in central Alberta.  In total 2 (0.2 net) gas wells were drilledon these properties during 2006.*

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*Mitsue,Alberta*

The Mitsue oil field islocated near Slave Lake in north central Alberta approximately 125 miles northof Edmonton.  AEI purchased a 28.1%working interest in the Mitsue Gilwood Sand Unit No.  1, which encompasses the majority of thefield, and a 14.4% working interest in the Calpine operated Mitsue Gilwood SandUnit No. 2.  AEI assumed operatorship ofUnit No. 1 following the acquisition of assets from ChevronTexaco on June 30,2004.  Canetic also has various interestsin non-unit production in this area.

The oil from the MitsueGilwood Sand Units Nos. 1 and 2 is collected at one of 37 satellites where thefluids are commingled and moved via three-phase group lines to one of threemain batteries.  The main batteriesconsist of separation, compression, treating, fresh water injection, waterdisposal and storage facilities.  Thetreated oil is shipped to Edmonton for sale through the Rainbow Pipeline.  The solution gas is collected at the mainbatteries, compressed and sent to the unit Mitsue Gas Plant located at16-30-072-04W5M.  The current averagethroughput of the plant is 7.0 MMcf/day of gas. The plant consists of sweetening, turbo expansion and refrigeration.

***Rocky District***

*The Rocky district includesproperties located in west central Alberta. In total 76 (28.3 net) wells were drilled on these properties during 2006,including 6 (3.0 net) oil, 69 (24.5 net) gas and 1 (0.8 net) dry and abandoned.*

*WillesdenGreen, Alberta*

The Willesden Green areais located approximately 125 kilometers southwest of Edmonton.  The properties include unit and non-unitinterests, with the majority of the production operated and with high workinginterests.  The unit interests consist offour producing oil units, with two large operated units and one wholly ownedproject area producing light oil (41° API) from the Cardium formation.  Two other units (one operated) produce longlife light crude oil and natural gas from the Viking formation.  The properties have opportunities for infilldrilling on 160 acres, opportunities to enhance water flood performance, andseveral stimulation candidates.  Thenon-unit interests produce light gravity crude oil from the Cardium formationand 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 tomoderate drill depths and a large concentrated land position with the majorityof the lands operated.  There are alsodeeper Mannville drilling targets defined by seismic data, as well as manyprospects in the shallower Belly River, Edmonton, Paskapoo and Scollardformations.  Canetic owns the facilitiesassociated with the production, as well as a 21.7% interest in the Imperial OilLtd. Willesden Green natural gas plant. Canetic also owns a 20 MMcf/d gas processing facility, with pipelineinfrastructure that allows Canetic to process the majority of our production inthis area in our owned gas plant.  Thisplant was constructed in late 2006 and early 2007, and was commissioned inFebruary 2007.

*Gilby/MedicineRiver, Alberta*

The Gilby area is situatedapproximately 30 kilometers southeast of the Willesden Green properties, andproduces light crude oil and sweet natural gas from a number of zones in thismulti-target area.  The property wasacquired pursuant to the Gilby/Willesden Green Acquisition and consists of sixunits (three operated) and non-unit holdings producing from early Cretaceousand Jurassic sands.  Opportunities existfor infill drilling and production optimization.  The property includes a 24.8% workinginterest in the Gilby West natural gas plant, of which Canetic was electedoperator, and working interests in a number of operated facilities.

*Hoadley/Ferrybank, Alberta*

The Hoadley — Ferrybankarea is located 90 kilometers southwest of Edmonton.  This property was purchased by Canetic in2006 in the Samson Acquisition. Production is entirely natural gas and associated liquids primarily fromthe Hoadley Barrier Bar complex in the Glauconite formation at a depth rangingfrom 1550 to 1850 mTVD.  Other producinghorizons include the Edmonton Sand, the Ellerslie, and Colony.  This property includes 204,000 net developedand undeveloped acreage with an average working interest of roughly 67%.  90% of the production is operated byCanetic.  Canetic operates 37 compressorsin the area and has ownership in 9 others. Gas is processed 

15

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primarily through theRimbey plant operated by Keyera Energy Ltd. Canetic has a 41% ownership in the Encana Oil and Gas Partnershipoperated Ferrybank plant at 2-1-44-28 W4 that has a capacity of 35 mmcf/d.  Canetic has a 13.24% ownership in the MikwanPlant operated by Vermillion Resources Ltd. that has a capacity of 9.5 mmcf/d.

*Innisfail, Alberta*

The Innisfail propertiesare located in central Alberta, south of Red Deer.  Drilling activity at Innisfail targets shallowEdmonton and Belly River gas, deeper Pekisko gas, and Leduc oil.  Natural gas is transported via Canetic’sowned central gathering system 30 kms south to the Garrington Sour Gas Plantoperated by Esprit Exploration Ltd. Leduc oil is gathered via pipeline to a central battery then shipped bypipeline to a third party facility for processing.

***Drayton Valley District***

*TheDrayton Valley district includes properties located in western Alberta.  In total 26 (6.3 net) wells were drilled onthese properties during 2006, including 12 (2.1 net) oil, 11 (4.0 net) gas, and3 (0.2 net) service.*

*Brazeau/Bigoray,Alberta*

There are 10 NiskuPools in the Bigoray, Brazeau, and West Pembina areas.  Canetic is the operator of all thesepools.  Eight of the pools were onmiscible flood, seven of which are now on blow down.  The Bigoray group includes the Bigoray NiskuD Unit No. 1 (“**BND**”) at a 75%working interest, the Bigoray Nisku F Pool (“**BNF**”)at a 50% working interest and the West Pembina Nisku D Pool (“**WPND**”) at a 50% working interest.  All three of these pools were under miscibleflood, but are now currently on blow down.

Gas from the 10 NiskuPools is processed at one of the following three Keyera Energy Ltd. operatedfacilities: the 10-07-051-09W5 Bigoray Gas Plant; the 16-35-048-12W5 BrazeauRiver Gas Plant; or the 11-22-049-12W5 West Pembina Gas Plant.

*Kaybob,Alberta*

The Kaybob districtcovers a very large geographic area approximately 250 kilometers northwest ofEdmonton.

*KaybobGas — Kaybob South Beaverhill Lake Unit Nos. 2 and 3*

The Kaybob natural gasproduction comes from the Kaybob South Beaverhill Lake Unit Nos. 2 and 3.  The units are located south of the town ofFox Creek.  BP Canada operates Unit No. 2and Trilogy Energy operates Unit No. 3. AEI purchased, an 11% working interest in Unit No. 2 and a 25.6% workinginterest in Unit No. 3 in June of 2004 as part of the ChevronTexacoacquisition.  Production is from the SwanHills formation of the Middle Devonian Beaverhill Lake Group.  The reservoir was a retrograde gas condensatereservoir, and as a result, all three units were initially produced on a gasrecycle scheme to maintain the reservoir pressure above the hydrocarbon dewpoint.  All three units are now on blowdown.

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

*KaybobSouth Triassic Unit No. 2*

Canetic owns a 23.3%working interest in the Kaybob South Triassic Unit No. 2, which is operated byPrime West Energy Inc.  The Kaybob SouthTriassic Unit No. 2 produces 42° API oil and associated natural gas from theTriassic Montney Formation.  The oil fromKaybob Triassic Unit No. 2 is processed at a central unit battery located at03-24-062-20W5 operated by Prime West Energy Inc.  The battery is equipped with solution gas recoveryand compression.  The solution gas iscompressed and shipped to the Central Alberta Midstream operated KaybobAmalgamated Gas Plant at 12-01-062-20W5 for processing.

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*Simonette,Alberta*

The Simonette BeaverhillLake A and B Pools are located approximately 150 kilometers southeast of GrandePrairie.  Canetic owns a 35.5% workinginterest in the A Pool and a 26.3% working interest in B Pool.  These pools produce from the Beaverhill LakeGroup.

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

***Peace River Arch District***

*The Peace River Arch districtincludes properties located in northwest Alberta and northeast BritishColumbia.  In total 18 (8.7 net) wellswere drilled on these properties during 2006, including 7 (1.5 net) oil and 11(7.2 net) gas.*

*PouceCoupe, Alberta*

The Pouce Coupeproperties are located approximately 80 kilometers northwest of GrandePrairie.  Canetic operates the PouceCoupe South Boundary ‘B’ Unit No. 2 with a 62.8% working interest.  This high netback, light oil unit includes anoil battery and water injection facility, as well as amine, refrigeration andgas compression facilities.  Productionwithin the unit is obtained from the Boundary Lake member of the Charlie Lakeformation.  Canetic also holds a 20.793%working interest in the Pouce Coupe South Boundary B Unit operated by EnerplusResources Corporation.  Non-unitproduction consists of wells with interests ranging from a gross overridingroyalty to a 78.75% working interest. Producing formations primarily include the Doig, Bluesky, Gething,Baldonnel, Halfway and Boundary Lake.

*RedRock, Alberta*

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

*Fort St. John, British Columbia*

The Fort St. Johnproperties are primarily located in the Fort St. John area in northeast BritishColumbia.  The principal properties arewithin a 20 kilometer radius of Fort St. John. Canetic has an average working interest of 55%.  Canetic also has 50% and 65% workinginterests, respectively, in two operated compressor stations and 38.44% and 27%working interests, respectively, in a further two non-operated compressorstations.  In September of 2006, Caneticobtained additional production in this area through the SamsonAcquisition.  Working interests average57% in this new acreage and Canetic operates 79% of its production.  Major fields include Stoddart, Monias,Airport, and Wilder.  Producing horizonsinclude Halfway, Doig, and Belloy. Canetic obtained operatorship in 10 compressors through this transactionand has additional ownership in 7 more. All gas is processed through Duke Midstream.

*Fireweed/Buick Creek, BritishColumbia*

The Fireweed/Buick Creekproperties are located approximately 75 kilometers north and northwest of FortSt. John in northeast British Columbia. Canetic obtained a large land position through the Samson Acquisition inSeptember of 2006.  Canetic has anaverage working interest of 57% in the new properties and operates 91% of itsproduction.  The majority of productioncomes from the Dunlevy Sand with minor production from the Doig, Halfway,Bluesky, and Baldonnel horizons.  Caneticoperates 9 compressors in the area and has additional ownership in 5others.  All gas is processed throughDuke Midstream.

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**STATEMENT OF RESERVES DATA ANDOTHER OIL AND GAS INFORMATION**

The effective date of thestatement of reserves data and other oil and gas information set forth below(the “**Statement**”) isDecember 31, 2006 and the preparation date of the Statement is February 28,2007.

Inthis section “Canetic” means Canetic or one or more of the other OperatingEntities.

**Disclosure of Reserves Data**

The reserves data ofCanetic set forth below (the “**Reserves****Data**”) is based upon evaluations by GLJ and Sproule with effective datesof December 31, 2006 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 futurenet revenue for these reserves using constant prices and costs and forecastprices and costs.  The Reserves Dataconforms to the requirements of National Instrument 51-101 Standards ofDisclosure for Oil and Gas Activities (“**NI 51-101**”).  Additional information not required by NI 51-101has been presented to provide continuity and additional information thatCanetic believes is important to the readers of this information.

The majority of Canetic’sreserves 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 assumedthat the estimates of future net revenues presented in the tables belowrepresent the fair market value of the reserves.  There is no assurance that the constant orforecast prices and costs or other assumptions will be attained and variancescould be material.

***Reserves Data(Forecast Prices and Costs)***

Thereserves information presented does not report the U.S. reserves separately.  The U.S. properties have proved plus probablegross reserves of approximately 6,811 MBoe or 2.5% of total reserves with abefore tax net present value discounted at 10% of approximately $43,419,000 or1.0% of total value.

The followingtables provide Reserves Data and future net revenues of Canetic using forecastprices and costs.

**Summary of Oil and Gas Reserves andNet Present Values of Future Net Revenue as of December 31, 2006Forecast Prices and Costs**
| ** **                  | ** ** | **Reserves**                        | ** ** |
|-----------------------------|------------|-------------------------------------|------------|
| ** **                  | ** ** | **Light and  Medium Oil** | ** ** | **Heavy Oil** | ** ** | **Natural Gas** | ** ** | **Natural  Gas Liquids** | ** ** | **Boe** | ** ** |
| ** **                  | ** ** | **Gross**                           | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| **Reserves Category**  | ** ** | **(Mbbls)**                         | ** ** | **(Mbbls)** | ** ** | **(Mbbls)** | ** ** | **(Mbbls)** | ** ** | **(MMcf)** | ** ** | **(MMcf)** | ** ** | **(Mbbls)** | ** ** | **(Mbbls)** | ** ** | **(MBoe)** | ** ** | **(MBoe)** | ** ** |
|                        |       |                                |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Proved                      |       |                                |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Developed Producing         |       | 68,038                              |       | 61,180 |   | 15,331 |   | 14,171 |   | 369,117 |   | 296,374 |   | 11,101 |   | 8,027 |   | 155,990 |   | 132,773 |   |
| Developed Non-Producing     |       | 2,932                               |       | 2,573 |   | 1,542 |   | 1,363 |   | 29,289 |   | 23,619 |   | 936 |   | 676 |   | 10,292 |   | 8,548 |   |
| Undeveloped                 |       | 11,657                              |       | 10,605 |   | 1,527 |   | 1,389 |   | 63,610 |   | 51,205 |   | 917 |   | 643 |   | 24,703 |   | 21,171 |   |
| Total Proved                |       | 82,627                              |       | 74,357 |   | 18,400 |   | 16,923 |   | 462,016 |   | 371,197 |   | 12,955 |   | 9,346 |   | 190,985 |   | 162,492 |   |
| Probable                    |       | 34,244                              |       | 30,728 |   | 5,765 |   | 5,268 |   | 226,787 |   | 185,922 |   | 5,219 |   | 3,830 |   | 83,026 |   | 70,812 |   |
|                        |       |                                |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Total Proved Plus  Probable |       | 116,872                             |       | 105,085 |   | 24,165 |   | 22,190 |   | 688,803 |   | 557,120 |   | 18,174 |   | 13,176 |   | 274,011 |   | 233,304 |   |

 

Royalty interestreserves for Proved Developed Producing, Total Proved, and Total Proved PlusProbable are 1,078 MBoe, 1,194 MBoe, and 1,631 MBoe respectively, which equateto Company Interest Reserves of 157,068 MBoe, 192,179 MBoe, and 275,642 MBoerespectively.

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| ** **                  | ** ** | **Net Present Values of Future Net Revenue** | ** ** |
|-----------------------------|------------|----------------------------------------------------------------------------|------------|
| ** **                  | ** ** | **Before Income Taxes  Discounted at (%/year)**        | ** ** | **After Income Taxes  Discounted at (%/year)** | ** ** |
| **Reserves Category**  | ** ** | **0  (M$)**                                                                | ** ** | **5  (M$)** | ** ** | **10  (M$)** | ** ** | **15  (M$)** | ** ** | **20  (M$)** | ** ** | **0  (M$)** | ** ** | **5  (M$)** | ** ** | **10  (M$)** | ** ** | **15  (M$)** | ** ** | **20  (M$)** | ** ** |
|                        |       |                                                                       |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Proved                      |       |                                                                       |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Developed Producing         |       | 4,662,073                                                                  |       | 3,515,069 |   | 2,892,706 |   | 2,493,224 |   | 2,210,722 |   | 4,662,073 |   | 3,515,069 |   | 2,892,706 |   | 2,493,224 |   | 2,210,722 |   |
| Developed Non-Producing     |       | 285,053                                                                    |       | 212,000 |   | 170,885 |   | 143,402 |   | 123,449 |   | 285,053 |   | 212,000 |   | 170,885 |   | 143,402 |   | 123,449 |   |
| Undeveloped                 |       | 475,959                                                                    |       | 329,570 |   | 237,133 |   | 174,204 |   | 129,143 |   | 475,959 |   | 329,570 |   | 237,133 |   | 174,204 |   | 129,143 |   |
| Total Proved                |       | 5,423,084                                                                  |       | 4,056,639 |   | 3,300,724 |   | 2,810,830 |   | 2,463,314 |   | 5,423,084 |   | 4,056,639 |   | 3,300,724 |   | 2,810,830 |   | 2,463,314 |   |
| Probable                    |       | 2,494,025                                                                  |       | 1,411,019 |   | 949,810 |   | 701,204 |   | 546,933 |   | 2,494,025 |   | 1,411,019 |   | 949,810 |   | 701,204 |   | 546,933 |   |
|                        |       |                                                                       |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Total Proved Plus  Probable |       | 7,917,110                                                                  |       | 5,467,658 |   | 4,250,534 |   | 3,512,034 |   | 3,010,247 |   | 7,917,110 |   | 5,467,658 |   | 4,250,534 |   | 3,512,034 |   | 3,010,247 |   |

 

**Total Future Net Revenue (Undiscounted) as ofDecember 31, 2006**

**ForecastPrices and Costs**
| **Reserves Category**     | ** ** | **Revenue  (M$)** | ** ** | **Royalties  (M$)** | ** ** | **Operating  Costs  (M$)** | ** ** | **Development  Costs  (M$)** | ** ** | **Well  Abandonment  Costs  (M$)** | ** ** | **Future Net  Revenue  Before Income  Taxes  (M$)** | ** ** | **Income  Taxes  (M$)** | ** ** | **Future Net  Revenue  After  Income  Taxes  (M$)** | ** ** |
|--------------------------------|------------|-------------------|------------|---------------------|------------|----------------------------|------------|------------------------------|------------|------------------------------------|------------|---------------------------------------------------------------|------------|-------------------------|------------|----------------------------------------------------------|------------|
|                           |       |              |       |                |       |                       |       |                         |       |                               |       |                                                          |       |                    |       |                                                     |       |
| Proved Reserves                |       | 10,946,040        |       | 1,734,382           |       | 3,172,124                  |       | 411,314                      |       | 205,135                            |       | 5,423,085                                                     |       | 0                       |       | 5,423,085                                                |       |
|                           |       |              |       |                |       |                       |       |                         |       |                               |       |                                                          |       |                    |       |                                                     |       |
| Proved Plus Probable  Reserves |       | 16,081,467        |       | 2,548,000           |       | 4,753,706                  |       | 620,716                      |       | 241,937                            |       | 7,917,108                                                     |       | 0                       |       | 7,917,108                                                |       |

**FutureNet Revenue by Production Group as of December 31, 2006**

**ForecastPrices 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)             |       | 1,876,792                                                                                                                 |       |
|                           |       | Heavy Oil (including  solution gas and other by-products)                              |       | 258,056                                                                                                                   |       |
|                           |       | Natural Gas  (including CBM and by-products but excluding solution gas from oil wells) |       | 1,163,698                                                                                                                 |       |
|                           |       | Other Company  Revenue/Costs                                                           |       | 2,178                                                                                                                     |       |
|                           | ** ** | **Total**                                                                              |       | 3,300,724                                                                                                                 |       |
|                           | ** ** | ** **                                                                             | ** ** | ** **                                                                                                                | ** ** |
| Proved  Plus Probable Reserves |       | Light and Medium  Crude Oil (including solution gas and other by-products)             |       | 2,373,058                                                                                                                 |       |
|                           |       | Heavy Oil  (including solution gas and other by-products)                              |       | 315,299                                                                                                                   |       |
|                           |       | Natural Gas  (including CBM and by-products but excluding solution gas from oil wells) |       | 1,559,999                                                                                                                 |       |
|                           |       | Other Company  Revenue/Costs                                                           |       | 2,178                                                                                                                     |       |
|                           | ** ** | **Total**                                                                              |       | 4,250,534                                                                                                                 |       |

 

19

----

***Reserves Data (ConstantPrices and Costs)***

The followingtables provide Reserves data and future net revenue of Canetic using constantprices and costs.

**Summaryof Oil and Gas Reserves and Net Present Values of Future Net Revenue as ofDecember 31, 2006**

**ConstantPrices and Costs**
| ** **                 | ** ** | **Reserves**                        | ** ** |
|----------------------------|------------|-------------------------------------|------------|
| ** **                 | ** ** | **Light and Medium  Oil** | ** ** | **Heavy Oil** | ** ** | **Natural Gas** | ** ** | **Natural Gas  Liquids** | ** ** | **Boe** | ** ** |
| ** **                 | ** ** | **Gross**                           | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| **Reserves Category** | ** ** | **(Mbbls)**                         | ** ** | **(Mbbls)** | ** ** | **(Mbbls)** | ** ** | **(Mbbls)** | ** ** | **(MMcf)** | ** ** | **(MMcf)** | ** ** | **(Mbbls)** | ** ** | **(Mbbls)** | ** ** | **(MBoe)** | ** ** | **(MBoe)** | ** ** |
|                       |       |                                |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Proved                     |       |                                |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Developed  Producing       |       | 69,497                              |       | 62,552 |   | 15,503 |   | 14,333 |   | 364,835 |   | 293,202 |   | 11,149 |   | 8,055 |   | 156,955 |   | 133,807 |   |
| Developed  Non-Producing   |       | 2,836                               |       | 2,481 |   | 1,575 |   | 1,397 |   | 28,791 |   | 23,213 |   | 921 |   | 663 |   | 10,131 |   | 8,410 |   |
| Undeveloped                |       | 11,822                              |       | 10,754 |   | 1,550 |   | 1,412 |   | 63,301 |   | 51,200 |   | 925 |   | 648 |   | 24,847 |   | 21,347 |   |
| Total Proved               |       | 84,154                              |       | 75,787 |   | 18,628 |   | 17,143 |   | 456,927 |   | 367,614 |   | 12,996 |   | 9,365 |   | 191,933 |   | 163,564 |   |
| Probable                   |       | 34,881                              |       | 31,324 |   | 5,891 |   | 5,391 |   | 222,885 |   | 182,974 |   | 5,211 |   | 3,819 |   | 83,130 |   | 71,030 |   |
|                       |       |                                |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Total Proved Plus Probable |       | 119,036                             |       | 107,111 |   | 24,519 |   | 22,534 |   | 679,812 |   | 550,588 |   | 18,206 |   | 13,184 |   | 275,063 |   | 234,594 |   |

 

Royalty interestreserves for Proved Developed Producing, Total Proved, and Total Proved PlusProbable are 1,078 MBoe, 1,192 MBoe, and 1,634 MBoe respectively, which equateto Company Interest Reserves of 158,033 MBoe, 193,126 MBoe, and 276,697 MBoerespectively.
| ** **                 | ** ** | **Net Present Values of Future Net Revenue** | ** ** |
|----------------------------|------------|----------------------------------------------------------------------------|------------|
| ** **                 | ** ** | **Before Income Taxes Discounted at (%/year)**    | ** ** | **After Income Taxes Discounted at (%/year)** | ** ** |
| **Reserves Category** | ** ** | **0  (M$)**                                                                | ** ** | **5  (M$)** | ** ** | **10  (M$)** | ** ** | **15  (M$)** | ** ** | **20  (M$)** | ** ** | **0  (M$)** | ** ** | **5  (M$)** | ** ** | **10  (M$)** | ** ** | **15  (M$)** | ** ** | **20  (M$)** | ** ** |
|                       |       |                                                                       |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Proved                     |       |                                                                       |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Developed Producing        |       | 4,244,546                                                                  |       | 3,226,467 |   | 2,653,161 |   | 2,279,373 |   | 2,013,531 |   | 4,244,546 |   | 3,226,467 |   | 2,653,161 |   | 2,279,373 |   | 2,013,531 |   |
| Developed Non-Producing    |       | 250,679                                                                    |       | 190,227 |   | 153,731 |   | 128,771 |   | 110,518 |   | 250,679 |   | 190,227 |   | 153,731 |   | 128,771 |   | 110,518 |   |
| Undeveloped                |       | 425,003                                                                    |       | 288,516 |   | 202,373 |   | 143,887 |   | 102,162 |   | 425,003 |   | 288,516 |   | 202,373 |   | 143,887 |   | 102,162 |   |
| Total Proved               |       | 4,920,229                                                                  |       | 3,705,209 |   | 3,009,265 |   | 2,552,031 |   | 2,226,211 |   | 4,920,229 |   | 3,705,209 |   | 3,009,265 |   | 2,552,031 |   | 2,226,211 |   |
| Probable                   |       | 2,051,904                                                                  |       | 1,210,674 |   | 828,942 |   | 615,367 |   | 480,060 |   | 2,051,904 |   | 1,210,674 |   | 828,942 |   | 615,367 |   | 480,060 |   |
|                       |       |                                                                       |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Total Proved Plus Probable |       | 6,972,133                                                                  |       | 4,915,884 |   | 3,838,207 |   | 3,167,398 |   | 2,706,271 |   | 6,972,133 |   | 4,915,884 |   | 3,838,207 |   | 3,167,398 |   | 2,706,271 |   |

 

**Total Future Net Revenue (Undiscounted) as ofDecember 31, 2006**

**ConstantPrices and Costs**
| **ReservesnCategory**          | ** ** | **Revenue  (M$)** | ** ** | **Royalties  (M$)** | ** ** | **Operating  Costs  (M$)** | ** ** | **Development  Costs  (M$)** | ** ** | **Well  Abandonment  Costs  (M$)** | ** ** | **Future Net  Revenue  Before  Income  Taxes  (M$)** | ** ** | **Income  Taxes  (M$)** | ** ** | **Future Net  Revenue  After  Income  Taxes  (M$)** | ** ** |
|--------------------------------|------------|-------------------|------------|---------------------|------------|----------------------------|------------|------------------------------|------------|------------------------------------|------------|-----------------------------------------------------------|------------|-------------------------|------------|----------------------------------------------------------|------------|
|                           |       |              |       |                |       |                       |       |                         |       |                               |       |                                                      |       |                    |       |                                                     |       |
| Proved Reserves                |       | 9,581,387         |       | 1,476,979           |       | 2,637,703                  |       | 398,264                      |       | 148,214                            |       | 4,920,227                                                 |       | 0                       |       | 4,920,227                                                |       |
|                           |       |              |       |                |       |                       |       |                         |       |                               |       |                                                      |       |                    |       |                                                     |       |
| Proved Plus Probable  Reserves |       | 13,559,853        |       | 2,106,517           |       | 3,724,891                  |       | 598,657                      |       | 157,655                            |       | 6,972,133                                                 |       | 0                       |       | 6,972,133                                                |       |

 

20

----

**FutureNet Revenue by Production Group as of December 31, 2006**

**ConstantPrices 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)             |       | 1,880,108                                                                                        |       |
|                           |       | Heavy Oil  (including solution gas and other by-products)                              |       | 254,111                                                                                          |       |
|                           |       | Natural Gas  (including CBM and by-products but excluding solution gas from oil wells) |       | 872,838                                                                                          |       |
|                           |       | Other Company  Revenue/Costs                                                           |       | 2,210                                                                                            |       |
|                           | ** ** | **Total**                                                                              |       | 3,009,267                                                                                        |       |
|                           |       |                                                                                   |       |                                                                                             |       |
| Proved  Plus Probable Reserves |       | Light and Medium  Crude Oil (including solution gas and other by-products)             |       | 2,374,040                                                                                        |       |
|                           |       | Heavy Oil  (including solution gas and other by-products)                              |       | 310,856                                                                                          |       |
|                           |       | Natural Gas  (including CBM and by-products but excluding solution gas from oil wells) |       | 1,151,101                                                                                        |       |
|                           |       | Other Company  Revenue/Costs                                                           |       | 2,210                                                                                            |       |
|                           | ** ** | **Total**                                                                              |       | 3,838,207                                                                                        |       |

**Pricing Assumptions**

The following tables setforth the pricing assumptions used in preparing the Reserves data, which was anaverage of the GLJ and Sproule December 31, 2006 reference****prices and, in the case of forecast pricesand costs, the inflation rate assumptions.

**Summaryof Pricing Assumptions as of December 31, 2006Constant Prices and Costs**

|                                          | ** ** | **December 31, 2006** |
|------------------------------------------|------------|-----------------------|
| Inflation Rate  Percent                  |       | 00.00                 |
|                                     |       |                  |
| **Crude  Oil $Cdn/Bbl**                  |       |                  |
| Light Sweet  Crude @ Edmonton            |       | 67.59                 |
| Heavy @ Hardisty                         |       | 39.35                 |
| Medium @ Cromer                          |       | 60.96                 |
|                                     |       |                  |
| WTI @ Cushing,  Oklahoma ($US/Bbl)       |       | 60.95                 |
|                                     |       |                  |
| **NGLs  $Cdn/Bbl at Edmonton**           |       |                  |
| Propane                                  |       | 42.66                 |
| Butane                                   |       | 54.03                 |
| Condensate                               |       | 71.53                 |
|                                     |       |                  |
| **Natural  Gas $Cdn/MMBTU**              |       |                  |
| AECO Spot                                |       | 6.10                  |
| Alberta Spot  Plant-gate                 |       | 5.59                  |
| Alberta  Government Reference Plant-gate |       | 5.57                  |
| Alberta  Aggregator Plant-gate           |       | 5.33                  |
| Saskatchewan  Spot Plant-gate            |       | 5.97                  |
| B.C. Spot  Plant-gate                    |       | 6.05                  |
| B.C. Westcoast  Stn2.                    |       | 6.24                  |
|                                     |       |                  |
| **Exchange  Rate $US/$Cdn**              |       | 0.858                 |

** **

21

----

**Summaryof Pricing and Inflation Rate Assumptions as of December 31, 2006**

**ForecastPrices 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   |       |                       |       |                                            |       |                                   |       |                                  |       |                                       |       |                  |       |                 |       |   |   |   |   |   |   |
| 2007       |       | 63.87                      |       | 72.17                                           |       | 41.11                                  |       | 62.49                                 |       | 7.46                                       |       | 44.47                 |       | 55.74                |       | 73.82 |   | 3.5 |   | .87 |   |
| 2008       |       | 64.41                      |       | 72.81                                           |       | 42.51                                  |       | 63.00                                 |       | 8.02                                       |       | 44.77                 |       | 54.05                |       | 74.37 |   | 3.0 |   | .87 |   |
| 2009       |       | 60.21                      |       | 68.00                                           |       | 40.25                                  |       | 58.83                                 |       | 7.74                                       |       | 41.83                 |       | 50.55                |       | 69.47 |   | 2.5 |   | .87 |   |
| 2010       |       | 57.68                      |       | 65.03                                           |       | 38.89                                  |       | 56.19                                 |       | 7.67                                       |       | 40.07                 |       | 48.31                |       | 66.45 |   | 2.0 |   | .87 |   |
| 2011       |       | 56.10                      |       | 63.20                                           |       | 38.08                                  |       | 54.62                                 |       | 7.79                                       |       | 38.98                 |       | 46.94                |       | 64.57 |   | 2.0 |   | .87 |   |
| 2012       |       | 56.90                      |       | 64.07                                           |       | 39.06                                  |       | 55.40                                 |       | 8.00                                       |       | 39.48                 |       | 47.53                |       | 65.46 |   | 2.0 |   | .87 |   |
| 2013       |       | 57.97                      |       | 65.34                                           |       | 39.93                                  |       | 56.58                                 |       | 8.14                                       |       | 40.35                 |       | 48.51                |       | 66.74 |   | 2.0 |   | .87 |   |
| 2014       |       | 59.17                      |       | 66.73                                           |       | 40.81                                  |       | 57.76                                 |       | 8.31                                       |       | 41.11                 |       | 49.62                |       | 68.15 |   | 2.0 |   | .87 |   |
| 2015       |       | 60.38                      |       | 68.02                                           |       | 41.57                                  |       | 58.83                                 |       | 8.48                                       |       | 42.00                 |       | 50.48                |       | 69.58 |   | 2.0 |   | .87 |   |
| 2016       |       | 61.60                      |       | 69.44                                           |       | 42.46                                  |       | 60.03                                 |       | 8.65                                       |       | 42.78                 |       | 51.61                |       | 71.02 |   | 2.0 |   | .87 |   |
| 2017       |       | 62.83                      |       | 70.76                                           |       | 43.23                                  |       | 61.25                                 |       | 8.82                                       |       | 43.69                 |       | 52.50                |       | 72.35 |   | 2.0 |   | .87 |   |
| 2018+      |       | 2%/yr                      |       | 2%/yr                                           |       | 2%/yr                                  |       | 2%/yr                                 |       | 2%/yr                                      |       | 2%/yr                 |       | 2%/yr                |       | 2%/yr |   | 2.0 |   | .87 |   |

Weighted average historical prices realized by Caneticfor the year ended December 31, 2006, were $7.01/Mcf for natural gas,$63.39/Bbl for light/medium crude oil, $47.84/Bbl for natural gas liquids and$43.57/Bbl for heavy oil.

**Reconciliations of Changes in Reserves and Future NetRevenue**

The following table setsforth the reconciliation of Canetic’s net reserves for the year ended December31, 2006 using anaverage of the GLJ and Sproule forecast price and cost estimates, reconciledto Canetic’s net reserves at December 31, 2005.

**Reconciliationof Company Net Reserves by Principal product Type**

**ForecastPrices and Costs**
| ** **           | ** ** | **Light and Medium Oil** | ** ** | **Heavy Oil**       | ** ** |
|----------------------|------------|-----------------------------------------|------------|--------------------------|------------|
| **Factors**          | ** ** | **Net  Proved (MBbl)**                  | ** ** | **Net  Probable (MBbl)** | ** ** | **Net  Proved  Plus  Probable (MBbl)** | ** ** | **Net Proved (MBbl)** | ** ** | **Net  Probable (MBbl)** | ** ** | **Net Proved  Plus Probable (MBbl)** | ** ** |
|                 |       |                                    |       |                     |       |   |   |   |   |   |   |   |   |
| December 31,  2005   |       | 73,486                                  |       | 29,754                   |       | 103,240 |   | 18,059 |   | 5,931 |   | 23,990 |   |
|                 |       |                                    |       |                     |       |   |   |   |   |   |   |   |   |
| Acquisitions         |       | 891                                     |       | 475                      |       | 1,365 |   | — |   | — |   | — |   |
| Dispositions         |       | —                                  |       | —                   |       | — |   | — |   | — |   | — |   |
| Discoveries          |       | 311                                     |       | 63                       |       | 374 |   | — |   | — |   | — |   |
| Extensions           |       | 1,347                                   |       | 299                      |       | 1,646 |   | 308 |   | 332 |   | 640 |   |
| Infill Drilling      |       | 2,362                                   |       | 782                      |       | 3,144 |   | 704 |   | (232 | ) | 472 |   |
| Improved  Recovery   |       | —                                  |       | 1,676                    |       | 1,676 |   | 2,318 |   | (1,450 | ) | 869 |   |
| Economic Factors     |       | 110                                     |       | 45                       |       | 155 |   | 27 |   | 9 |   | 36 |   |
| Technical  Revisions |       | 5,863                                   |       | (2,366                   | )          | 3,496 |   | (2,189 | ) | 679 |   | (1,512 | ) |
| Production           |       | (10,012                                 | )          | —                   |       | (10,012 | ) | (2,305 | ) | — |   | (2,305 | ) |
|                 |       |                                    |       |                     |       |   |   |   |   |   |   |   |   |
| December 31, 2006    |       | 74,357                                  |       | 30,728                   |       | 105,085 |   | 16,923 |   | 5,268 |   | 22,190 |   |

 

22

----

 
| ** **           | ** ** | **Gas**                | ** ** | **NGL**                  | ** ** | **Total**                              | ** ** |
|----------------------|------------|------------------------|------------|--------------------------|------------|----------------------------------------|------------|
| **Factors**          | ** ** | **Net  Proved (MMcf)** | ** ** | **Net  Probable (MMcf)** | ** ** | **Net  Proved  Plus  Probable (MMcf)** | ** ** | **Net  Proved (MBbl)** | ** ** | **Net  Probable (MBbl)** | ** ** | **Net  Proved  Plus  Probable (MBbl)** | ** ** | **Net  Proved (MBoe)** | ** ** | **Net  Probable (MBoe)** | ** ** | **Net Proved  Plus  Probable (MBoe)** | ** ** |
|                 |       |                   |       |                     |       |                                   |       |   |   |   |   |   |   |   |   |   |   |   |   |
| December 31,  2005   |       | 279,004                |       | 108,717                  |       | 387,721                                |       | 7,418 |   | 2,684 |   | 10,102 |   | 145,464 |   | 56,489 |   | 201,952 |   |
|                 |       |                   |       |                     |       |                                   |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Acquisitions         |       | 107,287                |       | 68,735                   |       | 176,022                                |       | 1,897 |   | 1,144 |   | 3,041 |   | 20,669 |   | 13,075 |   | 33,743 |   |
| Dispositions         |       | (851                   | )          | (160                     | )          | (1,011                                 | )          | (93 | ) | (17 | ) | (110 | ) | (235 | ) | (44 | ) | (279 | ) |
| Discoveries          |       | 871                    |       | 149                      |       | 1,020                                  |       | 53 |   | 8 |   | 61 |   | 510 |   | 95 |   | 605 |   |
| Extensions           |       | 17,799                 |       | 9,105                    |       | 26,904                                 |       | 799 |   | 222 |   | 1,021 |   | 5,420 |   | 2,371 |   | 7,791 |   |
| Infill Drilling      |       | 5,350                  |       | 1,378                    |       | 6,728                                  |       | 50 |   | 44 |   | 94 |   | 4,008 |   | 824 |   | 4,832 |   |
| Improved  Recovery   |       | 5,466                  |       | 918                      |       | 6,384                                  |       | 185 |   | 37 |   | 221 |   | 3,414 |   | 416 |   | 3,830 |   |
| Economic Factors     |       | 419                    |       | 163                      |       | 582                                    |       | 11 |   | 4 |   | 15 |   | 218 |   | 85 |   | 303 |   |
| Technical  Revisions |       | 9,886                  |       | (3,083                   | )          | 6,805                                  |       | 561 |   | (295 | ) | 266 |   | 5,883 |   | (2,498 | ) | 3,385 |   |
| Production           |       | (54,034                | )          | —                   |       | (54,034                                | )          | (1,536 | ) | — |   | (1,536 | ) | (22,859 | ) | — |   | (22,859 | ) |
|                 |       |                   |       |                     |       |                                   |       |   |   |   |   |   |   |   |   |   |   |   |   |
| December 31, 2005    |       | 371,197                |       | 185,922                  |       | 557,120                                |       | 9,346 |   | 3,830 |   | 13,176 |   | 162,492 |   | 70,812 |   | 233,304 |   |

The following table setsforth the reconciliation of Canetic’s net present value of future netrevenue for the year ended December 31, 2006 using an average of the GLJ and Sproule constantprice and cost estimates.

**Reconciliation of Changes in NetPresent Values of Future Net Revenue**

**Discounted at 10% Per Year**

**Proved Reserves**

**ConstantPrices and Costs**
| **Period and Factor**                                                     | ** ** | **(M$)**  | ** ** |
|-------------------------------------------------------------------------------------|------------|-----------|------------|
|                                                                                |       |      |       |
| Estimated Future  Net Revenue at Beginning of Year (December 31, 2005)              |       | 3,391,031 |       |
|                                                                                |       |      |       |
| Sales and Transfers of Oil and Gas Produced, Net of  Production Costs and Royalties |       | (923,545  | )          |
| Net Change in Prices, Production Costs and Royalties  Related to Future Production  |       | (442,994  | )          |
| Changes in Previously Estimated Development Costs  Incurred During the Period       |       | —    |       |
| Changes in Estimated Future Development Costs                                       |       | (20,535   | )          |
| Extensions, Infill Drilling and Improved Recovery                                   |       | 236,271   |       |
| Discoveries                                                                         |       | 9,380     |       |
| Acquisitions of Reserves                                                            |       | 325,475   |       |
| Dispositions of Reserves                                                            |       | (17,167   | )          |
| Net Change Resulting from Revisions in Quantity  Estimates                          |       | 112,246   |       |
| Accretion of Discount                                                               |       | 339,103   |       |
| Net Change in Income Taxes                                                          |       | —    |       |
|                                                                                |       |      |       |
| Estimated Future Net  Revenue at End of Year                                        |       | 3,009,265 |       |

** **

 

23

----

**AdditionalInformation Relating to Reserves Data**

***Undeveloped Reserves***

The followingtables set forth the gross Proved Undeveloped Reserves and the ProbableUndeveloped Reserves, each by-product type, attributed to the Canetic Assetsfor the periods indicated, based on forecast prices.
| ** ** | ** ** | **Gross Proved Undeveloped**            | ** ** | **Gross Probable Undeveloped** | ** ** |
|------------|------------|---------------------------------------------------|------------|------------------------------------------|------------|
| **Year**   | ** ** | **Light /  Medium  Crude Oil  (Mbbls)** | ** ** | **Heavy Oil  (Mbbls)**              | ** ** | **Natural Gas  (MMcf)** | ** ** | **NGL  (MBbls)** | ** ** | **Light /  Medium  Crude Oil  (Mbbls)** | ** ** | **Heavy Oil  (Mbbls)** | ** ** | **Natural  Gas  (MMcf)** | ** ** | **NGL  (Mbbls)** | ** ** |
|       |       |                                              |       |                                     |       |   |   |   |   |   |   |   |   |   |   |   |   |
| 2006       |       | 11,675                                            |       | 1,527                                    |       | 63,610 |   | 917 |   | 11,362 |   | 1,434 |   | 82,191 |   | 1,376 |   |

 

Canetic invests capitalinto development work, which moves it’s Proved Undeveloped Reserves andProbable Reserves into the Proved Developed Producing category ofReserves.  In 2006, $351 million wasspent on capital development and approximately $350 million has beenbudgeted for development capital in 2007 with respect to the Canetic Assets.  A portion of the development capital isintended to be used to convert Proved Undeveloped Reserves and ProbableReserves into Proved Developed Producing Reserves.  Allocating capital to properties and timingof development is based on economics and performance of the respective properties.  Canetic’s focus for 2007 development will bein the areas of Pouce Coupe in the Northern district and Willesden Green in theWestern district, as well the Southern District, the Williston Basin andCentral Alberta.

Canetic plans to continuepursuing development opportunities such as drilling, completions, andfacilities upgrades in order to move Proved Undeveloped and Probable Reservesinto Proved Developed Producing Reserves. In instances where land rights are expected to expire within one year,Canetic may engage in farm out arrangements which would eliminate the potentialexpiry and possibly result in some Proved Undeveloped and Probable Reservesbecoming Proved Developed Producing Reserves.

***Future Development Costs***

The followingtable sets forth development costs deducted in the estimation of Canetic’sfuture 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%** | ** ** |
|       |       |                                                   |       |                                               |       |   |   |   |   |   |   |   |   |
| 2007       |       | 184,885                                                |       | 176,281                                            |       | 258,174 |   | 246,159 |   | 184,885 |   | 176,281 |   |
| 2008       |       | 132,251                                                |       | 114,633                                            |       | 200,005 |   | 173,361 |   | 129,011 |   | 111,825 |   |
| 2009       |       | 42,540                                                 |       | 33,521                                             |       | 75,281 |   | 59,320 |   | 40,350 |   | 31,795 |   |
| 2010       |       | 16,077                                                 |       | 11,517                                             |       | 33,736 |   | 24,167 |   | 14,866 |   | 10,649 |   |
| 2011       |       | 5,062                                                  |       | 3,297                                              |       | 8,966 |   | 5,839 |   | 4,594 |   | 2,992 |   |
| Thereafter |       | 30,499                                                 |       | 13,899                                             |       | 44,561 |   | 19,205 |   | 24,555 |   | 12,020 |   |
| Total      |       | 411,314                                                |       | 353,147                                            |       | 620,723 |   | 528,051 |   | 398,261 |   | 345,562 |   |

 

The future developmentcosts are capital expenditures required in the future for Canetic to convertDeveloped Non Producing Reserves and Undeveloped Reserves into Proved DevelopedProducing Reserves.  Canetic anticipatesusing a combination of internally generated funds flow, debt and equityfinancing to fund these future development costs.  Based on the commodity price and costassumptions adopted for both the constant prices and costs case and theforecast prices and costs case, all the expenditures included in the futuredevelopment costs are economic as they enhance the net present values of theProved Developed Producing Reserves.

24

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**OtherOil and Gas Information**

***Oil and Gas Wells***

The following table setsforth the number and status of wells in which Canetic had a working interest asat December 31, 2006.
| ** **       | ** ** | **Oil Wells** | ** ** | **Natural Gas Wells** | ** ** |
|------------------|------------|--------------------|------------|---------------------------------|------------|
| ** **       | ** ** | **Producing**      | ** ** | **Non-Producing(1)**            | ** ** | **Producing** | ** ** | **Non-Producing(1)** | ** ** |
| ** **       | ** ** | **Gross(2)**       | ** ** | **Net**                         | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross(2)** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
|             |       |               |       |                            |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Alberta          |       | 3,102              |       | 1,035                           |       | 112 |   | 51 |   | 3,806 |   | 1,266 |   | 112 |   | 69 |   |
| British Columbia |       | 55                 |       | 15                              |       | 1 |   | 1 |   | 297 |   | 133 |   | 20 |   | 11 |   |
| Saskatchewan     |       | 2,691              |       | 1,236                           |       | 114 |   | 79 |   | 307 |   | 45 |   | 3 |   | 2 |   |
| Manitoba         |       | 467                |       | 146                             |       | 0 |   | 0 |   | 0 |   | 0 |   | 0 |   | 0 |   |
| United States    |       | 21                 |       | 9                               |       | 0 |   | 0 |   | 156 |   | 48 |   | 29 |   | 21 |   |
| Total            |       | 6,336              |       | 2,441                           |       | 227 |   | 131 |   | 4,566 |   | 1,492 |   | 164 |   | 103 |   |

----

**Notes:**

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

(2)                                  Grosswells include unit wells.

***Properties with noAttributed Reserves***

The following table setsout the total land holding of Proved and Unproved properties held by Canetic asat December 31, 2006.
| ** **       | ** ** | **Developed (Acres)** | ** ** | **Undeveloped Land (Acres)** | ** ** | **Total (Acres)** | ** ** |
|------------------|------------|----------------------------|------------|----------------------------------------|------------|------------------------|------------|
| ** **       | ** ** | **Gross**                  | ** ** | **Net**                                | ** ** | **Gross**              | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
|             |       |                       |       |                                   |       |                   |       |   |   |   |   |   |   |
| Alberta          |       | 1,666,860                  |       | 762,821                                |       | 1,050,353              |       | 584,843 |   | 2,717,213 |   | 1,347,665 |   |
| British Columbia |       | 233,024                    |       | 101,675                                |       | 262,088                |       | 148,144 |   | 495,112 |   | 249,819 |   |
| Saskatchewan     |       | 263,398                    |       | 149,210                                |       | 273,895                |       | 145,798 |   | 537,293 |   | 295,008 |   |
| Manitoba         |       | 36,510                     |       | 13,143                                 |       | 7,943                  |       | 2,627 |   | 44,453 |   | 15,770 |   |
| Wyoming          |       | 9,652                      |       | 3,821                                  |       | 26,785                 |       | 14,962 |   | 36,436 |   | 18,783 |   |
| Montana          |       | 1,520                      |       | 937                                    |       | 2,275                  |       | 811 |   | 3,796 |   | 1,748 |   |
| North Dakota     |       | 7,506                      |       | 3,731                                  |       | 31,148                 |       | 24,851 |   | 38,654 |   | 28,582 |   |
| Total            |       | 2,218,470                  |       | 1,035,338                              |       | 1,654,487              |       | 922,036 |   | 3,872,957 |   | 1,957,375 |   |

 

Management expects thatrights to explore, develop and exploit 204,146 net acres of Canetic’sundeveloped land holdings will expire within one year.

***Forward Contracts***

Canetichas an active price risk management program that undertakes to reduce riskexposure to budgeted annual funds flow projections resulting from uncertaintyor changes in commodity prices.  Thereduction of price risk is designed to result in an enhanced degree ofstability and certainty of distribution payments to Unitholders.  Core to Canetic’s risk management strategy isthe choice of the appropriate type of financial product at the time ofexecution which will give the optimal level of protection against downwardprice movements while maintaining as much exposure as possible to potentialprice increases.  The objective of Canetic’srisk management team is to hedge up to 50% of Canetic’s budgeted production forthe current and following year in accordance with the guidelines established bythe Board of Directors.

Caneticexpects to sell its physical production to independent marketers and end-usersthat 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.

25

----

***Additional InformationConcerning Abandonment and Reclamation Costs***

The following table setsforth well abandonment costs deducted in the estimation of Canetic’s future netrevenue 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%** | ** ** |
|       |       |                                                   |       |                                               |       |   |   |   |   |   |   |   |   |
| 2007       |       | 3,826                                                  |       | 3,648                                              |       | 2,663 |   | 2,539 |   | 5,356 |   | 5,107 |   |
| 2008       |       | 6,095                                                  |       | 5,283                                              |       | 4,812 |   | 4,171 |   | 4,755 |   | 4,122 |   |
| 2009       |       | 8,355                                                  |       | 6,584                                              |       | 5,770 |   | 4,547 |   | 6,278 |   | 4,947 |   |
| 2010       |       | 7,900                                                  |       | 5,659                                              |       | 5,288 |   | 3,788 |   | 5,879 |   | 4,211 |   |
| 2011       |       | 7,373                                                  |       | 4,802                                              |       | 4,675 |   | 3,044 |   | 7,358 |   | 4,792 |   |
| Thereafter |       | 171,578                                                |       | 41,189                                             |       | 218,730 |   | 39,018 |   | 118,584 |   | 32,426 |   |
| Total      |       | 205,127                                                |       | 67,164                                             |       | 241,938 |   | 57,107 |   | 148,210 |   | 55,604 |   |

 

Facility abandonment andreclamation costs of $158.8 million ($51.1 million discounted at 10%) are notincluded in the estimate of future net revenue.

***Tax Horizon***

Asa result of the structure of the Trust and the Operating Entities,substantially all of the taxable income that would otherwise arise in Caneticor any other affiliated entities will accrue in the Trust and will be allocatedby the Trust to Unitholders.  This isprimarily accomplished through the payment and deduction of interest on debt orthe payment of the Canetic NPI’s to the Trust. Therefore, no significant amount of income tax is anticipated to beincurred or paid by Canetic.  Ifthe proposed changes to the taxation of income trusts are enacted, taxes couldbe exigible in the Trust as certain distributions would no longer be adeduction in the calculation of its taxable income.  For more information on these proposals, seealso “*Risk Factors — October 31 Proposals*”.

***Costs Incurred***

The following tablesummarizes expenditures (net of incentives and net of certain proceeds andincluding capitalized general and administrative expenses) related to Canetic’sactivities with respect to the year ended December 31, 2006: 

| Capital Expenditures ($000s) | ** ** | **2006**      | ** ** |
|----------------------------------------|------------|---------------|------------|
|                                   |       |          |       |
| Land                                   | ** ** | **14,868**    | ** ** |
| Geological and  Geophysical            | ** ** | **2,783**     | ** ** |
| Drilling and  Completion               | ** ** | **215,593**   | ** ** |
| Production  Equipment and Facilities   | ** ** | **118,044**   | ** ** |
|                                   | ** ** | ** **    | ** ** |
| Net Development  Expenditures          | ** ** | **351,288**   | ** ** |
| Major  Acquisitions                    | ** ** | ** **    | ** ** |
| StarPoint                              | ** ** | **2,511,746** | ** ** |
| Samson                                 | ** ** | **924,635**   | ** ** |
| Producing Properties                   | ** ** | **23,869**    | ** ** |
| Minor Property  Acquisitions           | ** ** | **32,416**    | ** ** |
| Minor Property  Dispositions           | ** ** | **(17,167**   | **)**      |
| Net capital  expenditures              | ** ** | **3,826,787** | ** ** |

 

26

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***Exploration andDevelopment Activities***

The followingtable sets forth the gross and net exploratory and development wells in whichCanetic participated during the year ended December 31, 2006:
| ** **  | ** ** | **Exploratory Wells** | ** ** | **Development Wells** | ** ** |
|-------------|------------|----------------------------|------------|----------------------------|------------|
| ** **  | ** ** | **Gross**                  | ** ** | **Net**                    | ** ** | **Gross** | ** ** | **Net** | ** ** |
|        |       |                       |       |                       |       |   |   |   |   |
| Oil         |       | 11                         |       | 8.6                        |       | 150 |   | 73.2 |   |
| Natural Gas |       | 23                         |       | 9.8                        |       | 182 |   | 75.9 |   |
| Service     |       | 0                          |       | 0.0                        |       | 5 |   | 2.2 |   |
| Dry         |       | 2                          |       | 0.8                        |       | 5 |   | 4.3 |   |
| Total       |       | 36                         |       | 19.2                       |       | 342 |   | 155.2 |   |

 

***Production Estimates***

The followingtable sets out the volume of the Trust’s company interest forecast pricingproduction estimated for 2007, which is reflected in the estimate of future netrevenue disclosed in the tables contained under “*Disclosure of Reserves Data*”.  
| ** **           | ** ** | **Light and  Medium Oil** | ** ** | **Heavy Oil** | ** ** | **Natural Gas** | ** ** | **Natural Gas  Liquids** | ** ** | **Boe**     | ** ** |
|----------------------|------------|-------------------------------------|------------|--------------------|------------|----------------------|------------|-------------------------------|------------|-------------|------------|
| **2007**             | ** ** | **(Bbls/d)**                        | ** ** | **(Bbls/d)**       | ** ** | **(Mcf/d)**          | ** ** | **(Bbls/d)**                  | ** ** | **(Boe/d)** | ** ** |
|                 |       |                                |       |               |       |                 |       |                          |       |        |       |
| Proved Producing     |       | 26,079                              |       | 5,848              |       | 188,992              |       | 5,732                         |       | 69,158      |       |
| Total Proved         |       | 29,144                              |       | 6,327              |       | 202,851              |       | 6,187                         |       | 75,467      |       |
| Proved plus probable |       | 31,129                              |       | 6,769              |       | 216,968              |       | 6,655                         |       | 80,714      |       |

*** ***

***Production History***

The followingtables summarize certain information in respect of production, product pricesreceived, royalties paid, operating expenses and resulting netback for theperiods indicated below. 
| ** **                                   | ** ** | **Quarter Ended** | ** ** |
|----------------------------------------------|------------|------------------------|------------|
| ** **                                   | ** ** | **2006**               | ** ** |
| ** **                                   | ** ** | **Dec 31**        | ** ** | **Sept 30** | ** ** | **June 30** | ** ** | **Mar 31** | ** ** |
| **Average  Daily Production**                |       |                   |       |   |   |   |   |   |   |
| Light and Medium  Crude Oil (Bbls/d)         |       | 31,874                 |       | 32,759 |   | 31,969 |   | 32,028 |   |
| Heavy Oil  (Bbls/d)                          |       | 4,839                  |       | 5,555 |   | 5,379 |   | 5,597 |   |
| Natural Gas  (Mmcf/d)                        |       | 221                    |       | 181 |   | 166 |   | 176 |   |
| NGL (Bbls/d)                                 |       | 6,689                  |       | 5,925 |   | 5,043 |   | 5,763 |   |
| Combined (Boe/d)                             |       | 80,276                 |       | 74,475 |   | 70,061 |   | 72,738 |   |
|                                         |       |                   |       |   |   |   |   |   |   |
| **Average  Price Received (before hedging)** |       |                   |       |   |   |   |   |   |   |
| Light and Medium  Crude Oil ($/Bbl)          |       | 55.08                  |       | 70.17 |   | 70.07 |   | 58.01 |   |
| Heavy Oil  ($/Bbl)                           |       | 39.76                  |       | 50.54 |   | 50.36 |   | 33.26 |   |
| Natural Gas  ($/Mcf)                         |       | 6.90                   |       | 6.21 |   | 5.97 |   | 8.94 |   |
| NGL ($/Bbl)                                  |       | 45.44                  |       | 50.60 |   | 48.90 |   | 46.86 |   |
| Combined ($/Boe)                             |       | 47.08                  |       | 53.78 |   | 53.52 |   | 53.52 |   |
| ** **                                   |       |                   |       |   |   |   |   |   |   |
| **Royalties**                                |       |                   |       |   |   |   |   |   |   |
| Light and Medium  Crude Oil ($/Bbl)          |       | 9.22                   |       | 11.10 |   | 12.36 |   | 9.61 |   |
| Heavy Oil  ($/Bbl)                           |       | 5.42                   |       | 9.38 |   | 7.77 |   | 3.47 |   |
| Natural Gas  ($/Mcf)                         |       | 1.43                   |       | 0.94 |   | 1.29 |   | 2.03 |   |
| NGL ($/Bbl)                                  |       | 8.52                   |       | 15.60 |   | 12.92 |   | 10.58 |   |
| Combined ($/Boe)                             |       | 8.63                   |       | 9.11 |   | 10.21 |   | 10.25 |   |

 

27

----

 
| ** **                          | ** ** | **Quarter Ended** | ** ** |
|-------------------------------------|------------|------------------------|------------|
| ** **                          | ** ** | **2006**               | ** ** |
| ** **                          | ** ** | **Dec 31**        | ** ** | **Sep 30** | ** ** | **June 30** | ** ** | **Mar 31** | ** ** |
| **Operating Expenses**              |       |                   |       |   |   |   |   |   |   |
| Light and Medium Crude  Oil ($/Bbl) |       | 12.46                  |       | 11.12 |   | 9.82 |   | 9.74 |   |
| Heavy Oil ($/Bbl)                   |       | 13.60                  |       | 15.97 |   | 12.23 |   | 10.09 |   |
| Natural Gas ($/Mcf)                 |       | 1.41                   |       | 1.49 |   | 1.42 |   | 1.41 |   |
| NGL ($/Bbl)                         |       | —                 |       | — |   | — |   | — |   |
| Combined ($/Boe)                    |       | 9.67                   |       | 9.72 |   | 8.80 |   | 8.49 |   |
|                                |       |                   |       |   |   |   |   |   |   |
| **Transportation**                  |       |                   |       |   |   |   |   |   |   |
| Light and Medium Crude  Oil ($/Bbl) |       | 0.27                   |       | 0.24 |   | 0.22 |   | 0.21 |   |
| Heavy Oil ($/Bbl)                   |       | 0.29                   |       | 0.23 |   | 0.21 |   | 0.19 |   |
| Natural Gas ($/Mcf)                 |       | 0.21                   |       | 0.24 |   | 0.22 |   | 0.22 |   |
| NGL ($/Bbl)                         |       | 0.24                   |       | 0.25 |   | 0.26 |   | 0.23 |   |
| Combined ($/Boe)                    |       | 0.71                   |       | 0.73 |   | 0.67 |   | 0.66 |   |
|                                |       |                   |       |   |   |   |   |   |   |
| **Netback Received ($/Boe)**        |       |                   |       |   |   |   |   |   |   |
| Light and Medium Crude  Oil         |       | 33.13                  |       | 47.71 |   | 47.67 |   | 38.45 |   |
| Heavy Oil                           |       | 20.46                  |       | 24.95 |   | 30.16 |   | 19.51 |   |
| Natural Gas                         |       | 3.86                   |       | 3.54 |   | 3.04 |   | 5.27 |   |
| NGL                                 |       | 36.68                  |       | 34.75 |   | 35.72 |   | 36.06 |   |
| Combined                            |       | 28.07                  |       | 34.23 |   | 33.85 |   | 34.11 |   |

 

28

----

The following table indicates Canetic’s average dailyproduction from its important fields for the year ended December 31, 2006:
| ** **                  | ** ** | **Light and Medium  Crude Oil** | ** ** | **Heavy Oil** | ** ** | **Gas**      | ** ** | **NGL**     | ** ** | **BOE**     | ** ** |
|-----------------------------|------------|------------------------------------------------|------------|--------------------|------------|--------------|------------|-------------|------------|-------------|------------|
| ** **                  | ** ** | **(Bbl/d)**                                    | ** ** | **(Bbl/d)**        | ** ** | **(MMcf/d)** | ** ** | **(Bbl/d)** | ** ** | **(BOE/d)** | ** ** |
| **Alberta**                 |       |                                           |       |               |       |         |       |        |       |        |       |
| Acheson                     |       | 870                                            |       | 0                  |       | 13.1         |       | 1,195       |       | 4,252       |       |
| Alderson / Alderson  East   |       | 1,991                                          |       | 0                  |       | 0.7          |       | 1           |       | 2,101       |       |
| Bigoray                     |       | 1,129                                          |       | 0                  |       | 6.9          |       | 442         |       | 2,719       |       |
| Brazeau                     |       | 547                                            |       | 0                  |       | 6.3          |       | 325         |       | 1,916       |       |
| Countess                    |       | 0                                              |       | 0                  |       | 8.0          |       | 3           |       | 1,332       |       |
| Duchess / Rosemary          |       | 1,208                                          |       | 0                  |       | 2.3          |       | 10          |       | 1,600       |       |
| Ferrybank                   |       | 16                                             |       | 0                  |       | 3.8          |       | 119         |       | 761         |       |
| Gilby / Medicine River      |       | 356                                            |       | 0                  |       | 8.8          |       | 273         |       | 2,096       |       |
| Golden Spike                |       | 210                                            |       | 0                  |       | 4.3          |       | 354         |       | 1,288       |       |
| Homeglen / Rimbey           |       | 948                                            |       | 0                  |       | 9.4          |       | 349         |       | 2,867       |       |
| Innisfail / Innisfail  East |       | 495                                            |       | 0                  |       | 4.5          |       | 222         |       | 1,466       |       |
| Kaybob South                |       | 249                                            |       | 0                  |       | 3.5          |       | 306         |       | 1,141       |       |
| Leckie                      |       | 2                                              |       | 0                  |       | 4.9          |       | 0           |       | 822         |       |
| Mitsue                      |       | 1,249                                          |       | 0                  |       | 1.5          |       | 187         |       | 1,684       |       |
| Pouce Coupe                 |       | 455                                            |       | 0                  |       | 5.0          |       | 112         |       | 1,404       |       |
| Provost                     |       | 1,391                                          |       | 0                  |       | 0.6          |       | 19          |       | 1,507       |       |
| Red Rock                    |       | 10                                             |       | 0                  |       | 3.4          |       | 155         |       | 739         |       |
| Simonette                   |       | 732                                            |       | 0                  |       | 1.2          |       | 112         |       | 1,043       |       |
| Tatagwa                     |       | 753                                            |       | 0                  |       | 0.0          |       | 0           |       | 753         |       |
| Willesden Green             |       | 1,393                                          |       | 0                  |       | 8.2          |       | 354         |       | 3,109       |       |
| Other Properties            |       | 4,364                                          |       | 763                |       | 58.1         |       | 1,027       |       | 15,835      |       |
| **Total Alberta**           | ** ** | **18,368**                                     | ** ** | **763**            | ** ** | **154.5**    | ** ** | **5,565**   | ** ** | **50,435**  | ** ** |
| ** **                  |       |                                           | ** ** | ** **         | ** ** | ** **   | ** ** | ** **  | ** ** | ** **  | ** ** |
| **Saskatchewan**            |       |                                           |       |               |       |         |       |        |       |        |       |
| Cantal                      |       | 2,566                                          |       | 0                  |       | 3.1          |       | 0           |       | 3,077       |       |
| Furness                     |       | 0                                              |       | 2,336              |       | 0.6          |       | 0           |       | 2,444       |       |
| Ingoldsby                   |       | 867                                            |       | 0                  |       | 0.2          |       | 0           |       | 895         |       |
| Queensdale                  |       | 1,815                                          |       | 0                  |       | 1.0          |       | 0           |       | 1,976       |       |
| Unwin                       |       | 0                                              |       | 766                |       | 0.0          |       | 0           |       | 766         |       |
| Other Properties            |       | 6,825                                          |       | 1,476              |       | 2.4          |       | 0           |       | 8,710       |       |
| **Total Saskatchewan**      | ** ** | **12,073**                                     | ** ** | **4,578**          | ** ** | **7.3**      | ** ** | **0**       | ** ** | **17,868**  | ** ** |
| ** **                  |       |                                           | ** ** | ** **         | ** ** | ** **   | ** ** | ** **  | ** ** | ** **  | ** ** |
| **British Columbia**        |       |                                           |       |               |       |         |       |        |       |        |       |
| Buick/West Buick            |       | 48                                             |       | 0                  |       | 4.4          |       | 84          |       | 858         |       |
| Fireweed                    |       | 11                                             |       | 0                  |       | 1.5          |       | 14          |       | 271         |       |
| Fort St John                |       | 86                                             |       | 0                  |       | 9.2          |       | 52          |       | 1,673       |       |
| Stoddart                    |       | 64                                             |       | 0                  |       | 1.9          |       | 24          |       | 409         |       |
| Other Properties            |       | 0                                              |       | 0                  |       | 4.7          |       | 119         |       | 908         |       |
| **Total British Columbia**  | ** ** | **209**                                        | ** ** | **0**              | ** ** | **21.7**     | ** ** | **293**     | ** ** | **4,119**   | ** ** |
| ** **                  |       |                                           | ** ** | ** **         | ** ** | ** **   | ** ** | ** **  | ** ** | ** **  | ** ** |
| **Manitoba**                |       |                                           |       |               |       |         |       |        |       |        |       |
| Virden                      |       | 665                                            |       | 0                  |       | 0.4          |       | 0           |       | 738         |       |
| Other Properties            |       | 537                                            |       | 0                  |       | 0.0          |       | 0           |       | 531         |       |
| **Total Manitoba**          | ** ** | **1,202**                                      | ** ** | **0**              | ** ** | **0.4**      | ** ** | **0**       | ** ** | **1,269**   | ** ** |
| ** **                  |       |                                           | ** ** | ** **         | ** ** | ** **   | ** ** | ** **  | ** ** | ** **  | ** ** |
| **United States**           |       |                                           |       |               |       |         |       |        |       |        |       |
| USA Prospect                |       | 306                                            |       | 0                  |       | 2.4          |       | 0           |       | 713         |       |
| **Total United States**     | ** ** | **306**                                        | ** ** | **0**              | ** ** | **2.4**      | ** ** | **0**       | ** ** | **713**     | ** ** |
| ** **                  |       |                                           |       |               |       |         |       |        |       |        |       |
| **Total Canetic**           | ** ** | **32,158**                                     | ** ** | **5,341**          | ** ** | **186.3**    | ** ** | **5,858**   | ** ** | **74,404**  | ** ** |

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**Note:**

(1)                                  Productionnumbers reflect total production averaged over the course of the year, duringwhich Canetic owned the properties.

**Employees**

Canetic had a total of approximately540 full time employees (331 head office employees and 209 field employees) atDecember 31, 2006.

**Industry Conditions**

***Introduction***

The oil and gas industryis 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 levelsof government and with respect to pricing and taxation of oil and natural gasby agreements among the governments of Canada, Alberta, British Columbia,Saskatchewan and Manitoba, all of which should be carefully considered byinvestors in the oil and gas industry. It is not expected that any of these controls and regulations will affectthe operations of the Operating Entities in a manner materially different thanthey would affect other oil and gas companies or trusts of similar size.  All current legislation is a matter of publicrecord and Canetic is unable to predict what additional legislation oramendments may be enacted.  Outlinedbelow are some of the principal aspects of legislation, regulations andagreements governing the oil and gas industry.

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**Pricingand Marketing — Natural Gas**

In Canada, natural gas issold throughout the country at various market hubs that are connected toseveral pipelines within Canada and the United States.  The transaction price is determined bynegotiation between buyers and sellers and includes the utilization ofelectronic trading platforms and various publications and reference indexes.  Prices depend on many variables including butnot limited to supply and demand fundamentals, the price of NYMEX natural gascontracts, distance to alternate markets, pipeline costs, natural gas storagelevels, competing fuels, contract term, weather conditions and foreign exchangerates.  Natural gas exported from Canadais subject to regulation by the National Energy Board (the “**NEB**”) and the Government of Canada.  The price received for natural gas that isexported depends largely on the same variables noted above including the markethub prices at the delivery end of the export pipelines.  Exporters are free to negotiate prices andother terms with purchasers, provided that the export contracts must continueto meet certain other criteria prescribed by the NEB and the Government ofCanada.  Natural gas exports for a termof less than 2 years or for a term of 2 to 20 years (in quantities of not morethan 30,000 cubic meters per day), must be made pursuant to an NEB order.  Any natural gas export to be made pursuant toa contract of longer duration (to a maximum of 25 years) or a larger quantityrequires an exporter to obtain an export license from the NEB and the issuanceof such license requires the approval of the Governor in Council.

The governments ofAlberta, British Columbia and Saskatchewan****alsoregulate the removal of natural gas from those provinces for consumptionelsewhere based on such factors as reserve availability, transportationarrangements and market considerations.

***Pricingand Marketing - Oil***

In Canada, producers ofoil negotiate sales contracts directly with oil purchasers, with the resultthat the market determines the price of oil. Such price depends in part on oil type and quality, price of competingfuels, distance to market, the value of refined products, supply/demand balanceand other contractual terms.  Oilexporters are also entitled to enter into export contracts and export oilprovided that, for contracts that do not exceed one year in the case of lightcrude oil and two years in the case of heavy crude oil, an export order isobtained from the NEB prior to the export. Any export pursuant to a contract of longer duration (to a maximum of 25years) must be made pursuant to an NEB export license and Governor in Councilapproval.

***Pipeline Capacity***

Although pipelineexpansions are ongoing, the lack of firm pipeline capacity continues to affectthe oil and natural gas industry and limit the ability to produce and to marketnatural gas production.  In addition, thepro-rationing of capacity on the inter-provincial pipeline systems alsocontinues to affect the ability to export oil and natural gas.

***The North AmericanFree Trade Agreement***

On January 1, 1994, theNorth American Free Trade Agreement (“**NAFTA**”)among the governments of Canada, the U.S. and Mexico became effective.  The NAFTA carries forward most of thematerial energy terms contained in the Canada U.S. Free Trade Agreement.  In the context of energy resources, Canadacontinues to remain free to determine whether exports of energy resources tothe U.S. or Mexico will be allowed, provided that any export restrictions arejustified under certain provisions of the General Agreement on Tariffs andTrade, and further provided that any export restrictions do not: (i) reduce theproportion of energy resources exported relative to the total supply of theenergy resource (based upon the proportion prevailing in the most recent 36month period or in such other representative period as the parties may agree),(ii) impose an export price higher than the domestic price subject to anexception with respect to certain measures which only restrict the volume ofexports, and (iii) disrupt normal channels of supply.  All three countries are prohibited fromimposing minimum or maximum export or import price requirements, provided, inthe case of export price requirements, prohibition in any circumstances inwhich any other form of quantitative restriction is prohibited, and in the caseof import price requirements, such requirements do not apply with respect toenforcement of countervailing and anti-dumping orders and undertakings.

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The NAFTA contemplatesthe reduction of Mexican restrictive trade practices in the energy sector andprohibits discriminatory border restrictions and export taxes.  The NAFTA also contemplates clearerdisciplines on regulators to ensure fair implementation of any regulatorychanges and to minimize disruption of contractual arrangements and avoid undueinterference with pricing, marketing and distribution arrangements, which isimportant for Canadian natural gas exports.

**Provincial Royalties and Incentives**

***General***

In addition to federalregulation, each province has legislation and regulations that govern landtenure, royalties, production rates, environmental protection and othermatters.  The royalty regime is asignificant factor in the profitability of crude oil, natural gas, natural gasliquids and sulphur production. Royalties payable on production from lands other than Crown lands aredetermined by negotiations between the mineral owner and the lessee, althoughproduction from such lands is also subject to certain provincial taxes androyalties.  These royalties are noteligible for incentive programs sponsored by various governments as discussedbelow.  Crown royalties are determined bygovernmental regulation and are generally calculated as a percentage of thevalue of the gross production.  The rateof royalties payable generally depends in part on prescribed reference prices,well productivity, geographical location, field discovery date, method ofrecovery and the type or quality of the petroleum product produced.  Other royalties and royalty-like interestsare from time to time carved out of the working interest owner’s interestthrough non-public transactions.  Theseare often referred to as overriding royalties, gross overriding royalties, netprofits interests or net carried interests.

From time to time thegovernments of the western Canadian provinces have established incentiveprograms for exploration and development. Such programs often provide for royalty rate reductions, royaltyholidays and tax credits for the purpose of encouraging oil and natural gasexploration or enhanced recovery projects. The programs are designed to encourage exploration and developmentactivity by improving earnings and funds flow within the industry.  Royalty holidays and reductions would reducethe amount of Crown royalties paid by oil and gas producers to the provincialgovernments and would increase the net income and funds flow from operations ofsuch producers.  However, the trend inrecent years has been for provincial governments to allow such incentiveprograms to expire without renewal, and consequently few such incentiveprograms are currently operative.

The Canadian federalcorporate income tax rate levied on taxable income is 22.1% effective January1, 2007 for active business income including resource income.  With the elimination of the corporate surtaxeffective January 1, 2008 and other rate reductions introduced in the 2006Federal Budget, the federal corporate income tax rate will decrease to 19% inthree steps: 20.5% on January 1, 2008, 20% on January 1, 2009 and 19% onJanuary 1, 2010.

***Alberta***

Regulations made pursuantto the *Mines and Minerals Act*(Alberta) provide various incentives for exploring for and developing oilreserves in Alberta.  Oil produced fromhorizontal extensions commenced at least 5 years after the well was originallyspudded may also qualify for a royalty reduction.  A 24 month, 8,000 m3 exemption is available to production from areactivated well that has not produced for: (i) a 12 month period, if resumingproduction in October, November or December of 1992 or January, 1993; or (ii) a24 month period, if resuming production in February 1993 or later.  As well, oil production from eligible newfield and new pool wildcat wells and deeper pool test wells spudded or deepenedafter September 30, 1992 is entitled to a 12 month royalty exemption (to amaximum of $1 million).  Oil producedfrom low productivity wells, enhanced recovery schemes (such as injectionwells) and experimental projects is also subject to royalty reductions.

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

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In Alberta, the royaltyreserved to the Crown in respect of natural gas production, subject to variousincentives, is between 15% and 30%, in the case of new natural gas, and between15% and 35%, in the case of old natural gas, depending upon a prescribed orcorporate average reference price. Natural gas produced from qualifying intervals in eligible gas wellsspudded or deepened to a depth below 2,500 meters is also subject to a royaltyexemption, the amount of which depends on the depth of the well.

Oil sands projects aresubject to a specific regulation made effective July 1, 1997 and expiring June30, 2007, which, among other things, determines the Crown’s share of crude andprocessed oil sands products.

***Regulations made pursuant to the Mines and Minerals Act(Alberta) provided various incentives for exploring and developing oil reservesin Alberta.  However, the AlbertaGovernment announced in August of 2006 that four royalty programs were to beamended, a new program was to be introduced and the Alberta Royalty Tax CreditProgram (“***ARTC”) was to be eliminated, effectiveJanuary 1, 2007.  The programs affectedby this announcement are: (i) Deep Gas Royalty Holiday; (ii) Low ProductivityWell Royalty Reduction; (iii) Reactivated Well Royalty Exemption; and (iv)Horizontal Re-Entry Royalty Reduction. The program being introduced is the Innovative Energy TechnologiesProgram (the “IETP”) which is intended to promotethe producers’ investment in research, technology and innovation for thepurposes of improving environmental performance whilst creating commercialvalue.  The IETP provides royaltyreductions which are presumed to reduce financial risk.  Alberta Energy will decide which projectsqualify and the level of support that will be provided.  The deadline for the IETP’s third round ofapplications is May 31, 2007.

***On February 16, 2007, the Alberta Government announced thata review of the province’s royalty and tax regime (including income tax andfreehold mineral rights tax) pertaining to oil, gas and oil sands will beconducted by a panel of experts, with the assistance of individual Albertansand key stakeholders.  The purpose ofthis process is to ensure that Albertans are receiving a fair share from energydevelopment through royalties, taxes and fees. The issues to be reviewed during this examination process are:  (i) undertaking a comparison of Alberta’sroyalty system to other oil and gas producing jurisdictions, taking intoaccount investment economics and industry returns and risks in Alberta; (ii)whether Alberta’s royalty system is sufficiently sensitive to marketconditions; (iii) whether the current revenue minus cost system for oil sandsroyalties is optimal; (iv) which programs built into the existing royaltysystem should be retained or strengthened, and which should be adapted oreliminated; (v) how the tax treatment of the oil and gas sector compares toother sectors and jurisdictions; (vi) the economic and fiscal impacts of anypossible changes to the royalty and corporate tax structures; and (vii) howexisting resource development should be treated if changes are to be made tothe fiscal regime.  The review panel isto produce a final report that will be presented to the Minister of Finance byAugust, 31, 2007.***

***Saskatchewan***

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

The amount payable as aroyalty in respect of natural gas is determined by a sliding scale based on areference price (which is the greater of the amount obtained by the producerand a prescribed minimum price), the quantity produced in a given month, thetype of natural gas and the vintage of the natural gas.  As an incentive for the production andmarketing of natural gas which may have been flared, the royalty rate onnatural gas produced in association with oil is less than on non-associatednatural gas.  The royalty and productiontax classifications of gas production are “fourth tier gas” introduced October1, 2002, “third tier gas”, “new gas” and “old gas”.  The Crown royalty and freehold production taxfor gas is price sensitive and varies between the base royalty rate of 5% for “fourthtier gas” and 20% for “old gas”.  Themarginal royalty rates are between 30% for “fourth tier gas” and 45% for “oldgas”.

 

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

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

A modified systemof incentive volumes and maximum royalty/tax rates applicable to the initialproduction from oil wells and gas wells with a finished drilling date on orafter October 1, 2002 was introduced. The incentive volumes are applicable to various well types and aresubject to a maximum royalty rate of 2.5% and a freehold production tax rate ofzero per cent.

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

In 1975 the Government ofSaskatchewan introduced a Royalty Tax Rebate (“**RTR**”) as a response to the federal government disallowingcrown royalties and similar taxes as a deductible business expense for incometax purposes.  As of January 1, 2007 theremaining balance of any unused RTR will be limited in its carry forward to theyears since the federal government had the initiative to reintroduce the fulldeduction of provincial resource royalties from federal and provincial taxableincome.

***Land Tenure***

Crude oil and natural gaslocated in the western Canadian provinces is owned predominantly by therespective provincial governments. Provincial governments grant rights to explore for and produce oil andnatural gas pursuant to leases, licenses and permits for varying periods and onconditions set forth in provincial legislation including requirements toperform specific work or to make payments. Oil and natural gas located in such provinces can also be privatelyowned and rights to explore for and produce such oil and natural gas aregranted by lease on such terms and conditions as may be negotiated.

***Environmental Regulation***

The oil and natural gasindustry is subject to environmental regulation pursuant to local, provincialand federal legislation.  Environmentallegislation provides for restrictions and prohibitions on releases or emissionsand regulation on the storage and transportation of various substances producedor utilized in association with certain oil and gas industry operations and canaffect the location and operation of wells and facilities and the extent towhich exploration and development is permitted. In addition, legislation requires that well and facilities sites beabandoned and reclaimed to the satisfaction of provincial authorities.  As well, applicable environmental laws mayimpose remediation obligations with respect to property designated as acontaminated site upon certain responsible persons, which include personsresponsible for the substance causing the contamination, persons who caused therelease of the substance and any past or present owner, tenant or other personin possession of the site.  Compliancewith such legislation can require significant expenditures and a breach of suchlegislation may result in the suspension or revocation of necessary licensesand authorizations, civil liability for pollution damage, the imposition offines and penalties or the issuance of clean up orders.

Environmental legislationin the Province of Alberta has been consolidated into the *Environmental Protection and Enhancement Act*(Alberta)(the “**EPEA**”), whichcame into force on September 1, 1993 and the *Oiland Gas Conservation Act* (Alberta) (the “**OGCA**”).  The EPEA and OGCA impose stricterenvironmental standards, require more stringent compliance, reporting andmonitoring obligations and significantly increases penalties.  In 2006, the Alberta Government enactedregulations pursuant to the EPEA to specifically target sulphur oxide andnitrous oxide emissions from industrial operations including the oil and gasindustry.  No additional expenses areforeseen that are associated with complying with the new regulations.  Canetic is committed to meeting itsresponsibilities to protect the environment wherever it operates andanticipates making increased expenditures of both a capital and an expensenature as a result of the increasingly stringent laws relating to theprotection of the environment.  Caneticwill be taking such steps as required to ensure compliance with the EPEA andsimilar legislation in other jurisdictions in 

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which it operates.  Canetic believes that it is in materialcompliance with applicable environmental laws and regulations.  Canetic also believes that it is reasonablylikely that the trend towards stricter standards in environmental legislationand regulation will continue.

In December, 2002, theGovernment of Canada ratified the Kyoto Protocol (“**Protocol**”).  TheProtocol calls for Canada to reduce its greenhouse gas emissions to 6% below1990 “business-as-usual” levels between 2008 and 2012.  Given revised estimates of Canada’s normalemissions levels, this target translates into an approximately 40% grossreduction in Canada’s current emissions. It remains uncertain whether the Kyoto target of 6% below 1990 emissionlevels will be enforced in Canada.  TheFederal Government has introduced legislation aimed at reducing greenhouse gasemissions using a “intensity based” approach, the specifics of which have yetto be determined.  Bill C-288, which isintended to ensure that Canada meets its global climate change obligationsunder the Kyoto Protocol, was passed by the House of Commons on February 14,2007.  As details of the implementationof this legislation have not yet been announced, the effect on our operationscannot be determined at this time.

***Trends***

Thereare a number of trends that have been developing in the oil and gas industryduring the past several years that appear to be shaping the near future of thebusiness.

The first trend is increasing volatility in both crude oil and naturalgas prices.  Natural gas prices arevulnerable to changes in supply and demand factors within North America.  The key categories for North American naturalgas demand is the use of natural gas in industrial demand, commercialheating-cooling load, residential and power generation.  North American natural gas demand issensitive to economic growth, weather, inventory levels and the price of otherfuels and the subsequent ability for fuel switching.  North American natural gas supply is sensitiveto pricing as drilling activity levels have historically moved directionallywith natural gas prices.  Thehistorically unseasonable weather experienced over the past couple of years hasresulted in significant swings in natural gas inventory levels and subsequentlyhigh volatility in natural gas prices.

Crudeoil demand growth is closely correlated with changes in economic growth.  The economic growth seen in China and therest of Asia over the past couple of years has significantly increased the demandfor crude oil.  As such, OPEC’s level ofunutilized production capacity has declined significantly to a level thatcauses concerns about supply being sufficient to meet future demand growth inthe event that geo-political or operational disruptions occur.  Crude oil prices will continue to be subjectto volatility until a greater cushion of unutilized production capacity isrestored.

Theimpact on the oil and gas industry from commodity price volatility issignificant.  During periods of highprices, producers generate sufficient funds flow from operations to conductactive exploration programs without external capital.  Increased commodity prices frequentlytranslate into very busy periods for service suppliers triggering premium costsfor their services.  The price of landand properties similarly increases during these periods.  During low commodity price periods,acquisition costs drop, as do internally generated funds to spend onexploration and development activities. With decreased demand, the prices charged by the various servicesuppliers also decline.

Asecond trend within the Canadian oil and gas industry is the consistent “renewal”of private and small junior oil and gas companies starting up business.  These companies often have experiencedmanagement teams from previous industry organizations that have disappeared asa part of the ongoing industry consolidation. Many are able to raise capital and recruit well qualified personnel.

Athird trend currently affecting the oil and gas industry is the impact oncapital markets caused by investor uncertainty in the North Americaneconomy.  The capital market volatilityin Canada has also been affected by uncertainties surrounding the economicimpact that the Protocol and other environmental initiatives will have on thesector and by the October 31 Proposals. See also “*Risk Factors*”.  Generally during the past year, the economicrecovery combined with increased commodity prices has caused an increase in newequity financings in the oil and gas industry, although the level wasnegatively impacted by the October 31 Proposals.  Canetic must continue to compete with thenumerous new companies and their new management teams and development plans inits access to capital.  The competitivenature of the oil and gas industry will cause opportunities for equityfinancings to be selective.  Somecompanies will have to rely on internally generated funds to conduct theirexploration and developmental programs

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**ADDITIONAL INFORMATION RESPECTING CANETIC RESOURCES TRUST**

**Units**

An unlimited number ofUnits may be created and issued pursuant to the Trust Indenture.  Each Unit represents an equal fractionalundivided beneficial interest in any distribution from the Trust (whether ofnet income, net realized capital gains or other amounts) and in any net assetsof the Trust in the event of termination or winding-up of the Trust.  All Units outstanding from time to time areentitled 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 theTrust.  All Units rank among themselvesequally and ratably without discrimination, preference or priority.  Each Unit is transferable, is not subject toany conversion or pre-emptive rights and entitles the holder thereof torequire the Trust to redeem any or all of the Units held by such holder (Seealso, “*Redemption Right*”) and toone vote at all meetings of Unitholders for each Unit held.  Unitholders shall not be subject to anyliability in contract or tort or of any other kind in connection with theassets, obligations or affairs of the Trust or with respect to any actsperformed by the Trustee or any other person pursuant to the Trust Indenture.

As at March 21, 2007,approximately 226.9 million Units were outstanding, approximately 10.6 millionUnits were reserved for issuance onconversion of the Convertible Debentures (as defined herein) andapproximately 2.0 million Units were available for future issuance pursuant tothe Trust’s Unit Award Incentive Plan (subject to increase in accordance withsuch plan).  See also “*Additional Information Respecting Canetic ResourcesInc. — Share Capital of Canetic Resources Inc.*” and “*Convertible Debentures of the Trust*”.

**SpecialVoting Units**

In order to allow theTrust flexibility in pursuing corporate acquisitions, the Trust Indentureallows for the creation of Special Voting Units which will enable the Trust toeffect exchangeable securities transactions. Exchangeable securities transactions are commonly used in corporateacquisitions to give the selling securityholder a tax deferred “rollover” onthe sale of the securityholder’s securities, which may not otherwise beavailable.  In an exchangeable securitiestransaction the tax event is generally deferred until the exchangeablesecurities are actually exchanged.

An unlimited number ofSpecial Voting Units may be created and issued pursuant to the TrustIndenture.  Holders of Special VotingUnits are not entitled to any distributions of any nature whatsoever from theTrust, but are entitled to such number of votes at meetings of Unitholders asmay be prescribed by the Board of Directors in the resolution authorizing theissuance of any Special Voting Units. Except for the right to vote at meetings of the Unitholders, the SpecialVoting Units shall not confer upon the holders thereof any other rights.

No Special Voting Unitsare issued and outstanding.

**ConvertibleDebentures of the Trust**

The Trust has five seriesof convertible debentures outstanding, the 6.5% Canetic Debentures; 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 materialattributes and characteristics of the Convertible Debentures.

The 6.5% CaneticDebentures were originally issued in the aggregate principal amount of $230million and $230 million principal amount was outstanding at March 13,2007.  The 6.5% Canetic Debentures matureon December 31, 2011.

The 8% Debentures wereoriginally issued in the aggregate principal amount of $75 million andapproximately $8.0 million principal amount was outstanding at March 13,2007.  The 8% Debentures mature on August31, 2009.

The 11% Debentures wereoriginally issued in the aggregate principal amount of $45 million andapproximately $1.6 million principal amount was outstanding at March 13,2007.  The 11% Debentures mature onDecember 31, 2007.

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The 6.5% Debentures wereoriginally issued in the aggregate principal amount of $60 million andapproximately $17.8 million principal amount was outstanding at March 13,2007.  The 6.5% Debentures mature on July31, 2010.

The 9.4% Debentures wereoriginally issued in the aggregate principal amount of $50 million andapproximately $5.6 million principal amount were outstanding at March 13,2007.  The 9.4% Debentures mature on July31, 2008.

***Terms of ConvertibleDebentures***

The 6.5% CaneticDebentures bear interest from the date of issue at 6.5% per annum, which ispayable semiannually in arrears on June 30 and December 31 in each year.  The 8% Debentures bear interest from the dateof issue at 8% per annum, which is payable semi-annually in arrears onFebruary 28 and August 31 in each year. The 11% Debentures bear interest from the date of issue at 11% perannum, which is payable semi-annually in arrears on June 30 andDecember 31 in each year.  The 6.5%Debentures bear interest from the date of issue at 6.5% per annum, which ispayable semi-annually in arrears on January 31 and July 31 in each year.  The 9.4% Debentures bear interest from thedate of issue at 9.4% per annum, which is payable semi-annually in arrears onJanuary 31 and July 31 in each year.

The principal amount of the Convertible Debentures is payable in lawfulmoney of Canada or, at the option of the Trust and subject to applicableregulatory approval, by payment of Units as further described under “*Payment Upon Redemption or Maturity*” and “*Redemption and Purchase*”.  The interest on the Convertible Debentures ispayable in lawful money of Canada including, at the option of the Trust andsubject to applicable regulatory approval, in accordance with the InterestObligation as described under “*InterestPayment Option*”.

The ConvertibleDebentures are direct obligations of the Trust and are not secured by any mortgage,pledge, hypothec or other charge and are subordinated to other liabilities ofthe Trust as described under “*Subordination*”.  The indentures governing the ConvertibleDebentures do not restrict the Trust from incurring additional indebtedness forborrowed money or from mortgaging, pledging or charging its properties tosecure any indebtedness.

***Conversion Privilege***

The 6.5% CaneticDebentures are convertible at the holder’s option into fully paid andnon-assessable Units at any time prior to 5:00 p.m.(Calgary time) on theearlier of December 31, 2011, and the business day immediately preceding thedate specified by Canetic for redemption of the Canetic Debentures, at aconversion price of $26.55 per Unit, being a conversion rate of approximately37.6648 Units for each $1,000 principal amount of 6.5% Canetic Debentures.

The 8% Debentures areconvertible at the holder’s option into fully paid and non-assessable Units atany 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 forredemption 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 principalamount of 8% Debentures.

The 11% Debentures areconvertible at the holder’s option into fully paid and non-assessable Units atany 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 Caneticfor 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 $1,000principal amount of 11% Debentures.

The 6.5%Debentures are convertible at the holder’s option into fully paid and non-assessableUnits 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 Caneticfor redemption of the 6.5% Debentures, at a conversion price of $18.96 perUnit, being a conversion rate of approximately 52.74 Units for each $1,000principal amount of 6.5% Debentures.

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

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***Redemption and Purchase***

The 6.5% CaneticDebentures are not redeemable on or before December 31, 2009.  After December 31, 2009 and prior tomaturity, the 6.5% Canetic Debentures may be redeemed in whole or in part fromtime to time at the option of the Trust on not more than 60 days and not lessthan 30 days prior notice, at a redemption price of $1,050 per Debenture afterDecember 31, 2009 and on or before December 31, 2010 and at a redemption priceof $1,025 per Debenture after December 31, 2010 and before maturity (each a “**6.5% Canetic Redemption Price**”) in eachcase, plus accrued and unpaid interest thereon, if any.

The 8% Debenturesare 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 theoption of the Trust on not more than 60 days and not less than 40 days priornotice, at a redemption price of $1,050 per 8% Debenture after August 31, 2007and on or before August 31, 2008 and at a redemption price of $1,025 per8% Debenture after August 31, 2008 and before maturity (each an “**8% Redemption Price**”), in each case, plus accrued andunpaid interest thereon, if any.

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

The 6.5% Debentures arenot redeemable on or before July 31, 2008. The Trust may, on not more than 60 days and not less than 30 days priornotice, 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 priceof $1,025 per Debenture after July 31, 2009 and before July 31, 2010 (each a “**6.5% Redemption Price**”), plus accrued and unpaid interestthereon, if any.

The Trust may, on notmore 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 on or before July31, 2007, and at a price of $1,025 per Debenture after July 31, 2007 and beforeJuly 31, 2008 (each a “**9.4% Redemption Price**”),plus accrued and unpaid interest thereon, if any.

The Trust has the rightto purchase Convertible Debentures in the market, by tender or by privatecontract.

***Payment upon Redemptionor Maturity***

On redemption or atmaturity, the Trust will repay the indebtedness represented by the ConvertibleDebentures by paying to Debentures Trustee in lawful money of Canada an amountequal to the aggregate applicable redemption price of the outstandingConvertible Debentures which are to be redeemed or the principal amount of theoutstanding Convertible Debentures which have matured together with accrued andunpaid interest thereon.  The Trust may,at its option, and subject to applicable regulatory approval, elect to satisfyits obligation to pay the applicable redemption price of the ConvertibleDebentures which are to be redeemed or the principal amount of the ConvertibleDebentures which have matured, as the case may be, by issuing Units to theholders of the Convertible Debentures. Any accrued and unpaid interest thereon will be paid in cash.  The number of Units to be issued will be determinedby dividing the aggregate applicable redemption price of the outstandingConvertible Debentures which are to be redeemed or the principal amount of theoutstanding Convertible Debentures which have matured, as the case may be, by95% of the Current Market Price of the Units on the date fixed for redemptionor the maturity date, as the case may be. The term “Current Market Price” is defined in the Convertible Debentureindentures to mean the weighted average trading price of the Units on the TSXfor the 20 consecutive trading days ending on the fifth trading day preceding thedate fixed for redemption or the maturity date, as the case may be.

***Subordination***

The payment of theprincipal of, and interest on, the Convertible Debentures is subordinated inright of payment, as set forth in the Convertible Debenture indentures, to theprior payment in full of all Senior Indebtedness of the Trust and indebtednessto trade creditors of the Trust.  “**Senior Indebtedness**” of the Trust is defined in thedebenture 

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indentures as theprincipal of and premium, if any, and interest on and other amounts in respectof all indebtedness of the Trust (whether outstanding as at the date of theConvertible Debenture indentures or thereafter incurred), other thanindebtedness evidenced by the Convertible Debentures and all other existing andfuture debentures or other instruments of the Trust which, by the terms of theinstrument creating or evidencing the indebtedness, is expressed to be *pari**passu*with, or subordinate in right of payment to, the Convertible Debentures.

The Convertible Debentureindentures provide that in the event of any insolvency or bankruptcyproceedings, or any receivership, liquidation, reorganization or other similarproceedings relative to the Trust, or to its property or assets, or in theevent of any proceedings for voluntary liquidation, dissolution or otherwinding-up of the Trust, whether or not involving insolvency or bankruptcy, orany marshalling of the assets and liabilities of the Trust, then those holdersof Senior Indebtedness, including any indebtedness to trade creditors, willreceive payment in full before the holders of Convertible Debentures will beentitled to receive any payment or distribution of any kind or character,whether in cash, property or securities, which may be payable or deliverable inany such event in respect of any of the Convertible Debentures or any unpaidinterest accrued thereon.  TheConvertible Debenture indentures also provide that the Trust will not make anypayment, 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 orrealization of security or otherwise in any manner whatsoever) on account ofindebtedness represented by the Convertible Debentures (a) in a mannerinconsistent with the terms (as they exist on the date of issue) of theConvertible Debentures or (b) at any time when an event of default has occurredunder the Senior Indebtedness and is continuing and the notice of such event ofdefault has been given by or on behalf of the holders of Senior Indebtedness tothe Trust, unless the Senior Indebtedness has been repaid in full.

The ConvertibleDebentures are effectively subordinate to claims of creditors of the Trust’ssubsidiaries except to the extent the Trust is a creditor of such subsidiariesranking at least *pari passu*withsuch other creditors.  Specifically, theConvertible Debentures are subordinated in right of payment to the priorpayment in full of all indebtedness under the Trust’s credit facilities.

***Priority over TrustDistributions***

The Convertible Debentureindentures provide that certain expenses of the Trust must be deducted incalculating the amount to be distributed to the Unitholders.  Accordingly, the funds required to satisfythe interest payable on the Convertible Debentures, as well as the amountpayable upon redemption or maturity of the Convertible Debentures or upon anEvent of Default (as defined below), will be deducted and withheld from theamounts that would otherwise be payable as distributions to Unitholders.

***Change of Control of theTrust***

Within 30 days following the occurrence of a change ofcontrol of the Trust involving the acquisition of voting control or directionover 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 theConvertible Debentures then outstanding (the “**DebentureOffer**”), at a price equal to 101% of the principal amount thereofplus accrued and unpaid interest (the “**DebentureOffer Price**”).

If 90% or more of theaggregate principal amount of any series of Convertible Debentures outstandingon the date of the giving of notice of the Change of Control have been tenderedto the Trust pursuant to the applicable Debenture Offer, the Trust will havethe right and obligation to redeem all the remaining Convertible Debentures ofthat series, at the applicable Debenture Offer Price.

***Interest Payment Option***

The Trust may elect, fromtime to time, to satisfy its obligation to pay all or any part of the intereston the Convertible Debentures (the “**InterestObligation**”), on the date it is payable under the applicableConvertible Debenture indenture (an “**Interest Payment Date**”),by delivering sufficient Units to the Debenture Trustee to satisfy all or thepart, as the case may be, of the Interest Obligation in accordance with theapplicable Convertible Debenture indenture (the “**UnitInterest 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 

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sales of, such Units,each as the Trust shall direct in its absolute discretion; (c) invest theproceeds of such sales in short-term permitted government securities (asdefined in the applicable Indenture) which mature prior to the applicableInterest Payment Date, and use the proceeds received from such permittedgovernment securities, together with any proceeds from the sale of Units notinvested as aforesaid, to satisfy the Interest Obligation; and (d) perform anyother action necessarily incidental thereto.

If a Unit InterestPayment Election is made, the sole right of a holder of Convertible Debenturesin respect of interest will be to receive cash from the Debenture Trustee outof the proceeds of the sale of Units (plus any amount received by the DebentureTrustee from the Trust attributable to any fractional Units) in fullsatisfaction of the Interest Obligation, and the holder of such ConvertibleDebentures will have no further recourse to the Trust in respect of theInterest Obligation.

***Events of Default***

The ConvertibleDebenture indentures provide that an event of default (“**Event of Default**”) in respect of the Convertible Debentureswill occur if any one or more of the following described events has occurredand is continuing with respect of the Convertible Debentures: (a) failure for10 days to pay interest on the Convertible Debentures when due; (b) failure topay 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 theTrust under bankruptcy or insolvency laws; or (d) default in the observance orperformance of any material covenant or condition of the Convertible DebentureIndentures and continuance of such default for a period of 30 days after noticein writing has been given by the Debenture Trustee to the Trust specifying suchdefault and requiring the Trust to rectify the same.  If an Event of Default has occurred and iscontinuing, the Debenture Trustee may, in its discretion, and shall uponrequest of holders of not less than 25% of the principal amount of theapplicable Convertible Debentures then outstanding, declare the principal ofand interest on all outstanding such Convertible Debentures to be immediatelydue and payable.  In certain cases, theholders of more than 50% of the principal amount of the applicable ConvertibleDebentures then outstanding may, on behalf of the holders of all suchConvertible Debentures, waive any Event of Default and/or cancel any suchdeclaration upon such terms and conditions as such holders shall prescribe.

***Offers for Debentures***

The ConvertibleDebenture indentures contain provisions to the effect that if an offer is madefor any series of Convertible Debentures, which is a take-over bid for suchseries of Convertible Debentures within the meaning of the *Securities Act* (Alberta) and not less than90% of such Convertible Debentures (other than Convertible Debentures held atthe date of the take-over bid by or on behalf of the offeror or associates oraffiliates of the offeror) are taken up and paid for by the offeror, theofferor will be entitled to acquire the Convertible Debentures held by theholders of such series of Convertible Debentures who did not accept the offeron the terms offered by the offeror.

***Modification***

The rights of the holdersof the Convertible Debentures may be modified in accordance with the terms ofthe Convertible Debenture indentures. For that purpose, among others, the Convertible Debenture indenturescontain certain provisions which will make binding on all Convertible Debentureholders’ resolutions passed at meetings of the holders of ConvertibleDebentures by votes cast thereat by holders of not less than 662¤3%of the principal amount of the Convertible Debentures present at the meeting orrepresented by proxy, or rendered by instruments in writing signed by theholders of not less than 662¤3%of the principal amount of the Convertible Debentures then outstanding. Incertain cases, the modification will, instead or in addition, require assent bythe holders of the required percentage of Debentures of each particularlyaffected series.

***Limitation on Issuance ofAdditional Convertible Debentures***

The Convertible Debentureindentures provide that the Trust shall not issue additional ConvertibleDebentures of equal ranking if the principal amount of all issued andoutstanding Convertible Debenture of the Trust exceeds 25% of the Total MarketCapitalization of the Trust immediately after the issuance of such additionalConvertible Debenture.  

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“**Total Market Capitalization**” is defined in the ConvertibleDebenture indentures as the total principal amount of all issued andoutstanding Convertible Debentures of the Trust which are convertible at theoption of the holder into Units of the Trust plus the amount obtained bymultiplying the number of issued and outstanding Units of the Trust by theCurrent Market Price of the Units on the relevant date.

***Limitation on NonResident Ownership***

The Debenture Trustee mayrequire declarations as to the jurisdictions in which beneficial owners ofConvertible Debentures are resident.  Ifthe Debenture Trustee becomes aware as a result of requiring such declarationsas to beneficial ownership, that the beneficial owners of 49% of the Units thenoutstanding (40% in the case of the 6.5% Debentures) and, on a fully dilutedbasis, are, or may be, non residents or that such a situation is imminent, theDebenture Trustee may make a public announcement thereof and shall not registera transfer of Convertible Debentures to a person unless the person provides adeclaration that the person is not a non resident.  If, notwithstanding the foregoing, theDebenture Trustee determines that a majority of the Units are held bynon-residents, the Debenture Trustee may send a notice to non resident holdersof Convertible Debentures, chosen in inverse order to the order of acquisitionor registration of the Convertible Debentures or in such manner as theDebenture Trustee may consider equitable and practicable, requiring them tosell their Convertible Debentures or a portion thereof within a specifiedperiod of not less than 60 days.  If theConvertible Debenture holders receiving such notice have not sold the specifiednumber of Convertible Debentures or provided the Debenture Trustee withsatisfactory evidence that they are not non residents within such period, theDebenture Trustee may on behalf of such holder of Convertible Debentures, and,in the interim, shall suspend the rights attached to such ConvertibleDebentures.  Upon such sale the affectedholders shall cease to be holders of Convertible Debentures, and their rightsshall be limited to receiving the net proceeds of sale upon surrender of suchConvertible Debentures.

***Book-Entry System forConvertible Debentures***

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

**Issuanceof Units**

The TrustIndenture provides that Units, including rights, warrants, options and othersecurities to purchase, to convert into or to exchange into Units, may becreated, issued, sold and delivered on such terms and conditions and at suchtimes as the Board of Directors may determine.

**CashDistributions**

The Trust makes cashdistributions in amounts equal to the interest, dividend and other income ofthe Trust, net of the Trust’s administrative expenses.  In addition, Unitholders may, at thediscretion of the Board of Directors, receive distributions in respect ofrepayments of principal made by Canetic to the Trust on the Canetic Notes.

Cash distributions aremade on or about the 15th day of each month to Unitholders of record on theimmediately preceding distribution record date. The Trust currently distributes $0.19 per Unit per month.  Future distributions are subject to thediscretion of the Board of Directors and may vary depending on, among otherthings, the current and anticipated commodity price environment.  See also “*RiskFactors*”.

**RedemptionRight**

Units are redeemable atany time on demand by the holders thereof upon delivery to the Trust of thecertificate or certificates representing such Units, accompanied by a dulycompleted and properly executed notice requesting redemption.  Upon receipt of the redemption request by theTrust, 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 theprincipal market on which the Units are quoted for trading during the 10trading day period commencing 

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immediately after thedate on which the Units are surrendered for redemption; and (ii) the “closingmarket price” on the principal market on which the Units are quoted for tradingon the date that the Units are surrendered for redemption.

For the purposes of thiscalculation, “market price” will be an amount equal to the simple average ofthe closing price of the Units for each of the trading days on which there wasa closing price; provided that, if the applicable exchange or market does notprovide a closing price but only provides the highest and lowest prices of theUnits traded on a particular day, the market price shall be an amount equal tothe simple average of the average of the highest and lowest prices for each ofthe trading days on which there was a trade; and provided further that if therewas trading on the applicable exchange or market for fewer than five of the 10trading days, the market price shall be the simple average of the followingprices established for each of the 10 trading days: the average of the last bidand last ask prices for each day on which there was no trading; the closingprice of the Units for each day that there was trading if the exchange ormarket provides a closing price; and the average of the highest and lowestprices of the Units for each day that there was trading, if the market providesonly the highest and lowest prices of Units traded on a particular day.  The “closing market price” shall be: anamount equal to the closing price of the Units if there was a trade on thedate; an amount equal to the average of the highest and lowest prices of theUnits if there was trading and the exchange or other market provides only thehighest and lowest prices of Units traded on a particular day, and the averageof the last bid and last ask prices if there was no trading on the date.

The aggregate MarketRedemption Price payable by the Trust in respect of any Units surrendered forredemption during any calendar month shall be satisfied by way of a cashpayment on the last day of the following month. The entitlement of Unitholders to receive cash upon the redemption oftheir Units is subject to the limitation that the total amount payable by theTrust in respect of such Units and all other Units tendered for redemption inthe same calendar month and in any preceding calendar month during the sameyear shall not exceed $100,000; provided that Canetic may, in its solediscretion, waive such limitation in respect of any calendar month.  If this limitation is not so waived, theMarket Redemption Price payable by the Trust in respect of Units tendered forredemption in such calendar month shall be paid on the last day of thefollowing month by the Trust distributing Redemption Notes having anaggregate principal amount equal to the aggregate Market Redemption Price ofthe Units tendered for redemption.

If at the time Units aretendered for redemption by a Unitholder, the outstanding Units are not listedfor trading on the TSX and are not traded or quoted on any other stock exchangeor market which Canetic considers, in its sole discretion, providesrepresentative fair market value price for the Units or trading of theoutstanding Units is suspended or halted on any stock exchange on which theUnits are listed for trading or, if not so listed, on any market on which theUnits are quoted for trading, on the date such Units are tendered forredemption or for more than five trading days during the 10 trading day period,commencing immediately after the date such Units were tendered for redemptionthen such Unitholder shall, instead of the Market Redemption Price, be entitledto receive a price per Unit (the “**AppraisedRedemption Price**”) equal to 90% of the fair market value thereof asdetermined by Canetic as at the date upon which such Units were tendered forredemption.  The aggregate AppraisedRedemption Price payable by the Trust in respect of Units tendered forredemption in any calendar month shall be paid on the last day of the thirdfollowing month by, at the option of the Trust: (i) a cash payment; or (ii) adistribution of Notes or Redemption Notes as described above.

It is anticipated thatthis redemption right will not be the primary mechanism for holders of Units todispose of their Units.  Redemption Notesthat may be distributed to Unitholders in connection with a redemption will notbe listed on any stock exchange and no market is expected to develop in suchRedemption Notes.  Redemption Notes willnot be qualified investments for trusts governed by registered retirementsavings plans, registered retirement income funds and deferred profit sharingplans.

**Restrictionson Non Resident Ownership**

Generally, a trust cannotqualify as a “mutual fund trust” for the purposes of the**Tax Act if it is established or is beingmaintained primarily for the benefit of non-residents.  Although not without uncertainty, this isgenerally accepted to exist in most situations where Non-Resident holders ownsignificantly in excess of 50% of the aggregate number of Units issued andoutstanding.  However, there is currentlyan 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 timeconsisted of “taxable Canadian property”.

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

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

Canetic may, at any timeand from time to time, in its sole discretion, request that the Trustee makereasonable efforts, as practicable in the circumstances, to obtain declarationsas to beneficial ownership, perform residency searches of Unitholders andbeneficial Canetic mailing address lists, and take such other steps specifiedby Canetic, at the cost of the Trust, to determine or estimate as best possiblethe residence of the beneficial owners of the Units.

If at any time the Boardof Directors, in its sole discretion, determines that it is in the bestinterest of the Trust, Canetic, notwithstanding the ability of the Trust tocontinue to rely on subsection 132(7)(a) of the Tax Act for the purpose ofqualifying as a “mutual fund trust” under the Tax Act, may (i) require theTrustee to refuse to accept a subscription for Units from, or issue or registera transfer of Units to, a person unless the person provides a declaration toCanetic that the Units to be issued or transferred to such person will not whenissued or transferred be beneficially owned by a Non-Resident; (ii) to theextent practicable in the circumstances, send a notice to registered holders ofUnits which are beneficially owned by Non-Residents, chosen in inverse order tothe order of acquisition or registration of such Units beneficially owned byNon-Residents or in such other manner as Canetic may consider equitable andpracticable, requiring them to sell their Units which are beneficially owned byNon-Residents or a specified portion thereof within a specific period of notless than 60 days.  If the Unitholdersreceiving such notice have not sold the specified number of such Units orprovided Canetic with satisfactory evidence that such Units are not beneficiallyowned by Non-Residents within such period, Canetic may, on behalf of suchregistered Unitholder, sell such Units and, in the interim, suspend the votingand distribution rights attached to such Units and make any distribution inrespect of such Units by depositing such amount in a separate bank account in aCanadian chartered bank (net of any applicable taxes).  Any sale may be made on any stock exchange onwhich the Units are then listed and, upon such sale, the affected holders shallcease to be holders of Units so disposed of and their rights shall be limitedto receiving the net proceeds of sale, and any distribution in respect thereofdeposited as aforesaid, net of applicable taxes and costs of sale, uponsurrender of the certificates representing such Units; (iii) delist the Unitsfrom any non-Canadian stock exchange; and (iv) take such other actions as theBoard of Directors determines, in its sole discretion, are appropriate in thecircumstances that will reduce or limit the number of Units held byNon-Residents to ensure that Canetic is not maintained primarily for thebenefit of Non-Residents.

Notwithstanding any otherprovision of the Trust Indenture, Non-Resident Unitholders, whether registeredholders or beneficial holders of Trust Units, are not be entitled to vote inrespect of any Special Resolutions to amend the provisions of the TrustIndenture relating to restrictions on Non-Resident ownership.

**Meetingsof Unitholders**

The Trust Indentureprovides that meetings of Unitholders must be called and held for, among othermatters, the appointment or removal of the Trustee, the appointment or removalof the auditors of the Trust, the approval of amendments to the Trust Indenture(except as described under “*Amendments tothe Trust Indenture*”), the sale of the property of the Trust as anentirety or substantially as an entirety, and the commencement of winding-upthe affairs of 

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the Trust.  Meetings of Unitholders will be called andheld annually for, among other things, the election of the Trust’s nominees tothe 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, theTrustee.

A meeting of Unitholdersmay be convened at any time and for any purpose by the Trustee and must beconvened, except in certain circumstances, if requisitioned by the holders ofnot less than 20% of the Units then outstanding by a written requisition.  A requisition must, among other things, statein reasonable detail the business proposed to be transacted at the meeting.

Unitholders may attendand vote at all meetings of Unitholders either in person or by proxy and aproxyholder need not be a Unitholder. Two persons present in person or represented by proxy and representingin the aggregate at least 5% of the votes attaching to all outstanding Unitsshall constitute a quorum for the transaction of business at all suchmeetings.  The holders of any issuedSpecial Voting Units who are present at the meeting shall be regarded asrepresenting outstanding Units for the purposes of determining such quorum.

The Trust Indenturecontains provisions as to the notice required and other procedures with respectto the calling and holding of meetings of Unitholders in accordance with therequirements of applicable laws.

**TheTrustee**

Computershare TrustCompany of Canada is the trustee of the Trust (the “**Trustee**”).  TheTrustee is responsible for, among other things: (a) accepting subscriptions forUnits and issuing Units pursuant thereto; (b) maintaining the books and recordsof the Trust and providing timely reports to holders of Units; and (c) payingcash distributions to Unitholders.  TheTrust Indenture provides that the Trustee shall exercise its powers and carryout its functions thereunder as Trustee honestly, in good faith and in the bestinterests of the Trust and the Unitholders and, in connection therewith, shallexercise that degree of care, diligence and skill that a reasonably prudenttrustee would exercise in comparable circumstances.

The initial term of theTrustee’s appointment is until the second annual meeting of Unitholders.  The Unitholders shall, at the second annualmeeting of the Unitholders, re-appoint, or appoint a successor to the Trusteefor an additional two year term, and thereafter, the Unitholders shallreappoint or appoint a successor to the Trustee at the annual meeting ofUnitholders two years following the reappointment or appointment of thesuccessor to the Trustee.  The Trusteemay resign on giving not less than 60 days’ notice in writing to Canetic .  The Trustee may also be removed by SpecialResolution of the Unitholders.  Suchresignation or removal shall not become effective until (a) the appointment of,and acceptance of such appointment by, a new Trustee in the place of theresigning Trustee or the Trustee to be removed, and (b) a legal and validassumption by the new Trustee of all obligations of the Trustee related theretoin the same capacities as the resigning Trustee or the Trustee to be removed.

**Delegationof Authority, Administration and Trust Governance**

The Board of Directorshas been generally delegated the significant management decisions of the Trustand Canetic has been retained to administer the Trust on behalf of theTrustee.  In particular, the Trustee hasdelegated to Canetic responsibility for any and all matters relating to:(a) the redemption of Units; (b) the making of investments by theTrust and the negotiation of management agreements respecting such investments;(c) any offering of securities of the Trust including: (i) thelisting 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 fromany governmental or regulatory authority or the taking of any other step underfederal or provincial law to enable securities which a Unitholder is entitledto receive to be properly and legally delivered and thereafter traded;(iii) ensuring compliance with all applicable laws; (iv) all mattersrelating to the content of any prospectus, information memorandum, privateplacement memorandum and similar public or private securities offeringdocuments, and the certification thereof; (v) all matters concerning theterms of the sale or issuance of Units or rights to Units; (d) thedetermination of any record date for distributions; and (e) thedetermination of any borrowing or granting of security under the TrustIndenture.

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**Boardof Directors**

Canetic currently has aboard of directors consisting of eight****individuals.  Unitholders are entitled to elect the boardof directors of Canetic.  See also “*Additional Information Respecting Canetic ResourcesInc.*”.

**DecisionMaking**

The Board ofDirectors 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, theTrustee has delegated certain matters to the Board of Directors including alldecisions relating to: (i) issuance of additional Units; and (ii) thedetermination of the amounts payable from time to time to Unitholders.

**Liabilityof the Trustee**

The Trustee, itsdirectors, officers, employees, shareholders and agents shall not be liable toany Unitholder or any other person, in tort, contract or otherwise, inconnection with any matter pertaining to the Trust or the Trust Fund (asdefined in the Trust Indenture), arising from the exercise by the Trustee ofany powers, authorities or discretion conferred under the Trust Indenture, including,without limitation, entering into the Administration Agreement and relying onCanetic thereunder, any action taken or not taken in good faith in reliance onany documents that are, prima facie, properly executed, any depreciation of, orloss to, the Trust Fund incurred by reason of the sale of any asset, anyinaccuracy 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 otheraction or failure to act (including failure to compel in any way any formertrustee to redress any breach of trust or any failure by Canetic to perform itsduties under or delegated to it under the Trust Indenture or any othercontract), including anything done or permitted to be done pursuant to, or anyerror or omission relating to, the rights, powers, responsibilities and dutiesconferred upon, granted, allocated and delegated to Canetic under the TrustIndenture or under the Administration Agreement, or the act of agreeing to theconferring upon, granting, allocating and delegating any such rights, powers,responsibilities and duties to Canetic in accordance with the terms of theTrust Indenture or under the Administration Agreement, unless such liabilitiesarise out of the negligence, wilful default or fraud of the Trustee or any ofits directors, officers, employees, shareholders, or agents.  If the Trustee has retained an appropriateexpert or adviser or legal counsel with respect to any matter connected withits duties under the Trust Indenture or any other contract, the Trustee may actor refuse to act based on the advice of such expert, adviser or legal counsel,and notwithstanding any other provision of the Trust Indenture, the Trusteeshall not be liable for and shall be fully protected from any loss or liabilityoccasioned by any action or refusal to act based on the advice of any suchexpert, adviser or legal counsel.  In theexercise of the powers, authorities or discretion conferred upon the Trusteeunder the Trust Indenture, the Trustee is and shall be conclusively deemed tobe acting as Trustee of the assets of the Trust and shall not be subject to anypersonal liability for any debts, liabilities, obligations, claims, demands,judgments, costs, charges or expenses against or with respect to the Trust orthe Trust Fund.

**Amendmentsto the Trust Indenture**

The Trust Indenture maybe amended or altered from time to time by Special Resolution.  The Trustee may, without the approval of theUnitholders, make certain amendments to the Trust Indenture, includingamendments for the purpose of: (a) ensuring the Trust’s continuingcompliance with applicable laws or requirements of any governmental agency orauthority of Canada or of any province; (b) ensuring that the Trust willsatisfy the provisions of each of subsections 108(2) and 132(6) of the Tax Actas from time to time amended or replaced; (c) ensuring that suchadditional protection is provided for the interests of Unitholders as theTrustee may consider expedient; (d) amending, modifying or changing anyprovisions of the Trust Indenture that are necessary or desirable in the opinionof Canetic as a result of amendments to the Tax Act, the regulations thereunderor the interpretation thereof including, without limitation, amendments orchanges relating to eligibility for investment and the requirements to maintainthe Trust’s status as a “unit trust” and a “mutual fund trust” for purposes ofthe Tax Act; (e) removing or curing any conflicts or inconsistenciesbetween the provisions of the Trust Indenture or any supplemental indenture,the Administration Agreement and any other agreement of the Trust or anyoffering document pursuant to which securities of the Trust are issued withrespect 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 ofthe Unitholders are not prejudiced thereby; (f) providing for, or 

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amending the provisionsof the Trust Indenture for, the electronic delivery by the Trust to Unitholdersof documents relating to the Trust (including annual and quarterly reports,including financial statements, notices of Unitholder meetings and informationcirculars and proxy related materials) at such time as applicable securitieslaws have been amended to permit such electronic delivery in place of normaldelivery procedures, provided that such amendments to the Trust Indenture arenot contrary to or do not conflict with such laws; (g) curing, correctingor rectifying any ambiguities, defective or inconsistent provisions, errors,mistakes or omissions, provided that in the opinion of the Trustee the rightsof the Trustee and of the Unitholders are not prejudiced thereby;(h) making any modification in the form of unit certificates to conformwith the provisions of the Trust Indenture, or any other modifications,provided the rights of the Trustee and of the Unitholders are not prejudicedthereby; and (i) changing the **situs**of the Trust or the governing laws of the Trust, which, in the opinion of theTrustee, are, necessary or desirable in order to provide Unitholders with thebenefit of any legislation limiting their liability.

**Take-overBids**

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

**Terminationof the Trust**

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

Unless the Trust isterminated or extended by vote of the Unitholders earlier, the Trustee shallcommence 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 onetransaction or in a series of transactions at public or private sale and do allother acts appropriate to liquidate the trust assets, and shall in all respectsact in accordance with the directions, if any, of the Unitholders in respect oftermination authorized pursuant to the Special Resolution authorizing thetermination of the Trust.  In no eventshall 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 anyinterest in the trust assets.  Afterpaying, retiring or discharging or making provision for the payment, retirementor discharge of all known liabilities and obligations of the Trust andproviding for indemnity against any other outstanding liabilities andobligations, the Trustee shall distribute the remaining part of the proceeds ofthe sale of the trust assets among the Unitholders in accordance with their prorata share.

**Reportingto Unitholders**

The financial statementsof the Trust are audited annually by an independent recognized firm ofchartered accountants.  The auditedfinancial statements of the Trust, together with the report of such charteredaccountants, will be mailed by the Trustee to Unitholders and the unauditedinterim financial statements of the Trust will be mailed to Unitholders withinthe periods prescribed by securities legislation.  The year-end of the Trust isDecember 31.

The Trust is subject tothe continuous disclosure obligations of applicable securities legislation.

**Managementof the Trust**

Pursuant to theprovisions of the Administration Agreement, Canetic provides certainmanagement, administrative and support services to the Trust, including thosenecessary: (a) to ensure compliance by the Trust with continuousdisclosure obligations under applicable securities legislation; (b) toprovide investor relations services; (c) to provide or cause to beprovided to Unitholders all information to which Unitholders are entitled tounder the Trust Indenture; (d) to call, hold and distribute materialsincluding notices of meetings and information circulars in respect of allnecessary meetings of Unitholders; (e) to determine the amounts payablefrom time to time to Unitholders; and (f) to 

45

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determine the timing and terms of future offerings of Units, ifany.  The Board of Directors is requiredto approve all matters referred to in items (d), (e) and (f) above.

 

**ADDITIONAL INFORMATION RESPECTING CANETIC RESOURCES INC.**

**Managementof Canetic**

The name,municipality of residence, principal occupation for the prior five years andposition, of each of the persons who is a director or officer of Canetic is asfollows:
| **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 Energy Ltd., also a predecessor of Canetic. Mr. Brawn has 48 years  experience in the oil and gas industry. He is also a Director of Black  Diamond Income Trust; Parkland Income Trust; the Calgary Airport Authority;  Zapata Energy Corporation, 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.                                                                                                                                                                                   |
|                                                               |       |                                            |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| 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 of GLJ Petroleum Consultants Ltd.  (formerly 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., MGM Energy  Corp., Nexstar Energy Ltd. (public oil and gas companies), Zed-I Inc. and  Globel Direct, Inc.                                                                                       |
|                                                               |       |                                            |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| 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 33 years of experience in the oil and gas  industry.                                                                                   |

 

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| 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, ICD.D (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. Mr. Lee is also a Director of Darian Resources  Ltd., Gryphon Petroleum Corp. and Alaris Income Growth Trust (private oil and  gas companies). |
|                                                                |   |                                                |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             |
| R. Gregory Rich  BSc (Engr), MBA (3)(4)  Houston, Texas             |   | Director                                            |   | A Principal of Blackrock Energy Associates (an  energy consulting and investment 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 35 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                         |   | Chief Operating Officer                             |   | Chief Operating Officer of Canetic since August 30,  2006 and prior thereto 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).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             |

 

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|                                      |   |                                                          |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
|-------------------------------------------|--------|---------------------------------------------------------------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| Brian D. Evans  BA, LLB  Calgary, Alberta |   | Vice President, General Counsel & Secretary               |   | Vice President, General Counsel and Secretary 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 2000.                      |
|                                      |   |                                                          |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
| 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.                                                                        |
|                                      |   |                                                          |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
| Brian Keller  Calgary, Alberta            |   | Vice President, Exploitation                                  |   | Vice President of Exploitation of Canetic since  November 2006. Director of Geology and Geophysics of AEI from January 2002 to  November 2006 and prior thereto Senior Geologist of AEI from November, 2002  to July, 2006. Before joining AEI, Brian was Operations Manager for MarkWest  Resources Canada Corp. from 2001 to 2002 and its predecessor Leland Energy  Ltd from 2000 to 2001.                                                                                                          |

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**Note:**

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

(2)                                  Memberof the Reserves Committee (Daryl Gilbert, Chair).

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

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

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

(6)                                  Mr.Gilbert is a director of Globel Direct, Inc., which was subject to a ceasetrade order issued by the British Columbia Securities Commission on November20, 2002 and the Alberta Securities Commission on November 22, 2002 for delayin filing financial statements.  Therequired financial statements were filed and the cease trade orders wererevoked effective December 23, 2002.

As at March 22, 2007, number of Units beneficiallyowned, directly or indirectly, by all of the directors and officers of Caneticis approximately 1,867,388 million Units (approximately 0.82% of the issued andoutstanding Units).

**ShareCapital of Canetic**

The authorized capital ofCanetic consists of an unlimited number of common shares, an unlimited numberof non-voting common shares and an unlimited number of exchangeableshares, issuable in series.

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The following is ageneral description of the material rights, privileges, restrictions andconditions attaching to each class of shares.

*CommonShares*

Each common share ofCanetic entitles its holder to receive notice of and to attend all meetings ofshareholders of Canetic and to one vote at such meetings.  The holders of common shares of Canetic are,at the discretion of the Board of Directors and subject to the rights ofholders of the exchangeable shares and applicable legal restrictions, entitledto receive any dividends or other distributions declared by the Board ofDirectors on the common shares of Canetic. The holders of common shares of Canetic are, subject to the rights ofholders of the exchangeable shares, entitled to share equally in anydistribution of the assets of Canetic upon the liquidation, dissolution orwinding-up of Canetic or other distribution of its assets among itsshareholders for the purpose of winding-up its affairs.  All of the issued and outstanding commonshares of Canetic are owned by the Trust.

*Non-votingCommon Shares*

The non-votingcommon shares of Canetic have the same rights, privileges, restrictions andconditions as the common shares of Canetic, with the exception that holdersthereof are not entitled to notice of or to vote at meetings of shareholders ofCanetic (except where required by applicable law).  Dividends may be declared on either the commonshares of Canetic or the non-voting common shares of Canetic to theexclusion of the other.  No non-votingcommon shares have been issued.

*ExchangeableShares*

The exchangeable shareshave a priority over all common shares and non-voting common shares withrespect 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 andparticular rights, privileges, restrictions and conditions attaching to eachseries of the exchangeable shares.  Noexchangeable shares have been issued.

**AUDIT COMMITTEE INFORMATION**

The full text of theaudit committee mandate is included in Appendix C of this Annual InformationForm.

**Compositionof the Committee**

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

***Robert G. Brawn***

Mr. Brawn has a degree in Chemical Engineering from the University ofCalgary and has been employed in the oil industry for 48 years.  He has been president and or chairman ofTurbo Resources Ltd., Merland Exploration Ltd., Bankeno Mines Ltd., OMV CanadaLtd (Canadian subsidiary of the Austrian National Oil Company), Danoil EnergyLtd. and AEI (Danoil and AEI are predecessor companies to Canetic) and he ispresently Chairman of Grande Cache Coal Corporation.  All of these companies with the exception ofOMV have been Canadian listed public companies. Mr. Brawn currently serves as a director of numerous privatecorporations and the following publicly listed companies: Zapata Energy Ltd,Parkland Income Trust, Black Diamond Income Trust, the Calgary AirportAuthority and has or is currently serving on the audit committee of Zapata,Grande Cache, the Calgary Airport Authority. He is also formerly a director and was on the audit committees ofCanadian Foremost Industries (machinery manufacturer), Forzani Group Ltd.(retailer), Churchill Corporation (engineering/construction contractor) andUnited Inc. (property developer).  He hasalso been Chairman / President of the Calgary Chamber of Commerce, Van HorneInstitute (transportation policy), Calgary Economic Development Authority, IndependentPetroleum Association of Canada, Springbank Park for all Seasons and is amember of the World President’s Organization and the Alberta EconomicDevelopment Authority.

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***W. Peter Comber (AuditCommittee Chair)***

Mr. Comber holds a Bachelor of Arts degree from the University ofToronto, a Masters of Business Administration from York University and is aChartered Accountant.  Mr. Comber hasbeen engaged in various aspects of the financial services industry since 1965,first as a chartered accountant, then in corporate finance in Toronto andCalgary and then in investment management, as an investment counselor. SinceAugust 1999 Mr. Comber has been managing director of Barrantagh InvestmentManagement Inc., investment counselors based in Toronto, Ontario.  From May 1993 to August 1999, Mr. Comber wasthe President of Newtonhouse Investment Management Ltd., investment counselorslocated in Toronto, Ontario.  BetweenJune 1989 and December 31, 1991, Mr. Comber was Senior Vice-President ofThornmark Capital Corporation, an investment holding company, and principalofficer of Thornmark Capital Funding Corporation, merchant bank.  Prior to June 1989, Mr. Comber was SeniorVice-President and Managing Director of Prudential-Bache Securities CanadaLimited, an investment dealer in Toronto, Ontario.  Mr. Comber is a director of Nuvista EnergyLtd., and Sure Energy Inc. and serves as chairman of the audit committee foreach of the aforementioned companies. Over the course of his career, he has acquired competence in the auditand accounting issues facing public companies and considerable knowledge offinancial reporting procedures and controls**.**

***Daryl Gilbert***

Mr.Gilbert graduated from the University of Manitoba in 1973 with a Bachelor ofScience degree in Civil Engineering. Upon graduation he joined the AlbertaEnergy Resources Conservation Board where he received his training in PetroleumEngineering and related regulatory processes. In 1976 he joined Great Northern Oil Ltd. where he managed various oiland gas exploitation projects.  Mr.Gilbert entered the field of independent consulting in 1979 when he joined thepredecessor oil and gas engineering and geological firm which became GilbertLaustsen Jung Associates Ltd. He became a Principal Officer of the firm in 1988and was appointed President and Chief Executive Officer in 1994 and served inboth capacities until his retirement in early 2005.  The firm provided professional services tothe Canadian and International oil and gas industry including detailed reservoirand economic analyses, project and corporate evaluations, fair market valueappraisals, merger and acquisition advice and expert witness testimony.  Mr. Gilbert currently serves as a Director ofAltaGas Income Trust, Kereco Energy Ltd., MGM Energy Corp., Nexstar EnergyLtd., Zed-I Inc. and Globel Direct Inc. as well as several privatecompanies.  Mr. Gilbert is currently amember of the Association of Petroleum Engineers, Geologists and Geophysicistsof Alberta, the Canadian Institute of Mining and Metallurgy and the Society ofPetroleum Evaluation Engineers.

***Jack C. Lee***

Mr. Lee, Chairman of Canetic, holds a Bachelor of Arts and a Bachelorof Commerce degree from the University of Saskatchewan.  Mr. Lee, has been a director of Canetic sinceits formation in November 2005.  He was adirector, President and CEO of AEI (a predecessor company of Canetic) fromApril 2001 until October 2002.  He servedas AEI’s Chairman from May 2003 until January 2006.  He was a director, President and CEO ofDanoil Energy Ltd., predecessor to Acclaim from 1997 until 2001.  He was a director, Chairman and CEO ofIndependent Energy Inc. from 1992 until 1996. He was a shareholder and Vice President of Sprott Securities Ltd. from1993 to 1995.  He was a director,President/CEO of Gane Energy Corporation, predecessor to Northstar EnergyCorporation from 1980 to 1986.

**Pre-ApprovalPolicies and Procedures**

Canetichas adopted procedures with respect to the pre-approval of audit and permittednon-audit services to be provided by Deloitte & Touche LLP.  All audit and non-audit services must beapproved in advance by the audit committee of the Board of Directors in thefollowing manner.  The audit committee inconsultation with Deloitte & Touche LLP has established a budget for theprovision of a specified list of audit and permitted non-audit services thatthe audit committee believes to be typical, recurring or otherwise likely to beprovided by Deloitte & Touche LLP. The budget generally covers the period between the adoption of the budgetand the next meeting of the audit committee, but at the option of the auditcommittee it may cover a longer or shorter period.  The list of services is sufficiently detailedas to the particular services to be provided to ensure that (i) the audit committeeknows precisely what services it is being asked to pre-approve and (ii) it isnot necessary for any member of management to make a judgment as to whether aproposed service fits within the pre-approved services.

 

50

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** **

**ExternalAuditor Service Fees**

The followingtable provides information about the fees billed to the Trust and to Acclaim (apredecessor of the Trust) for professional services rendered by Deloitte &Touche LLP during fiscal 2006 and 2005, respectively:

|                        | ** ** | **2006** | ** ** | **2005** | ** ** |
|------------------------|------------|----------|------------|----------|------------|
|                   |       |     |       |     |       |
| Audit Fees(1)          |       | $        | 497,140    |     | $          | 200,000 |   |
| Audit-Related  Fees(2) |       | $        | 418,442    |     | $          | 314,000 |   |
| Tax Fees(3)            |       | $        | 18,675     |     | $          | 205,550 |   |
| All Other Fees(4)      |       | $        | 247,611    |     | $          | 112,150 |   |
| Total                  |       | $        | 1,181,868  |     | $          | 831,700 |   |

----

**Notes:**

(1)                                Auditfees consist of fees for the audit of Canetic’s annual financial statements orservices that are normally provided in connection with statutory and regulatoryfilings or engagements.

(2)                                Audit-relatedfees consist of fees for assurance and related services that are reasonablyrelated to the performance of the audit or review of Canetic’s financialstatements and are not reported as Audit Fees. During fiscal 2006 and 2005, theservices provided in this category included Quarterly Reviews, ProspectusFilings, 40-F Registration Filings, Review of Internal Controls over FinancialReporting and Research of Accounting and Audit related issues.

(3)                                Taxfees in 2006 and 2005 consist of fees for tax advice and compliance pertainingto filing of Canetic’s annual tax returns.

(4)                                Allother fees in 2006 and 2005 consists of fees for property tax complianceservices.

**MARKET FOR SECURITIES**

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

The followingtable sets forth the closing price range and trading volumes of the Units asreported 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      |       | 24.49                                |       | 21.86                                      |       | 19,381 |   | 21.35 |   | 18.88 |   | 7,965 |   |
| April      |       | 25.50                                |       | 23.70                                      |       | 11,500 |   | 22.45 |   | 20.74 |   | 6,263 |   |
| May        |       | 24.43                                |       | 21.94                                      |       | 17,887 |   | 22.16 |   | 19.50 |   | 6,031 |   |
| June       |       | 24.63                                |       | 20.44                                      |       | 14,105 |   | 22.35 |   | 18.38 |   | 6,725 |   |
| July       |       | 23.80                                |       | 22.01                                      |       | 9,143 |   | 21.00 |   | 19.61 |   | 4,226 |   |
| August     |       | 23.69                                |       | 22.16                                      |       | 18,204 |   | 21.40 |   | 19.72 |   | 11,098 |   |
| September  |       | 22.98                                |       | 18.15                                      |       | 22,535 |   | 20.81 |   | 16.25 |   | 15,647 |   |
| October    |       | 20.64                                |       | 16.40                                      |       | 28,495 |   | 18.30 |   | 14.37 |   | 27,143 |   |
| November   |       | 18.00                                |       | 13.70                                      |       | 63,722 |   | 16.15 |   | 12.04 |   | 10,716 |   |
| December   |       | 16.85                                |       | 15.76                                      |       | 17,329 |   | 14.74 |   | 13.65 |   | 4,384 |   |

 

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The followingtable 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      |       | 210.54                               |       | 210.54 |   | 200 |   |
| April      |       | 224.94                               |       | 224.93 |   | 200 |   |
| May        |       | 206.36                               |       | 205.71 |   | 375 |   |
| June       |       | 201.98                               |       | 181.71 |   | 430 |   |
| July       |       | 200.05                               |       | 195.40 |   | 120 |   |
| August     |       | 202.00                               |       | 196.22 |   | 540 |   |
| September  |       | —                               |       | — |   | — |   |
| October    |       | 180.00                               |       | 163.00 |   | 900 |   |
| November   |       | —                               |       | — |   | — |   |
| December   |       | 145.46                               |       | 144.20 |   | 980 |   |

 

The following table setsforth 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      |       | 155.00                               |       | 143.00 |   | 5,020 |   |
| April      |       | 160.00                               |       | 150.00 |   | 1,740 |   |
| May        |       | 155.00                               |       | 145.11 |   | 4,740 |   |
| June       |       | 155.00                               |       | 132.25 |   | 4,120 |   |
| July       |       | 145.00                               |       | 141.31 |   | 1,710 |   |
| August     |       | 151.04                               |       | 141.73 |   | 4,460 |   |
| September  |       | 147.00                               |       | 117.08 |   | 1,330 |   |
| October    |       | 130.00                               |       | 119.00 |   | 1,390 |   |
| November   |       | 112.53                               |       | 106.82 |   | 1,530 |   |
| December   |       | 107.27                               |       | 106.00 |   | 1,120 |   |

The following table sets forth the closing price rangeand trading volumes of the 6.5% Debentures (CNE.DB.B) as reported by the TSXfor 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      |       | 129.00                               |       | 114.87 |   | 13,360 |   |
| April      |       | 133.00                               |       | 124.70 |   | 11,600 |   |
| May        |       | 125.50                               |       | 116.00 |   | 6,250 |   |
| June       |       | 129.07                               |       | 108.85 |   | 14,276 |   |
| July       |       | 124.50                               |       | 116.67 |   | 7,420 |   |
| August     |       | 124.75                               |       | 116.99 |   | 12,485 |   |
| September  |       | 120.36                               |       | 105.03 |   | 4,590 |   |
| October    |       | 109.25                               |       | 103.83 |   | 4,970 |   |
| November   |       | 105.50                               |       | 100.10 |   | 7,810 |   |
| December   |       | 102.00                               |       | 100.50 |   | 3,540 |   |

 

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The following table setsforth 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      |       | 151.00                               |       | 137.22 |   | 1,610 |   |
| April      |       | 154.50                               |       | 146.24 |   | 2,380 |   |
| May        |       | 150.00                               |       | 140.00 |   | 2,170 |   |
| June       |       | 151.00                               |       | 128.32 |   | 2,620 |   |
| July       |       | 145.00                               |       | 140.00 |   | 2,310 |   |
| August     |       | 145.50                               |       | 130.00 |   | 2,060 |   |
| September  |       | —                               |       | — |   | — |   |
| October    |       | 115.72                               |       | 113.06 |   | 500 |   |
| November   |       | 115.00                               |       | 104.22 |   | 1,600 |   |
| December   |       | 110.00                               |       | 104.33 |   | 650 |   |

The following table sets forth the closing price rangeand trading volumes of the 6.5% Canetic Debentures (CNE.DB.E) as reported bythe TSX for the periods indicated.
|            | ** ** | **Toronto Stock Exchange** | ** ** |
|------------|------------|--------------------------------------|------------|
| **Period** | ** ** | **High (C$)**                   | ** ** | **Low (C$)** | ** ** | **Volume (000’s)** | ** ** |
| ** ** |       |                                 |       |   |   |   |   |
| **2006**   |       |                                 |       |   |   |   |   |
|       |       |                                 |       |   |   |   |   |
| August     |       | 100.89                               |       | 100.15 |   | 389,890 |   |
| September  |       | 100.50                               |       | 99.05 |   | 259,090 |   |
| October    |       | 100.50                               |       | 99.50 |   | 110,800 |   |
| November   |       | 99.50                                |       | 93.00 |   | 122,300 |   |
| December   |       | 97.89                                |       | 96.00 |   | 51,530 |   |

**DISTRIBUTIONS**

**Policy**

The Trust makes cashdistributions in amounts equal to the interest, dividend and other income ofthe Trust, net of the Trust’s administrative expenses.  In addition, Unitholders may, at thediscretion of the Board of Directors, receive distributions in respect ofrepayments of principal made by Canetic to the Trust on the Canetic Notes.  Canetic retains a portion of its funds flowfrom operations over time to fund capital expenditures and distributes thebalance to the Trust.  The actualpercentage retained by Canetic is subject to the discretion of the Board ofDirectors and will vary from month to month depending on, among other things,the current and anticipated commodity price environment.  Canetic’s credit facilities and otheragreements with lenders may limit its ability to pay distributions.  See also “*Risk Factors*”.

Cash distributions aremade on or about the 15th day of each month to Unitholders of record on theimmediately preceding distribution record date. The Trust’s current policy is to distribute $0.19 per Unit per month($2.28 per Unit per annum).

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**DistributionRecord**

The followingtable sets forth the per Unit amount of monthly cash distributions paid by theTrust since the completion of the Arrangement. 
|            | ** ** | **Distribution Per Unit**(1)     | ** ** |
|------------|------------|----------------------------------|------------|
| **2007**   | ** ** | ** **                       | ** ** |
| ** ** | ** ** | ** **                       | ** ** |
| January    |       | $0.19                            |       |
| February   |       | $0.19                            |       |
| March      |       |     $0.19(2) |       |
|       |       |                             |       |
| **2006**   |       |                             |       |
|       |       |                             |       |
| January    |       | $0.23                            |       |
| February   |       | $0.23                            |       |
| March      |       | $0.23                            |       |
| April      |       | $0.23                            |       |
| May        |       | $0.23                            |       |
| June       |       | $0.23                            |       |
| July       |       | $0.23                            |       |
| August     |       | $0.23                            |       |
| September  |       | $0.23                            |       |
| October    |       | $0.23                            |       |
| November   |       | $0.23                            |       |
| December   |       | $0.23                            |       |

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**Notes:**

(1)                                  Monthlyinformation refers to the month in which the record date for the relevantdistribution occurs, with the distribution being paid in the following month.

(2)                                  TheTrust announced on March 16, 2007 that the next monthly distribution of $0.19per Unit will be paid on April 13, 2007 to Unitholders of record on March 31,2007.

**RISKFACTORS**

**Thefollowing is a summary of certain risk factors relating to the business of theTrust and the Operating Entities.  Thefollowing information is a summary only of certain risk factors and isqualified in its entirety by reference to, and must be read in conjunctionwith, the detailed information appearing elsewhere in this Annual InformationForm.  Unitholders and potentialUnitholders should consider carefully the information contained herein and, inparticular, the following risk factors.**

**Being a limited purposetrust makes the Trust largely dependent upon the operations and assets of theOperating Entities.  If the oil andnatural gas reserves associated with the Operating Entities’ resourceproperties are not supplemented through additional development or theacquisition of oil and natural gas properties, the ability of the OperatingEntities to continue to generate funds flow from operations for distribution toUnitholders may be adversely affected.**

The Trust is alimited purpose trust that is entirely dependent upon the operations and assetsof the Operating Entities through its ownership, directly and indirectly, ofsecurities of the Operating Entities including the common shares of Canetic,the Canetic Notes and the Canetic NPIs. Accordingly, the Trust and its ability to pay cash distributions toUnitholders are dependent upon the ability of the Operating Entities to meettheir interest, principal, dividend and other distribution obligations on thesecurities of the Operating Entities and the Canetic NPIs.  The Operating Entities’ income is receivedfrom the production of oil and natural gas from the Operating Entities’Canadian resource properties and is susceptible to the risks and uncertaintiesassociated with the oil and natural gas industry generally.  If the oil and natural gas reservesassociated with the Operating Entities’ resource properties are notsupplemented through additional development or the acquisition of additionaloil and natural gas properties, the ability of the Operating Entities to meettheir obligations to the trust and its ability to pay distributions toUnitholders may be adversely affected.

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**TheTrust may not be able to achieve the anticipated benefits of acquisitions andthe integration of acquisitions may result in the loss of key employees and thedisruption of ongoing business relationships.**

The Trust and itspredecessors, Acclaim and StarPoint, have completed a number of acquisitionsand the Trust anticipates making additional acquisitions in the future tostrengthen its position in the oil and natural gas industry and to create theopportunity to realize certain benefits. Achieving the benefits of completed and future acquisitions depends inpart on successfully consolidating functions and integrating operations,procedures and personnel in a timely and efficient manner, as well as the Trust’sability to realize the anticipated growth opportunities and synergies fromcombining the acquired businesses and operations with those of the Trust.  The integration of acquired businessesrequires the dedication of substantial management effort, time and resources,which may divert management’s focus, and resources from other strategicopportunities and from operational matters. The integration process may result in the loss of key employees and thedisruption of ongoing business, supplier, customer and employee relationshipsthat may adversely affect the Trust’s ability to achieve the anticipatedbenefits of past and future acquisitions.

**Incorrectassessments of value at the time of acquisitions could adversely affect thevalue of the Units and distributions to Unitholders.**

Acquisitions ofoil and gas properties or companies will be based in large part on engineeringand economic assessments made by independent engineers.  These assessments include a series ofassumptions regarding such factors as recoverability and marketability of oiland gas, future prices of oil and gas and operating costs, future capitalexpenditures and royalties and other government levies which will be imposedover the producing life of the reserves. Many of these factors are subject to change and are beyond the controlof the Trust.  All such assessmentsinvolve a measure of geological and engineering uncertainty which could resultin lower production and reserves than anticipated.

**TheOperating Entities are subject to risks in connection with the exploitation anddevelopment of oil and gas properties.**

Exploitation anddevelopment risks are due to the uncertain results of searching for andproducing oil and natural gas using imperfect scientific methods.  Canetic seeks to mitigate these risks byusing experienced staff, focusing exploitation efforts in areas in which theOperating Entities have existing knowledge and expertise or access to suchexpertise, using up-to-date technology to enhance methods and controlling coststo maximize returns.

**Actualreserves will vary from reserve estimates, and those variations could bematerial, and negatively affect the market price of the Units and distributionsto Unitholders.**

The reserve and recovery information contained in theCanetic Trust Engineering Report are only estimates and the actual productionand ultimate reserves from the properties may be greater or less than the estimatesprepared.  In addition, probable reserveestimates for properties may require revision based on the actual developmentstrategies employed to prove such reserves. Estimated reserves may also be affected by changes in oil and naturalgas prices.  Declines in the reserves ofthe Operating Entities that are not offset by the acquisition or development ofadditional reserves may reduce the underlying value of the Units.

**Volatilityin oil and natural gas prices could have a material adverse effect on resultsof operations and financial condition, which, in turn, could negatively affectthe amount of distributions to Unitholders.**

The price of oiland natural gas will fluctuate throughout the life of the Operating Entities’reserves and price and demand are factors largely beyond their control. Suchfluctuations will have a positive or negative effect on the revenue to bereceived. Such fluctuations will also have an effect on the acquisition costsof any future oil and natural gas properties that the Operating Entities mayaquire. As well, cash distributions to Unitholders are highly sensitive to theprevailing price of crude oil and natural gas.

Oil and naturalgas prices have fluctuated widely during recent years and are subject tofluctuations in response to relatively minor changes in supply, demand, marketuncertainty and other factors that are beyond Canetic’s control

 

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 These factors include, but are not limited to,worldwide political instability, foreign supply of oil and natural gas, thelevel of consumer product demand, government regulations and taxes, the priceand availability of alternative fuels and the overall economic environment.

Canetic usesfinancial derivative instruments and other hedging mechanisms to try to limit aportion of the adverse effects resulting from changes in natural gas and oilcommodity prices.  In hedging Canetic’scommodity price exposure, it attempts whenever practicable to use financialinstruments that protect it against downward price movements while stillproviding some variable level of participation in the event that pricesincrease.  To the extent it hedges itscommodity price exposure, Canetic recognizes that depending on the type ofstructure used, it may forego some or all of the benefit that it would havereceived if commodity prices increase. Canetic recognizes that this potential opportunity cost is a trade-offfor limiting its exposure to downward price movements.  In addition to the potential of experiencingan opportunity cost, other potential costs or losses associated with hedgingcould include situations where the other party to a hedge does not perform itsobligations under the hedge agreement, the hedge is imperfect or Canetic’shedging policies and procedures are not followed.  Furthermore, Canetic cannot guarantee thatsuch hedging transactions will fully offset the risk of changes in commodityprices.  Canetic’s commodity hedgingactivities could expose it to losses. Such losses could occur under various circumstances.

In addition,Canetic regularly assesses the carrying value of its assets in accordance withCanadian GAAP under the full cost method. If oil and natural gas prices become depressed or decline, the carryingvalue of Canetic’s assets could be subject to downward revision.

**Adecline in the Operating Entities’ ability to market their oil and natural gasproduction could have a material adverse effect on production levels or on theprice received for production, which, in turn, could reduce distributions toUnitholders and affect the market price of the Units.**

The marketabilityand price of oil and natural gas that may be acquired or discovered by theOperating Entities will be affected by numerous factors beyond theircontrol.  These factors include demandfor oil and natural gas, market fluctuations, the proximity and capacity of oiland 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.

**Distributionsmay be reduced during periods in which the Operating Entities make capitalexpenditures using funds flow from operations, which could also negativelyaffect the market price of the Units.**

Production anddevelopment costs incurred with respect to properties, including power costsand the costs of injection fluids associated with tertiary recovery operations,reduce the royalty income that the Trust receives and, consequently, theamounts the Trust can distribute to its Unitholders.

The timing andamount of capital expenditures directly affect the amount of income fordistribution to Unitholders. Distributions may be reduced, or even eliminated, at times whensignificant capital or other expenditures are made.  To the extent that external sources ofcapital, including the issuance of additional Units, become limited orunavailable, the Operating Entities’ ability to make the necessary capitalinvestments to maintain or expand oil and gas reserves and to invest in assets,as the case may be, will be impaired.  Tothe extent that the Operating Entities are required to use funds flow fromoperations to finance capital expenditures or property acquisitions, the cashthe Trust receives from the Operating Entities will be reduced, resulting inreductions to the amount of cash it is able to distribute to its Unitholders.

**Theindustry in which the Operating Entities operate exposes the Operating Entitiesto potential liabilities that may not be covered by insurance.**

The operation ofoil and gas wells involves a number of operating and natural hazards, which mayresult in blowouts, environmental damage and other unexpected or dangerousconditions resulting in damage to the Operating Entities and possible liabilityto third parties.  The Operating Entitiesmaintain liability insurance, where available, in amounts consistent withindustry standards.  Businessinterruption insurance may also be purchased for selected facilities, to theextent that such insurance is available. The Operating Entities may become liable for damages arising from such 

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events againstwhich they cannot insure or against which they may elect not to insure becauseof high premium costs or other reasons. Costs incurred to repair such damage or pay such liabilities will havean adverse effect on the Trust’s financial condition and therefore on thedistributable income to be distributed to holders of Units.

**Theoperation of a significant portion of the properties of the Operating Entitiesis largely dependent on the ability of third party operators, and harm to theirbusiness could cause delays and additional expenses in the Trust receivingrevenues, which could negatively affect the market price of the Units anddistributions to Unitholders.**

Continuingproduction from a property, and to some extent the marketing of productiontherefrom, are largely dependent upon the abilities of the operator of theproperty.  To the extent the operatorfails to perform these functions properly, revenue may be reduced.  Payments from production generally flowthrough the operator and there is a risk of delay and additional expense inreceiving such revenues if the operator becomes insolvent.  To the extent the Operating Entities are notthe operators of their oil and natural gas properties, the Operating Entitieswill be dependent on such operators for the timing of activities related tosuch properties and will be largely unable to direct or control the activitiesof those operators.

The operation ofthe wells located on properties not operated by Canetic or one of the OperatingEntities are generally governed by operating agreements which typically requirethe operator to conduct operations in a good and workmanlike manner.  Operating agreements generally provide,however, that the operator will have no liability to the other non-operatingworking interest owners for losses sustained or liabilities incurred, exceptsuch as may result from gross negligence or wilful misconduct.  In addition, third-party operators aregenerally not fiduciaries with respect to the Operating Entities, the Trust orthe Unitholders.  The Operating Entities,as owners of working interests in properties not operated by them, willgenerally have a cause of action for damages arising from a breach of theoperator’s duty.  Although notestablished by definitive legal precedent, it is unlikely that the Trust or itsUnitholders would be entitled to bring suit against third-party operators toenforce the terms of the operating agreements. Therefore, Unitholders will be dependent upon the Operating Entities, asowners of the working interest, to enforce such rights.

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

Higher operatingcosts for the Operating Entities’ properties will directly decrease the amountof funds flow from operations received by the Trust and, therefore, may reducedistributions to Unitholders. Electricity, chemicals, supplies, reclamation and abandonment and labourcosts are a few of the operating costs that are susceptible to materialfluctuation.

The level ofproduction from the Operating Entities’ existing properties may decline atrates greater than anticipated due to unforeseen circumstances, many of whichare beyond the Operating Entities’ control. A significant decline in production could result in materially lowerrevenues and funds flow from operations and, therefore, could reduce the amountavailable for distribution to Unitholders.

**The Trust’sdistributions could be adversely affected by unforeseen title defects, whichcould reduce distributions to Unitholders.**

Although titlereviews are generally conducted in accordance with industry standards, suchreviews do not guarantee or certify that a defect in the chain of title may notarise to defeat the claim of an Operating Entity to certain properties.  A reduction of distributable income couldresult in such circumstances.  Similarly,the economic impact on us of claims of aboriginal title is unknown.  Aboriginal people have claimed aboriginaltitle and rights to a substantial portion of western Canada.  The Trust is unable to assess the effect, ifany, that any such claim would have on the Operating Entities’ business andoperations.

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**Changesin Canadian income tax legislation, or if the Trust ceases to qualify as amutual fund trust it would adversely affect the value of the Units.**

There can be no assurance that Canadian federal incometax laws and administrative policies respecting the treatment of mutual fundtrusts will not be changed in a manner that adversely affects the holders ofUnits.  If the Trust ceases to qualify asa “mutual fund trust” under the Tax Act, certain adverse tax consequences mayarise for the Trust and Unitholders.

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

If the Trustceases to qualify as a mutual fund trust, the Units will cease to be qualifiedinvestments for Registered Retirement Savings Plans (“**RRSPs**”), Registered Retirement Income Funds (“**RRIFs**”), Deferred Profit Sharing Plans (“**DPSPs**”) and Registered Education Savings Plans (“**RESPs**”) (collectively, “**Deferred Plans**”).  Where at the end of any month a Deferred Planholds Units that were qualified investments at the time of acquisition, butsubsequently 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 bythe Deferred Plan.  In addition, where atrust governed by an RRSP or RRIF holds Units that are not qualifiedinvestments, the trust will become taxable on its income attributable to theUnits while they are not qualified investments, including the full amount ofany capital gain realized on a disposition of Units while they are notqualified investments.  Where a trustgoverned by an RESP holds Units that are not qualified investments, the plan’sregistration may be revoked.  If an RESP’sregistration is revoked, it will become subject to tax under Part I on itstaxable income.  If, however, an RESPholds property that is not a qualified investment and the registration of theRESP is not revoked, Part XI.1 tax will apply, as described above.  In addition, if the Trust were to cease toqualify as a mutual fund trust:

The Trust would betaxed on certain types of income distributed to Unitholders, including incomegenerated by the royalties and the net profits interests held by theTrust.  Payment of this tax may haveadverse consequences for some Unitholders, particularly Unitholders that arenot residents of Canada and residents of Canada that are otherwise exempt fromCanadian income tax.

Units held byUnitholders that are not residents of Canada would become taxable Canadianproperty.  Consequently, non-residentholders would be subject to Canadian income tax on any gains realized on adisposition of Units held by them.

**October31 Proposals**

**The October 31 Proposals would beexpected to result in adverse tax consequences to the Trust and certainUnitholders and may adversely impact cash distributions from the Trust andreduce the value of the Units.**

The October 31Proposals propose to apply a tax at the trust level on distributions of certainincome from publicly traded mutual fund trusts at rates of tax comparable tothe combined federal and provincial corporate tax and to treat suchdistributions as dividends to the unitholders. Existing trusts will have a four-year transition period and, subject tothe qualification below, will not be subject to the new rules until 2011.  However, assuming the October 31 Proposalsare ultimately enacted in the form currently proposed, the implementation ofsuch proposals would be expected to result in adverse tax consequences to theTrust and certain Unitholders (including most particularly Unitholders that aretax exempt or non-residents of Canada) and may impact cash distributions fromthe Trust.

In light of theforegoing, the October 31 Proposals may reduce the value of the Units, whichwould be expected to increase the cost to the Trust of raising capital in thepublic capital markets.  In addition, theOctober 31 Proposals are expected to (a) substantially eliminate thecompetitive advantage that the Trust and other Canadian energy trusts enjoyrelative to their corporate competitors in raising capital in a tax-efficientmanner, and (b) place the Trust and 

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other Canadianenergy trusts at a competitive disadvantage relative to industry competitors,including U.S. master limited partnerships, which will continue to not besubject to entity level taxation.  TheOctober 31 Proposals are also expected to make the Units less attractive as anacquisition currency.  As a result, itmay become more difficult for the Trust to compete effectively for acquisitionopportunities.  There can be no assurancethat the Trust will be able to reorganize its legal and tax structure tosubstantially mitigate the expected impact of the October 31 Proposals.

Further, theOctober 31 Proposals provide that, while there is no intention to prevent “normalgrowth” during the transitional period, any “undue expansion” could result inthe transition period being “revisited”, presumably with the loss of thebenefit to the Trust of that transitional period.  As a result, the adverse tax consequencesresulting from the proposals could be realized sooner than 2011.  On December 15, 2006, the Department ofFinance issued guidelines with respect to what is meant by “normal growth” inthis context.  Specifically, theDepartment of Finance stated that “normal growth” would include equity growthwithin certain “safe harbour” limits, measured by reference to the marketcapitalization of a specified investment flow through entity (“**SIFT**”) as of the end of trading on October31, 2006 (which would include only the market value of the SIFT’s issued andoutstanding publicly-traded trust units, and not any convertible debt, optionsor other interests convertible into or exchangeable for trust units).  Those safe harbour limits are 40% for theperiod from November 1, 2006 to December 31, 2007, and 20% each for calendar2008, 2009 and 2010.  Moreover, theselimits are cumulative, so that any unused limit for a period carries over intothe subsequent period.  Additionaldetails of the Department of Finance’s guidelines include the following:

(i)                                     new equity for these purposesincludes units and debt that is convertible into units (and may include othersubstitutes for equity if attempts are made to develop those);

(ii)                                  replacing debt that wasoutstanding as of October 31, 2006 with new equity, whether by a conversioninto trust units of convertible debentures or otherwise, will not be consideredgrowth for these purposes and will therefore not affect the safe harbour; and

(iii)                               the exchange, for trust units,of exchangeable partnership units or exchangeable shares that were outstandingon October 31, 2006 will not be considered growth for those purposes and willtherefore not affect the safe harbour where the issuance of the trust units ismade in satisfaction of the exercise of the exchange right by a person otherthan the SIFT.

The marketcapitalization of the Trust as of the close of trading on October 31, 2006, havingregard only to its issued and outstanding publicly-traded Units, wasapproximately $4.5 billion, which means the Trust’s “safe harbour” equitygrowth amount for the period ending December 31, 2007 is approximately $1.8billion, and for each of calendar 2008, 2009 and 2010 is an additionalapproximately $900 million (in any case, not including equity, includingconvertible debentures, issued to replace debt that was outstanding on October31, 2006).

While theseguidelines are such that it is unlikely they would affect the ability of theTrust to raise the capital required to maintain and grow its existingoperations in the ordinary course during the transition period, they couldadversely affect the cost of raising capital and the ability of the Trust toundertake more significant acquisitions.

It is not known atthis time when the October 31 Proposals will be enacted by Parliament orwhether the October 31 Proposals will be enacted in the form currentlyproposed.

**Theability of investors resident in the United States to enforce civil remediesmay be negatively affected for a number of reasons.**

Both the Trust andCanetic are organized under the laws of Alberta, Canada with their principalplace of business in Canada.  Most of thedirectors and all of the officers of Canetic and the representatives of theexperts who provide services to Canetic (such as its auditors and itsindependent reserve engineers), and a substantial portion of the assets of theTrust and all or a substantial portion of the assets of such persons arelocated outside the United States.  As aresult, it may be difficult for investors in the United States to effectservice of process within the United States upon such directors, officers andrepresentatives of experts who are not residents of the United States or toenforce against them judgments of United States courts based upon civilliability under the United States federal securities laws or the securitieslaws of any state within the United States. There is doubt as to the enforceability in Canada 

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against the Trustor Canetic or against any of Canetic’s directors, officers or representativesof experts who are not residents of the United States, in original actions orin actions for enforcement of judgments of United States courts of liabilitiesbased solely upon the United States federal securities laws or the securitieslaws of any state within the United States.

**Canadianand United States practices differ in reporting reserves and production and theTrust’s estimates may not be comparable to those of companies in the UnitedStates.**

The Trust reportsits production and reserve quantities in accordance with Canadian practices andspecifically in accordance with NI 51-101. These practices are different from the practices used to reportproduction and to estimate reserves in reports and other materials filed withthe SEC by companies in the United States.

The Trustincorporates additional information with respect to production and reserveswhich is either not generally included or prohibited under rules of the SEC andpractices in the United States.  TheTrust follows the Canadian practice of reporting gross production and reservevolumes; however, the Trust also follows the United States practice ofseparately reporting these volumes on a net basis (after the deduction ofroyalties and similar payments).  TheTrust also follows the Canadian practice of using forecast prices and costswhen the Trust estimates its reserves; however, the Trust separately estimatesits reserves using prices and costs held constant at the effective date of thereserve report in accordance with the Canadian reserve reportingrequirements.  These requirements aresimilar to the constant pricing reserve methodology utilized in the UnitedStates.

We included in thisAnnual Information Form estimates of proved and proved plus probablereserves.  The SEC generally prohibitsthe inclusion of estimates of probable reserves in filings made with it.  This prohibition does not apply to the Trustbecause it is a Canadian foreign private issuer.

**UnitedStates and other non-resident unitholders may be subject to additionaltaxation.**

***The TaxAct and the tax treaties between Canada and other countries may imposeadditional withholding or other taxes on the cash distributions or otherproperty paid by the Trust to unitholders who are not residents of Canada, andthese taxes may change from time to time. Since January 1, 2005, a 15% Canadian withholding tax is applied toreturn of capital portion of distributions made to non-resident unitholders.***

**Additionally,the reduced ‘‘Qualified Dividend’’ rate of 15% tax applied to the Trust’sdistributions under current U.S.  taxlaws is scheduled to expire at the end of 2010 and there is no assurance thatthis reduced tax rate will be renewed by the U.S.  government at such time.**

**Furthermore,it is unclear what impact the proposed changes to the Tax Act relating to theOctober 31 Proposals will have on the taxation of cash distributions or otherproperty paid by the Trust to unitholders who are not residents of Canada.**

**Non-residentunitholders are subject to foreign exchange risk on the distributions that theymay receive from the Trust.**

**The Trust’sdistributions are declared in Canadian dollars and converted to foreigndenominated currencies at the spot exchange rate at the time of payment.  As a consequence, investors are subject toforeign exchange risk.  To the extentthat the Canadian dollar weakens with respect to their currency, the amount ofthe distribution will be reduced when converted to their home currency.**

**Fluctuationsin foreign currency exchange rates could adversely affect the business of theOperating Entities, and adversely affect the market price of the Units as wellas distributions to Unitholders.**

Fluctuations inforeign currency exchange rates could adversely affect the Operating Entities’business, and could affect the market price of the Units as well asdistributions to Unitholders.  The pricethat the Operating Entities receive for a majority of their oil and natural gasis based on United States dollar denominated benchmarks, and therefore theprice received in Canadian dollars is affected by the exchange rate between thetwo currencies.  A 

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material increasein the value of the Canadian dollar relative to the United States dollar maynegatively impact net production revenue by decreasing the Canadian dollarsreceived for a given United States dollar price.  The Operating Entities could be subject tounfavourable price changes to the extent that they have engaged, or in thefuture engage, in risk management activities related to foreign exchange rates,through entry into forward foreign exchange contracts or otherwise.

The operationalresults and financial condition of the Trust are dependent on the pricesreceived by the Operating Entities for oil and natural gas production.  Oil and natural gas prices are currently highon an historical basis, but have fluctuated widely during recent years and aredetermined by supply and demand factors, including weather and general economicconditions as well as economic, political and other conditions in other oil andnatural gas regions, all of which are beyond the Trust’s control.  Any decline in oil and natural gas pricescould have an adverse effect on the Trust’s financial condition and thereforeon the distributable income to be distributed to holders of Units as well as onthe future value of the Trust’s reserves as determined by independentevaluators.

**Operationof oil and natural gas wells by the Operating Entities could subject them toenvironmental claims and liability which would be funded out of the Trust’sfunds flow from operations and could therefore reduce distributable cashpayable to Unitholders.  The OperatingEntities could also incur material costs as a result of compliance with health,safety and environmental laws and regulations which could negatively affect thefinancial condition of the Trust and, therefore, reduce distributions toUnitholders and decrease the market price of the Units.**

The OperatingEntities’ operations are subject to a variety of federal, provincial laws andregulations, including laws and regulations relating to the protection of theenvironment.  A breach of suchlegislation may result in the imposition of fines or issuance of clean up ordersin respect of the Operating Entities or their oil and gas properties.  Such legislation may be changed to imposehigher standards and potentially more costly obligations on the OperatingEntities.  See also “*IndustryConditions — ProvincialRoyalties and Incentives — Environmental Regulation*”.

Canada is asignatory to the United Nations Framework Convention on Climate Change and hasratified the Kyoto Protocol established thereunder to set legally bindingtargets to reduce nationwide emissions of carbon dioxide, methane, nitrousoxide and other so called “greenhouse gases”. The Operating Entities’ exploration and production facilities and otheroperations and activities emit a small amount of greenhouse gases, which maysubject the Operating Entities to legislation regulating emissions ofgreenhouse gases.  The Government ofCanada has put forward a Climate Change Plan for Canada which suggests furtherlegislation will set greenhouse gases emission reduction requirements forvarious industrial activities, including oil and gas exploration andproduction.  Future federal legislation,together with provincial emission reduction requirements, such as thoseproposed in Alberta’s Bill 32: Climate Change and Emissions Management,may require the reduction of emissions or emissions intensity of the OperatingEntities’ operations and facilities.  Thedirect or indirect costs of these regulations may adversely affect theOperating Entities’ business.

**Canetic’sindebtedness may limit the amount of distributions that the Trust is able topay Unitholders, and if Canetic defaults on its debt, the net proceeds of anyforeclosure sale would be allocated to the repayment of Canetic’s lenders andother creditors and only the remainder, if any, would be available for distributionto Unitholders.**

Amounts paid inrespect of interest and principal on debt incurred in respect of the OperatingEntities’ properties will reduce distributable income.  Variations in interest rates and scheduledprincipal repayments could result in significant changes in the amount requiredto be applied to debt service before payment of any amounts to the Trust.  Certain covenants of the agreements withCanetic’s lenders may also limit distributions to the Trust and by the Trust toUnitholders.  Although Canetic believesits credit facilities will be sufficient for Canetic’s immediate requirements,there can be no assurance that the amount will be adequate for the financialobligations of the Operating Entities or that additional funds can be obtained.

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Canetic’s principal lenders have obtained guaranteesand subordination agreements from all material Operating Entities.  If the Operating Entities become unable topay their debt service charges or otherwise commit an event of default such asbankruptcy, the lenders may prohibit the Operating Entities from makingpayments to the Trust.  The lenders mayenforce the payment obligations of the Operating Entities under the loanagreement and guarantees and such obligations of the Operating Entities to thelenders will rank in priority to any payments by the Operating Entities to theTrust.

In the event of a bankruptcy, liquidation orreorganization of Canetic or any of the other Operating Entities, holders oftheir indebtedness and their trade creditors will generally be entitled topayment of their claims from the assets of Canetic and the other OperatingEntities, 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 andmost other liabilities (including trade payables) of Canetic and the otherOperating Entities.  Neither Canetic norany of the other Operating Entities are limited in their ability to incursecured or unsecured indebtedness.

**Delayin Cash Receipts**

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

**Caneticis dependent on its management and the loss of its key management and otherpersonnel could negatively impact its business.**

Unitholders aredependent on the senior management and Board of Directors in respect of allaspects of the management of matters relating to the Operating Entities andtheir properties and all material matters relating to the Trust.  The success of the Trust’s operations will belargely dependent on the skills and expertise of senior management and otherkey personnel.  The Trust’s continuedsuccess will be dependent on its ability to retain or recruit such personnel.

**Ifthe Trust is unable to acquire additional reserves, the value of the Units anddistributions to Unitholders may decline.**

Like other incometrusts, the Trust has certain unique attributes that differentiate it fromconventional oil and gas industry participants. Distributions of distributable income in respect of the OperatingEntities’ oil and gas properties, absent commodity price increases or costeffective acquisition and development activities, will decline over time in amanner consistent with declining production from typical oil, natural gas andnatural gas liquids reserves.  TheOperating Entities will not be reinvesting funds flow from operations in thesame manner as other industry participants. Accordingly, absent capital injections, the Operating Entities’ initialproduction levels and reserves will decline.

The OperatingEntities’ future oil and natural gas reserves and production, and thereforetheir funds flow from operations, will be highly dependent on the OperatingEntities’ success in exploiting their reserve base and acquiring additionalreserves.  Without reserve additions throughacquisition or development activities, the Operating Entities’ reserves andproduction will decline over time as reserves are exploited.

To the extent thatexternal sources of capital, including the issuance of additional Units becomelimited or unavailable, the Operating Entities’ ability to make the necessarycapital investments to maintain or expand their oil and natural gas reserveswill be impaired.  To the extent that theOperating Entities are required to use funds flow from operations to financecapital expenditures or property acquisitions, the level of distributableincome will be reduced.

There can be noassurance that the Operating Entities will be successful in developing oracquiring additional reserves on terms that meet the Trust’s investmentobjectives.

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**Unitholdersmay suffer dilution if the Trust was to redeem or satisfy its interestobligations under its Convertible Debentures through the issue of Units.**

The Trust maydetermine to redeem the currently outstanding convertible debentures for Unitsor to settle the interest and/or pay the redemption price at maturity of suchconvertible debentures by issuing additional Units.  Accordingly, holders of Units may sufferdilution in the event of any such redemption.

**TheTrust or the Operating Entities may be unable to successfully compete withother companies in their industry, which could negatively affect the marketprice of the Units and distributions to Unitholders.**

There is strongcompetition relating to all aspects of the oil and gas industry.  The Trust and the Operating Entities activelycompete for reserve acquisitions and skilled industry personnel with asubstantial number of other oil and gas companies, many of which havesignificantly greater financial and other resources than the Trust or theOperating Entities.

**Changes in Canadian legislation could adversely affectthe value of Units.**

There can be noassurance that income tax laws and government incentive programs relating tothe oil and gas industry, such as the status of mutual fund trusts and theresource allowance, will not be changed in a manner that adversely affects theTrust or Unitholders.

**Theredemption right associated with the Units is limited.**

It is anticipatedthat the redemption right associated with Units will not be the primarymechanism for holders of Units to dispose of their Units.  Redemption Notes that may be distributed inspecie to Unitholders in connection with a redemption, will not be listed onany stock exchange and no market is expected to develop in such RedemptionNotes.  Redemption Notes will not bequalified investments for trusts governed by Deferred Plans.

**Therights of a Unitholder differ from the rights associated with other types ofinvestments and the Trust cannot assure Unitholders that the distributions theyreceive over the life of their investment will meet or exceed the Unitholder’sinitial capital investment.**

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

The Trust’s primary assets are the Canetic Notes, theCanetic NPIs and the direct and indirect ownership of the Operating Entities.  The price per Unit is a function of theanticipated distributable income, the oil and gas properties of the OperatingEntities and the Trust’s ability to effect long-term growth in its value.  The market price of Units will be sensitiveto a variety of market conditions including, but not limited to, interest ratesand the ability of the Trust to acquire suitable oil and natural gasproperties.  Changes in market conditionsmay adversely affect the trading price of Units.

Units will have novalue when reserves from the Operating Entities’ properties can no longer beeconomically 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 oninvestment.

The Trust is not alegally recognized entity within the relevant definitions of the *Bankruptcy and Insolvency Act*(Canada),the *Companies’ Creditors Arrangement Act*(Canada) and in some cases, the *Winding Upand Restructuring Act* (Canada). As a result, in the event a restructuring of the Trust were necessary,the Trust would not be able to access the remedies available thereunder.

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

**Thelimited liability of Unitholders is uncertain.**

The TrustIndenture provides that no Unitholder, in its capacity as such, shall incur orbe subject to any liability in contract or in tort or of any other kindwhatsoever to any person in connection with the Trust Fund (as defined in theTrust Indenture) or the obligations or the affairs of the Trust or with respectto any act performed by the Trustee or by any other person pursuant to theTrust Indenture or with respect to any act or omission of the Trustee or anyother person in the performance or exercise, or purported performance orexercise, of any obligation, power, discretion or authority conferred upon theTrustee or such other person under the Trust Indenture or with respect to anytransaction entered into by the Trustee or by any other person pursuant to theTrust Indenture.  The Trust Indenturefurther provides that no Unitholder shall be liable to indemnify the Trustee orany such other person with respect to any such liability or liabilities incurredby the Trustee or by any such other person or persons or with respect to anytaxes payable by the Trust or by the Trustee or by any other person on behalfof or in connection with the Trust. Notwithstanding the foregoing, the Trust Indenture also provides that tothe extent that any Unitholders are found by a court of competent jurisdictionto be subject to any such liability, such liability shall be enforceable onlyagainst, and shall be satisfied only out of, the Trust Fund and the Trust, (tothe extent of the Trust Fund) is liable to, and shall indemnify and saveharmless any Unitholder against any costs, damages, liabilities, expenses,charges or losses suffered by any Unitholder from or arising as a result ofsuch Unitholder not having any such limited liability.

The TrustIndenture provides that all contracts signed by or on behalf of the Trust mustcontain a provision to the effect that such obligation will not be binding uponUnitholders personally.  Notwithstandingthe terms of the Trust Indenture, Unitholders may not be protected fromliabilities of the Trust to the same extent a shareholder is protected from theliabilities of a corporation.  Personalliability may also arise in respect of claims against the Trust (to the extentthat claims are not satisfied by the Trust) that do not arise under contracts,including claims in tort, claims for taxes and possibly certain other statutoryliabilities.  The possibility of anypersonal liability to Unitholders of this nature arising is considered unlikelyin view of the fact that the primary activity of the Trust is to holdsecurities, and all of the business operations are currently carried on byCanetic or the Operating Entities.  The *Income Trusts Liability Act* (Alberta) cameinto force on July 1, 2004.  Thelegislation provides that a unitholder will not be, as a beneficiary, liablefor any act, default, obligation or liability of the trustee that arises afterthe legislation came into force.

**TheTrust Indenture permits the Board of Directors to restrict the ownership ofUnits by non-resident of Canada in certain circumstances in order to maintainthe Trust’s status as a mutual fund trust.**

Generally, a trust cannot qualify as a “mutual fundtrust” for the purposes of the Tax Act if it is established or is beingmaintained primarily for the benefit of non-residents.  Although not without uncertainty, this isgenerally accepted to exist in most situations where Non-Resident holders ownsignificantly in excess of 50% of the aggregate number of Units issued andoutstanding.  However, there is currentlyan 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 timeconsisted of “taxable Canadian property”.

In accordance withthe Trust Indenture, in order to ensure the maintenance of its “mutual fundtrust” status Canetic will: (i) prior to the completion of any transactioninvolving the acquisition by the Trust of any Subsequent Investment; (ii) priorto any material modification to the Trust Fund (as defined in the TrustIndenture) other than as contemplated by subclause (i); (iii) promptlyfollowing (a) any proposed amendment to paragraph 132(7)(a) of the Tax Act(which provision relates to the level of “taxable Canadian property”), (b) anyother proposed amendment to the Tax Act which impacts on paragraph 132(7)(a) ofthe Tax Act or otherwise imposes restrictions on non-resident ownership ofunits of a mutual fund trust or (c) the publication of any administrative bulletinor other notice of interpretation relating to the interpretation or applicationof 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, atthe 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 ofinterpretation), still qualifies as a mutual fund trust under the Tax Act.

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If at any time theBoard of Directors determines, in its sole discretion, or becomes aware thatthe ability of the Trust to continue to rely on paragraph 132(7)(a) of the TaxAct (or any successor provision thereto) for purposes of qualifying as a “mutualfund trust” thereunder is in jeopardy, then forthwith after such determinationit shall be the sole responsibility of Canetic to monitor the holdings byNon-Residents and Canetic will take such steps as are necessary or desirable toensure that the Trust is not maintained primarily for the benefit ofNon-Residents or that the Trust is otherwise able to continue to qualify as a “mutualfund trust” for the purposes of the *Tax Act*.

Canetic may, atany time and from time to time, in its sole discretion, request that theTrustee make reasonable efforts, as practicable in the circumstances, to obtaindeclarations as to beneficial ownership, perform residency searches ofUnitholders and beneficial Canetic mailing address lists, and take such othersteps specified by Canetic, at the cost of the Trust, to determine or estimateas best possible the residence of the beneficial owners of the Units.

If at any time theBoard of Directors, in its sole discretion, determines that it is in the bestinterest of the Trust, Canetic, notwithstanding the ability of the Trust tocontinue to rely on subsection 132(7)(a) of the Tax Act for the purpose ofqualifying as a “mutual fund trust” under the Tax Act, may (i) require theTrustee to refuse to accept a subscription for Units from, or issue or registera transfer of Units to, a person unless the person provides a declaration toCanetic that the Units to be issued or transferred to such person will not whenissued or transferred be beneficially owned by a Non-Resident; (ii) to theextent practicable in the circumstances, send a notice to registered holders ofUnits which are beneficially owned by Non-Residents, chosen in inverse order tothe order of acquisition or registration of such Units beneficially owned byNon-Residents or in such other manner as Canetic may consider equitable andpracticable, requiring them to sell their Units which are beneficially owned byNon-Residents or a specified portion thereof within a specific period of notless than 60 days.  If the Unitholdersreceiving such notice have not sold the specified number of such Units orprovided Canetic with satisfactory evidence that such Units are notbeneficially owned by Non-Residents within such period, Canetic may, on behalfof such registered Unitholder, sell such Units and, in the interim, suspend thevoting and distribution rights attached to such Units and make any distributionin respect of such Units by depositing such amount in a separate bank accountin a Canadian chartered bank (net of any applicable taxes).  Any sale may be made on any stock exchange onwhich the Units are then listed and, upon such sale, the affected holders shallcease to be holders of Units so disposed of and their rights shall be limitedto receiving the net proceeds of sale, and any distribution in respect thereofdeposited as aforesaid, net of applicable taxes and costs of sale, uponsurrender of the certificates representing such Units; (iii) delist the Unitsfrom any non-Canadian stock exchange; and (iv) take such other actions as theBoard of Directors determines, in its sole discretion, are appropriate in thecircumstances that will reduce or limit the number of Units held byNon-Residents to ensure that Canetic is not maintained primarily for thebenefit of Non-Residents.

Notwithstandingany other provision of the Trust Indenture, Non-Resident Unitholders, whetherregistered holders or beneficial holders of Units, are not be entitled to votein respect of any Special Resolutions to amend the provisions of the TrustIndenture relating to restrictions on Non Resident ownership.

**Managementmay have conflicts of interest that may create incentives for it to actcontrary to or in competition with the interests of Unitholders.**

The directors andofficers of Canetic are engaged in and will continue to engage in otheractivities in the oil and natural gas industry and, as a result of these andother activities, the directors and officers of Canetic may become subject toconflicts of interest.  The ABCA providesthat in the event that a director has an interest in a contract or proposedcontract or agreement, the director shall disclose his interest in suchcontract or agreement and shall refrain from voting on any matter in respect ofsuch contract or agreement unless otherwise provided under the ABCA.  To the extent that conflicts of interestarise, such conflicts will be resolved in accordance with the provisions of theABCA.

**AdditionalRisk Factors**

The business ofthe Operating Entities is subject to other risks and matters that are outsideof their control.  See also “*Industry Conditions*”.

 

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** INTEREST OFMANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS**

To the knowledgeof the directors and executive officers of Canetic, there were no materialinterests, direct or indirect, of directors or executive officers of Canetic,nominees for director of Canetic, any Unitholder who beneficially owns morethan 10% of the Units of the Trust, or any known associate or affiliate of suchpersons, in any transaction since inception of the Trust or in any proposedtransaction which has materially affected or would materially affect the Trustor Canetic other than as disclosed herein.

**INTEREST OF EXPERTS**

Deloitte &Touche LLP, Chartered Accountants, are the Trust’s auditors and such firm hasprepared an opinion with respect to the Trust’s consolidated financial statementsas at and for the fiscal period ended December 31, 2006.  Deloitte & Touche LLP is independent inaccordance with the Rules of Professional Conduct as outlined by the Instituteof Chartered Accountants of Alberta.

GLJ and Sproule preparedthe Canetic Trust Engineering Report.  Asat the date hereof, neither GLJ or Sproule nor any of their directors orofficers owns, directly or indirectly, any of the Units.

**MATERIAL CONTRACTS**

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

1.                                       theTrust Indenture;

2.                                       theAdministration Agreement ;

3.                                       theTrust Unit Incentive Plan;

4.                                       the8% Debenture Indenture;

5.                                       the11% Debenture Indenture;

6.                                       the6.5% Debenture Indenture;

7.                                       the9.4% Debenture Indenture;

8.                                       the6.5% Canetic Debenture Indenture; and

9.                                       Agreementof Purchase and Sale in respect of the Samson Acquisition.

**LEGAL PROCEEDINGS**

There are no outstandinglegal proceedings material to the Trust to which the Trust or Canetic is aparty or in respect of which any of the Canetic Assets are subject, nor arethere any such proceedings known to be contemplated.

**AUDITORS, TRANSFER AGENT AND REGISTRAR**

The auditors of the Trustare Deloitte & Touche LLP, 3000 Scotia Centre, 700 Second Street SW,Calgary, Alberta T2P 0S7.

Computershare TrustCompany of Canada at its principal offices in Calgary, Alberta and Toronto,Ontario is the registrar and transfer agent for the Trust Units and theConvertible 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 UnitedStates.

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**ADDITIONAL INFORMATION**

Additionalinformation including remuneration and indebtedness of directors and officers,principal holders of securities and securities authorized for issuance underequity compensation plans is contained in the Information Circular — ProxyStatement of the Trust dated March 23, 2007 and additional financial information is providedin the financial statements and management’s discussion and analysis of theTrust for the year ended December 31, 2006.

For additionalcopies of the Annual Information Form and the materials listed in the precedingparagraphs 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 materialslisted in the preceding paragraphs, together with additional informationrelating to the Trust may also be accessed through the SEDAR website atwww.sedar.com or through the Trust’s website at www.canetictrust.com.

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**GLOSSARY OF TERMS**

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

**“****000s****”** meansthousands.

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

**“****Acclaim****”** meansAcclaim Energy Trust, an unincorporated trust formed under the laws of theProvince 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 administrationof the Trust.

**“****AEI****”** meansAcclaim Energy Inc., a predecessor of Canetic amalgamated under the ABCA.

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

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

**“****ARTC****”** means theAlberta 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. fromElk Point as part of the Elk Point Arrangement.

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

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

**“****Canetic Notes****”**means the promissory notes of AEI, SEL and other affiliates of Acclaim andStarPoint 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 theoil, natural gas liquids and natural gas interests held by the Trust andprepared by GLJ and Sproule effective December 31, 2006.

**“CBCA”**meansthe *Canada Business Corporation Act*,R.S.C. 1985, C. C-44, as amended, including the regulations promulgatedthereunder.

**“Chevron Canada”**means, collectively, Chevron Canada Limited and Chevron Canada Resources, asvendor of the Chevron Texaco Properties.

**“****Chevron Texaco Acquisition****”**means the acquisition of the Chevron Texaco Properties by AEI as moreparticularly described under the heading “*Business and Properties — Acclaim Significant Transactions*”.

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**“****Chevron Texaco Properties****”**means the interests in oil and natural gas reserves and associated facilitieslocated in Alberta, British Columbia, Saskatchewan and Manitoba acquired by AEIpursuant to the Chevron Texaco Acquisition as more particularly described underthe heading “*Business and Properties — Acclaim Significant Transactions*”.

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

**“CompanyInterest Reserves”** means Canetic’s Gross Reserves plus itsroyalty interest Reserves.

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

(a)                                  Canetic’sprices and costs as at the effective date of the estimation, held constantthroughout 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 futureprices or costs to which Canetic is legally bound by a contractual or otherobligation to supply a physical product, including those for an extensionperiod of a contract that is likely to be extended, those prices or costsrather than the prices and costs referred to in paragraph (a).

**“****Convertible Debentures****”**means, collectively, the 8% Debentures, the 11% Debentures, the 6.5%Debentures, the 9.4% Debentures and the 6.5% Canetic Debentures.

**“****Danoil****”** meansDanoil Energy Ltd., a predecessor corporation of Canetic, incorporated underthe ABCA.

**“****Danoil Merger****”**means the transaction described under the heading “*Business andProperties — AcclaimSignificant Transactions*”.

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

**“****6.5% Canetic Debentures****”**means the 6.5% convertible, extendible, unsecured, subordinated debenturesissued on August 24, 2006 pursuant to the 6.5% Canetic Debenture Indenture.

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

**“****6.5% Debentures****”**means the 6.5% convertible, extendible, unsecured, subordinated debenturesissued 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 issuedon 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 debenturesissued 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 debenturesissued on December 17, 2002 pursuant to the 11% Debenture Indenture.

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**“Development****costs****”** means costsincurred 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 andother costs of development activities, are costs incurred to:

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

(b)                                 drilland equip development wells, development type stratigraphic test wells andservice wells, including the costs of platforms and of well equipment such ascasing, 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 wastedisposal systems; and

(d)                                 provideimproved recovery systems.

**“Developed Non-Producing Reserves”** are those Reservesthat 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 thatare expected to be recovered from completion intervals open at the time of theestimate.  These reserves may becurrently producing or, if shut-in, they must have previously been on production,and the date of resumption of Production must be known with reasonablecertainly.

**“Developed Reserves”** are those Reserves that areexpected to be recovered from existing wells and installed facilities or, iffacilities have not been installed, that would involve a low expenditure (forexample, when compared to the cost of drilling a well) to put the Reserves onProduction.

**“Development well”** means a well drilled inside theestablished limits of an oil and gas reservoir, or in close proximity to theedge of the reservoir, to the depth of a stratigraphic horizon known to beproductive.

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

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

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

**“****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 BurmisEnergy Inc. completed on January 28, 2003 by way of plan of arrangement underthe CBCA pursuant to which, among other things, Acclaim indirectly acquired allof the issued and outstanding common shares of Elk Point and Burmis Energy Inc.acquired the United States assets and certain minor Alberta properties of ElkPoint and the shares of Burmis Energy Inc. were distributed to the formerholders of common shares of Elk Point.

**“****Established Reserves****”**means proved reserves plus risked (50%) probable reserves, with “provedreserves” and “probable reserves” having the meanings ascribed to them underformer National Policy Statement 2-B of the Canadian SecuritiesAdministrators.

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**“****Exodus****”** meansExodus Energy Ltd., a predecessor corporation of Canetic, incorporated underthe ABCA and acquired by Canetic on December 19, 2003 pursuant to the ExodusAcquisition.

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

**“Exploration costs”** means costs incurred in identifyingareas that may warrant examination and in examining specific areas that areconsidered to have prospects that may contain oil and gas reserves, includingcosts of drilling exploratory wells and exploratory type stratigraphic testwells.  Exploration costs may be incurredboth before acquiring the related property and after acquiring theproperty.  Exploration costs, which includeapplicable operating costs of support equipment and facilities and other costsof exploration activities, are:

(a)                                  costsof topographical, geochemical, geological and geophysical studies, rights ofaccess to properties to conduct those studies, and salaries and other expensesof geologists, geophysical crews and others conducting those studies;

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

(c)                                  dryhole contributions and bottom hole contributions;

(d)                                 costsof drilling and equipping exploratory wells; and

(e)                                  costsof drilling exploratory type stratigraphic test wells.

**“Exploratory****well****”** means a well that is not a Development well, a Servicewell or a Stratigraphic Test Well.

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

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

(b)                                 ifand only to the extent that, there are fixed or presently determinable futureprices or costs to which Canetic is legally bound by a contractual or otherobligation to supply a physical product, including those for an extensionperiod of a contract that is likely to be extended, those prices or costsrather than the prices and costs referred to in paragraph (a).

**“****Gilby/Willesden Green Acquisition****”** means the acquisition of the Gilby/Willesden GreenProperties by Canetic as more particularly described under the heading “*Business and Properties— Acclaim Significant Transactions*”.

**“****Gilby/Willesden Green Properties****”** means the interests in oil and natural gas reserves andassociated facilities located in the Gilby West and Willesden Green areas ofwest central Alberta acquired by Canetic pursuant to the Gilby/Willesden GreenAcquisition as more particularly described under the heading “*Business and Properties— Acclaim Significant Transactions*”.

**“****GLJ****”** means GLJPetroleum Consultants Ltd.

**“****GLJ Report****”**means the report of GLJ dated March 5, 2007 and effective as of December 31,2006, evaluating the oil and natural gas reserves and future net productionrevenues attributable to certain of the properties of Canetic.

**“****Gross****”** means:

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

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

(c)                                  inrelation to properties, the total area of properties in which Canetic has aninterest.

**“****Hoadley and B.C. Properties****”**means the interests in oil and natural gas reserves and associated facilitieslocated in Alberta and British Columbia acquired by Canetic pursuant to theSamson Acquisition as more particularly described under the heading “*Business and Properties— Canetic Significant Transactions*”.

**“****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, incorporatedunder the ABCA.

**“****Ketch Energy Arrangement****”**means the business combination involving Acclaim, AEI, Ketch Energy and KetchResources Ltd. completed on October 1, 2002 by way of a plan of arrangementunder the ABCA pursuant to which, among other things, Acclaim indirectlyacquired all of the issued and outstanding shares of Ketch Energy, certaingrowth assets of Ketch Energy were acquired by Ketch Resources Ltd. and theshares of Ketch Resources Ltd. were distributed to the former holders of commonshares 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 onwhich the Units are tendered to the Trust for redemption; (ii) 95% of the “closingmarket price”, as calculated under Trust Indenture, on the principal market onwhich the Units are quoted for trading on the date that the Units are sotendered for redemption; and (iii) 95% of the closing market price of the TrustUnits on the date of redemption.

**“****NAFTA****”** meansthe North American Free Trade Agreement.

**“****NEB****”** means theNational Energy Board.

**“**n**et****”** means:

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

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

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

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

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

**“****Nexen Acquisition****”**means the acquisition of the Nexen Assets by StarPoint and more particularlydescribed under the heading “*Business and Properties — StarPoint Significant Transactions*”.

**“****Nexen Assets****”**means the interests in oil and natural gas reserves and related facilitieslocated in Saskatchewan acquired by StarPoint pursuant to the NexenAcquisition.

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**“****NG Acquisition****”**means the acquisition of the NG Properties by Canetic as more particularlydescribed under the heading “*Business and Properties — Acclaim Significant Transactions*”.

**“****NG Properties****”**means the interests in oil and natural gas reserves and associated facilitieslocated in Alberta and British Columbia acquired by Canetic pursuant to the NGAcquisition as more particularly described under the heading “*Business and Properties— Acclaim Significant Transactions*”.

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

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

**“****NYSE****”** means theNew York Stock Exchange.

**“October31 Proposals”** means the proposal of the Canadian federalgovernment, originally announced on October 31, 2006, to introduce a taxon publicly traded income trusts (other than real estate investment trusts) togenerally tax income trusts at the same effective tax rates as Canadiancorporations including the draft legislation introduced on December 21, 2006 toimplement the October 31, 2006 Proposals.

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

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

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

**“****Person****”** meansany individual, partnership, association, body corporate, trustee, executor,administrator, legal representative, government, regulatory authority or otherentity.

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

**“Proved Reserves”**are those reserves that can be estimated with a high degree of certainty to berecoverable.  It is likely that theactual remaining quantities recovered will exceed the estimated ProvedReserves.  It is believed that there isat least a 90 percent probability that the quantities actually recovered willequal or exceed the estimated Proven Reserves.

**“****Reserves****”** areestimated remaining quantities of oil and natural gas and related substancesanticipated to be recoverable from known accumulations, from a given dateforward, based on:

(a)                                  analysisof drilling, geological, geophysical and engineering data;

(b)                                 theuse of established technology; and

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(c)                                  specifiedeconomic conditions which are generally accepted as being reasonable and shallbe disclosed.

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

**“Samson Acquisition”**means the acquisition of the Hoadley and B.C. Properties by Canetic as moreparticularly described under the heading “*Business and Properties — Canetic Significant Transactions*”.

**“****SEDAR****”** meansthe System for Electronic Document Analysis and Retrieval.

**“****SEL****”** meansStarPoint Energy Ltd., a corporation amalgamated under the ABCA.

**“****Service well****”**means a well drilled or completed for the purpose of supporting production inan existing field.  Wells in this classare 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 forcombustion.

**“****Special Resolution****”**means a resolution proposed to be passed as a special resolution at a meetingof Unitholders (including an adjourned meeting) duly convened for the purposeand held in accordance with the provisions of the Trust Indenture at which twoor more holders of at least 5% of the aggregate number of Units thenoutstanding are present in person or by proxy and passed by the affirmativevotes 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 toattend meetings of Unitholders and to such number of votes at meetings ofUnitholders as may be prescribed by the Board in the resolution authorizing theissuance of any such Special Voting Units.

**“****Sproule****”** meansSproule Associates Limited.

**“****Sproule Report****”**means the reports of Sproule dated February 22, 2007 and February 23, 2007 andeffective December 31, 2006, evaluating the crude oil and natural gas reservesand future net production revenues attributable to certain properties ofCanetic.

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

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

**“****StarPoint Units****”**means the trust units of StarPoint.

**“****Stratigraphic Test Well****”**means a drilling effort, geologically directed, to obtain informationpertaining to a specific geologic condition. Ordinarily, such wells are drilled without the intention of beingcompleted for hydrocarbon production. They include wells for the purpose of core tests and all types ofexpendable holes related to hydrocarbon exploration.

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

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

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**“****Tax Act****”** meansthe *Income Tax Act* (Canada),R.S.C. 1985, C. 1 (5th Supp.), as amended, including the regulationspromulgated thereunder, as amended from time to time.

**“****TSX****”** means theToronto Stock Exchange.

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

**“****TriStar Arrangement Warrants****”** means the share purchase issued to Acclaim Securityholdersand StarPoint Securityholders pursuant to the Arrangement, each of whichentitled the holder to acquire one (1) TriStar Common Share at an exerciseprice of $2.75 per wholeTriStar Common Share until 4:30 p.m. (Calgary time) on or before but not afterFebruary 6, 2006.

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

**“****Trust****”** meansCanetic Resources Trust, a trust established under the laws of the Province ofAlberta pursuant to the Trust Indenture.

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

**“****Trust Unit Incentive Plan****”**means the 2006 Unit Award Incentive Plan adopted by the Board of Directorsgoverning the issue of Units to certain service providers of the Trust.

**“****Trustee****”** meansComputershare Trust Company of Canada, the initial trustee of the Trust, orsuch other trustee, from time to time of the Trust.

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

**“****Unit****”** means atrust unit of the Trust.

**“****Unitholder****”**means a holder of Units.

**CONVENTIONS**

Certain terms used hereinare defined in the “*Glossar*y*of Terms*”.  Certain other terms used herein but notdefined herein are defined in NI 51-101 and, unless the contextotherwise requires, shall have the same meanings herein as in NI 51-101.

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

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

**ABBREVIATIONS**
| **Oil and  Natural Gas Liquids** | ** **             | ** ** | **Natural Gas** | ** **                    |
|----------------------------------|------------------------|------------|-----------------|-------------------------------|
|                             |                   |       |            |                          |
| Bbl                              | barrel                 |       | Mcf             | thousand cubic feet           |
| Bbls                             | barrels                |       | MMcf            | million cubic feet            |
| MBbls                            | thousand barrels       |       | Mcf/d           | thousand cubic feet per day   |
| MMBbls                           | million barrels        |       | MMcf/d          | million cubic feet per day    |
| Bbls/d                           | barrels per day        |       | mmbtu           | million British thermal units |
| BOPD                             | barrels of oil per day |       | Bcf             | billion cubic feet            |
| NGL                              | natural gas liquids    |       | GJ              | gigajoule                     |

 

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**Other**

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

API                                                                           AmericanPetroleum Institute

°API                                                                      anindication of the specific gravity of crude oil measured on the API gravityscale.

Boe*                                                                    barrelof oil equivalent of natural gas and crude oil and natural gas liquids on thebasis of 1 Boe for 6 Mcf of natural gas

Boe/d                                                                barrelof oil equivalent per day

C$                                                                                  Canadiandollars

m3                                                                                  cubicmetres

M$                                                                              thousandsof dollars

MBoe                                                               thousandbarrels of oil equivalent

mTVD                                                              metrestrue vertical depth

MMBoe                                                   millionbarrels of oil equivalent

MM                                                                        million

US$                                                                          UnitedStates dollars

WTI                                                                       WestTexas Intermediate, the reference price paid in United States dollars atCushing, Oklahoma for crude oil of standard grade

 

*                                                                                         Boesmay be misleading, particularly if used in isolation.  Where reserves or production are stated on aboe basis, natural gas volumes have been converted to a boe at a ratio of 6,000cubic feet of natural gas to one barrel of oil. This conversion ratio is based on an energy equivalent conversion methodprimarily applicable at the burner tip and does not represent value equivalenceat the wellhead.

**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           |
| gigajoule       |       | MMBTU        |       | 0.948213        |
| MMBTU           |       | gigajoule    |       | 1.054615        |

 

 

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**APPENDIX“A”**

**REPORTOF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION**

Management of CaneticResources Inc. (“**Canetic**”) areresponsible for the preparation and disclosure of information with respect toCanetic’s oil and gas activities in accordance with securities regulatoryrequirements.  This information includesreserves data, which consist of the following:

(a)                                  (i)                                     provedand proved plus probable oil and gas reserves estimated as at December 31, 2006using forecast prices and costs; and

(ii)                                  therelated estimated future net revenue; and

(b)                                 (i)                                     provedoil and gas reserves estimated as at December 31, 2006 using constant pricesand costs; and

(ii)                                  therelated estimated future net revenue.

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

The Reserves Committee ofthe Board of Directors of Canetic has:

(a)                                  reviewedCanetic’s procedures for providing information to the independent qualifiedreserves evaluators;

(b)                                 metwith the independent qualified reserves evaluator to determine whether anyrestrictions affected the ability of the independent qualified reservesevaluators to report without reservation; and

(c)                                  reviewedthe reserves data with management and the independent qualified reservesevaluators.

The Reserves Committee ofthe Board of Directors has reviewed Canetic’s procedures for assembling andreporting other information associated with oil and gas activities and hasreviewed that information with management. The board of directors has, on the recommendation of the ReservesCommittee, approved:

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

(b)                                 thefiling of the report of the independent qualified reserves evaluators on thereserves data; and

(c)                                  thecontent and filing of this report.

Because the reserves dataare based on judgments regarding future events, actual results will vary andthe variations may be material.
| (signed) *“J. Paul Charron”*          |   | (signed)*“Richard J. Tiede”*        |
|-------------------------------------------------|--------|-----------------------------------------------|
| J. Paul Charron                                 |   | Richard J. Tiede                              |
| President and Chief Executive Officer           |   | Chief Operating Officer                       |
|                                            |   |                                          |
| (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 22, 2007                                  |   |                                          |

 

 

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**APPENDIX “B”**

**REPORT ON RESERVES DATA**

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

1.                                       Wehave evaluated the Company’s reserves data as at December 31, 2006.  The reserves data consist of the following:
| (a)    |   | (i)    |   | proved and proved plus probable oil and gas reserves  estimated as at December 31, 2006 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,  2006 using constant prices and costs; and                          |
|   |   |   |   |                                                                                                                              |
|   |   | (ii)   |   | the related estimated future net revenue.                                                                                         |
|   |   |   |   |                                                                                                                              |

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

We carried out ourevaluation in accordance with standards set out in the Canadian Oil and GasEvaluation Handbook (the “**COGE Handbook**”)prepared jointly by the Society of Petroleum Evaluation Engineers (CalgaryChapter) and the Canadian Institute of Mining, Metallurgy & Petroleum(Petroleum Society).

3.                                       Thosestandards require that we plan and perform an evaluation to obtain reasonableassurance as to whether the reserves data are free of materialmisstatement.  An evaluation also includesassessing whether the reserves data are in accordance with principles anddefinitions presented in the COGE Handbook.

4.                                       Thefollowing table sets forth the estimated future net revenue (before deductionof income taxes) attributed to proved plus probable reserves, estimated usingforecast 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 endedDecember 31, 2006, and identifies the respective portions thereof that wehave audited, evaluated and reviewed and reported on to the Company’s board ofdirectors:
| ** **                                                           | ** ** | ** **                                                                                                                                                          | ** ** | **Location of  Reserves  (County or  Foreign  Geographic  Area)** | ** **  | **Net Present Value of Future Net Revenue  (before income taxes, 10% discount rate)** | ** **    |
|----------------------------------------------------------------------|------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-----------------------------------------------------------------------------|-------------|----------------------------------------------------------------------------------------------------------------------------------------------|---------------|
| **Independent  Qualified Reserves  Evaluator or  Auditor** | ** ** | **Description and  Preparation Date of  Report**                                                                                                     | ** ** | ** **                                                                  | **Audited** | ** **                                                                                                                                   | **Evaluated** | ** ** | **Reviewed** | ** ** | **Total** | ** ** |
| ** **                                                           | ** ** | ** **                                                                                                                                                          | ** ** | ** **                                                                  | ** **  | ** **                                                                                                                                   | ** **    | **($M)** | ** ** | ** ** | ** ** | **($M)** | ** ** |
| ** **                                                           | ** ** | ** **                                                                                                                                                          | ** ** | ** **                                                                  | ** **  | ** **                                                                                                                                   | ** **    | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| GLJ  Petroleum Consultants Ltd.                                      |       | Evaluation  of the  P&NG Reserves in  Certain Properties of  Canetic Resources  Trust, as of  December 31, 2006,  prepared February 16,  2007         |       | Canada                                                                      |        | 0                                                                                                                                            |          | 1,674,583 |   | 0 |   | 1,674,583 |   |
|                                                                 |       |                                                                                                                                                                |       |                                                                        |        |                                                                                                                                         |          |   |   |   |   |   |   |
| Sproule Associates Ltd.                                              |       | Evaluation of the  P&NG Reserves in  Certain Properties of  Canetic Resources  Trust, as of  December 31, 2006,  prepared September  2006 to February 2007 |       | Canada and  United States                                                   |        | 0                                                                                                                                            |          | 1,997,538 |   | 0 |   | 1,997,538 |   |

 

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| Sproule  Associates  Ltd. |   | Evaluation of the  P&NG Reserves of  Canetic Resources  Trust Acquired from  Samson Oil & Gas  Limited, as of  December 31, 2006,  prepared September  2006 to February 2007 |   | Canada |   | 0 |   | 578,413 |   | 0 |   | 578,413 |   |
|---------------------------|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|--------|--------|---|--------|---------|--------|---|--------|---------|--------|

 

5.                                       Inour opinion, the reserves data respectively evaluated by us have, in allmaterial respects, been determined and are in accordance with the COGEHandbook.  We express no opinion on thereserves data that we reviewed but did not audit or evaluate.

6.                                       Wehave no responsibility to update our reports referred to in paragraph 4for events and circumstances occurring after their respective preparationdates.

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

 
| (signed)*“Doug R.  Sutton”*             | * *                                 | (signed)*“Robert N. Johnson”* |
|---------------------------------------------------|------------------------------------------|-----------------------------------------|
| GLJ Petroleum  Consultants Ltd.  Calgary, Alberta | Sproule Associates Ltd  Calgary, Alberta |
|                                              |                                     |
| **March  5, 2007**                                | **February 23, 2007**                    |

 

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**APPENDIX “C”**

**TERMSOF 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 Corporationand their subsidiaries, the term “**Board**” or “**Board of Directors**” refers to the board of directors of theCorporation, 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 theCommittee is to assist the Board in fulfilling its oversight responsibilities,in the Corporation’s capacity as administrator of the Trust, relating to theTrust’s financial reporting including the integrity of the Trust’s financialstatements, the Trust’s financial reporting process and systems of internalcontrols, the compliance by the Trust with legal and regulatory requirementsand the qualifications, performance and independence of the Trust’s externalauditors and internal audit function (if any).

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

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

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

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

(d)                                 all audit processes.

2.                                      Primary responsibility for thefinancial reporting, information systems, risk management and internal controlsof the Trust is vested in management and is overseen by the Board.  While the Committee has the responsibilitiesand powers set forth in these terms of reference, it is not the duty of the Committeeto plan or conduct audits or to determine that the Trust’s financial statementsare complete and accurate and are in accordance with generally acceptedaccounting principles and applicable rules and regulations.  These are the responsibilities of managementand the external auditors.  Nor is it theduty of the Committee to conduct investigations or to assure compliance withlaws and regulations.  The Committee, itschair (the “**Committee Chair**”) andany Committee members identified as having accounting or related financialexpertise or being financially literate are members of the Board, appointed tothe Committee to provide broad oversight of the financial, risk and controlrelated activities of the Trust, and are specifically not accountable orresponsible for the day-to-day operation or performance of suchactivities.  Although the designation ofa Committee member as having accounting or related financial expertise or beingfinancially literate for disclosure purposes or otherwise is based on thatindividual’s education and experience, which that individual will bring to bearin carrying out his or her duties on the Committee, such designation does notimpose on such person any duties, obligations or liability that are greaterthan the duties, obligations or liability imposed on such person as a member ofthe Committee and the Board in the absence of such designation.  Rather, the role of a Committee member who isidentified as having accounting or related financial expertise or beingfinancially literate, like the role of all Committee members, is to oversee theprocess, not to certify or guarantee the internal or external audit of theTrust’s financial information or public disclosure.

**B.**                                    COMPOSITIONAND OPERATIONS

1.                                      The Committee shall be composedof three directors or such greater number as the Board may from time to timedetermine.  The Committee shall only becomprised of independent directors in accordance with the definition of “independent”directors from time to time under the requirements or guidelines for auditcommittee service under applicable securities laws and the rules of any stockexchange on which the Units are listed for trading and a majority shall beresident Canadians.  Currently suchdefinitions are contained in 

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                                               National Instrument 52-110of the Canadian Securities Administrators, Section 303A.02 of theCorporate 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 theCommittee must be financially literate, as the term “financially literate” isinterpreted by the Board in its business judgment or as may be defined fromtime to time under the requirements or guidelines for audit committee serviceunder securities laws and the rules of any stock exchange on which the Unitsare listed for trading, or must become financially literate within a reasonableperiod of time after his or her appointment to the Committee.  “Financially literate” means the ability toread and understand a set of financial statements that present a breadth andlevel of complexity of accounting issues that are generally comparable to thebreadth and complexity of the issues that can reasonably be expected to beraised by the Trust’s financial statements.

The Committee shall havea Committee Chair, who is a full member of the Committee, and who is appointedby the Board.  The Committee Chair shallhave a casting vote in the event of a tie vote in the Committee.  The Board Chair, if not otherwise appointedas a full member of the Committee, shall be an ex officio member of theCommittee.

Committee members mayenhance their familiarity with finance and accounting by participating ineducational programs conducted by the Trust or an outside consultant.  In addition, at least one member of the Committeemust have accounting or related financial management expertise, as theCorporation’s Board of Directors interprets such qualification in its businessjudgment.  At least one member of theCommittee must be an “audit committee financial expert” as defined in theExchange Act and its rules.

2.                                      In connection with the electionof the members of the Committee, the Board will determine whether any proposednominee for the Committee serves on the audit committees of more than threepublic companies.  To the extent that anyproposed nominee of the Corporation serves on the audit committees of more thanthree public companies, the Board will make a determination as to whether suchsimultaneous services would impair the ability of such member to effectively serveon the Committee and will disclose such determination in the Trust’s annualinformation circular and annual report on Form 40-F filed with the Securitiesand Exchange Commission.

3.                                      The external auditors shall beadvised of the names of the Committee members and when appropriate will receivenotice of and be invited to attend meetings of the Committee, and to be heardat those meetings on matters relating to the auditors’ duties.

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

5.                                      The Committee shall meet atleast four times each year.

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

7.                                      The Committee provides openavenues of communication among management, employees, the external auditors andthe Board.

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

9.                                      Notice of the time and place ofevery meeting may be given orally, in writing, by facsimile or email or byother electronic means to each member of the Committee at least 48 hours priorto the time fixed for such meeting.  Amember may, in any manner, waive notice of the meeting.  Attendance of a member at a meeting shallconstitute waiver of notice.

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10.                                The Chief Executive Officer (“**CEO**”), Board Chair and Chief FinancialOfficer (“**CFO**”)of the Corporationwill be available to attend Committee meetings or portions thereof as requestedby the Committee.

The external auditorsshould meet at least twice annually with the Committee and would be expected tobe available to attend such additional meetings or portions thereof asrequested by the Committee.

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

The Committee shall havethe right to determine who shall and who shall not be present at any timeduring a meeting of the Committee.

11.                                The Committee shall report tothe Board any issues that arise with respect to the quality or integrity of theTrust’s financial statements, the Trust’s compliance with legal or regulatoryrequirements, or the performance or independence of the Trust’s externalauditors or internal audit function (if any).

12.                                Minutes of Committee meetingsshall be approved by the Committee Chair and maintained with the Corporation’srecords by the Committee Secretary or designate.  Minutes of Committee meetings shall be madeavailable to all Board members.

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

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

15.                                The Committee may delegate fromto time to any person or committee of persons any of the Committee’sresponsibilities that are permitted to be delegated to such person or committeein accordance with applicable laws, regulations and stock exchangerequirements.

**C.**                                    DUTIES ANDRESPONSIBILITIES

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

1.                                      Financial Statements and OtherFinancial Information

The Committee will reviewand recommend for approval to the Board financial information that will be madepublicly available.  This includes:

(a)                                  reviewing (including by meetingwith management and the external auditors) and recommending 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, andreporting to the Board before the statements are approved by the Board;

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(b)                                 reviewing (including by meetingwith management and the external auditors) and approving for release orrecommending to the Board for approval, the Trust’s interim quarterly financialstatements (including the notes), the MD&A relating to such financialstatements and associated press release;

(c)                                  reviewing and approving forrelease, all earnings or distributable cash press releases, press releasescontaining other financial information and any earnings, distributable cash orother financial performance guidance provided to analysts or rating agencies;

(d)                                 reviewing and recommending tothe Board for approval, the financial content of the annual report and anyfinancial reports required by government or regulatory authorities;

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

(f)                                    reviewing any management reportthat accompanies published financial statements (to the extent such a reportdiscusses the financial position or operating results) for consistency ofdisclosure with the financial statements themselves;

(g)                                 reviewing and resolvingdisagreements between management and the external auditors regarding financialreporting or the application of any accounting principles or practices; and

(h)                                 meeting separately,periodically, with management, with internal auditors (or other personnelresponsible for the internal audit function), if any, and with the externalauditors including reviewing with the external auditors any audit problems ordifficulties and management’s response.

Reviewing and discussing:

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

(j)                                     any significant proposed changesin financial reporting and accounting policies and practices to be adopted bythe Trust;

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

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

(m)                               with the CEO, the CFO and theexternal auditors, the matters required to be reviewed with those persons inconnection with any certificates required by applicable laws, regulations orstock exchange requirements to be provided by the CEO and CFO;

(n)                                 major issues regardingaccounting principles and financial statement presentations, including anysignificant changes in the Trust’s selection or application of accountingprinciples;

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

(p)                                 analyses prepared by managementand/or the external auditors setting forth significant financial reportingissues and judgments made in connection with the preparation of the financialstatements, including analyses of the effects of alternative GAAP methods onthe financial statements;

(q)                                 the effect of regulatory andaccounting initiatives, as well as off-balance sheet structures, on the Trust’sfinancial statements;

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

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

2.                                      Risk Management, InternalControl and Information Systems

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

(a)                                  reviewing the Trust’s and theCorporation’s risk management controls and policies;

(b)                                 obtaining reasonable assurancethat the information systems are reliable and the systems of internal controlsare properly designed and effectively implemented through discussions with andreports from management and the external auditors;

(c)                                  reviewing management steps toimplement and maintain appropriate internal control procedures including areview of policies;

(d)                                 satisfying itself that adequateprocedures are in place for the review of the Trust’s public disclosure offinancial information extracted or derived from the Trust’s financialstatements and periodically assessing the adequacy of those procedures;

(e)                                  reviewing the adequacy ofsecurity of information, information systems and recovery plans;

(f)                                    monitoring compliance withstatutory and regulatory obligations;

(g)                                 reviewing the appointment of theCFO; and

(h)                                 reviewing the adequacy ofaccounting and finance resources.

3.                                      External Audit

The Committee will reviewand oversee the planning and results of external audit activities including theappointment, compensation, retention and oversight of the work of the externalauditors and the ongoing relationship with the external auditors who shallreport directly to the Committee.  Thisincludes:

(a)                                  reviewing and recommending, forUnitholder approval, engagement of the external auditors including, as part ofsuch review and recommendation, an evaluation of the external auditors’qualifications, independence and performance;

(b)                                 reviewing and approving theannual external audit plan, including but not limited to the following:

(i)                                     engagement letter;

(ii)                                  objectives and scope of theexternal audit work;

(iii)                               procedures for quarterly reviewof financial statements;

(iv)                              materiality limit;

(v)                                 areas of audit risk;

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(vi)                              staffing;

(vii)                           timetable; and

(viii)                        fees.

(c)                                  meeting with the externalauditors to discuss the Trust’s quarterly and annual financial statements andother financial disclosures including the management’s discussion and analysisand the auditors’ audit or review engagement reports, as applicable, includingthe appropriateness of accounting policies and underlying estimates;

(d)                                 reviewing with the externalauditors and advising the Board with respect to the planning, conduct andreporting of the annual audit, including but not limited to:

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

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

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

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

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

(vi)                              assessing the performance andconsidering the annual appointment of external auditors for recommendation tothe Board;

(e)                                  reviewing the auditors’ reporton all material subsidiaries;

(f)                                    reviewing and receivingassurances on the independence of the external auditors;

(g)                                 evaluating the performance ofthe lead partner of the external auditors;

(h)                                 ensuring the rotation ofpartners on the audit engagement team in accordance with applicable law.  Considering whether, in order to ensurecontinuing external auditor independence, it is appropriate to adopt a policyof rotating the external audit firm on a regular basis;

(i)                                     reviewing the non-audit servicesto be provided by the external auditors’ firm or its affiliates (includingestimated fees), and considering the impact on the independence of the externalaudit, all of which services shall be subject to pre-approval by the Committee;

(j)                                     approving in advance all auditand permitted non-audit services to be provided to the Trust or any ofits affiliates by the external auditors or any of their affiliates, subject toany *de minimus* exception providedby applicable law; the Committee may delegate to one or more designated membersof the Committee the authority to grant pre-approvals required by thisparagraph, provided that the decision of any such subcommittee to grantpre-approval must be presented to the full Committee at its next scheduledmeeting for ratification;

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(k)                                  the Committee may establishpolicies and procedures for the pre-approval of audit and permitted non-auditedservices to the Corporation in its capacity as administrator of the Trust, solong as such policies and procedures are detailed as to the particular service,the Committee is informed of each service, and the policies and procedures donot include delegation of the Committee’s responsibilities under applicablelaws and regulations to management;

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

(m)                               reviewing the disclosure withrespect to its pre-approval of any audit and non-audit servicesprovided by the external auditors;

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

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

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

(q)                                 meeting periodically, and atleast annually, with the external auditors without management present.

4.                                      Other

(a)                                  reviewing insurance coverageincluding Directors and Officers coverage and making recommendations forrenewal or amendment of the policies or replacement of the insurer(s);

(b)                                 reviewing material litigationand its impact on financial reporting;

(c)                                  reviewing Canetic’s use ofderivative financial instruments and providing recommendations to the Board;

(d)                                 reviewing the “Management’sLevels of Authority Document” and any formal policies outlining Management’slevels of expenditure or approval authority and provide recommendations to theBoard;

(e)                                  reviewing fees paid to outsideprofessional consultants, i.e. lawyers, accountants, other than consultantsplaced in operations in lieu of full time staff;

(f)                                    ensuring that there are nooutstanding loans to directors, officers, employees or consultants of theCorporation;

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

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(h)                                 establishing procedures for thereceipt, retention and treatment of complaints received by the Trust andCanetic regarding accounting, internal accounting controls or auditing mattersand the confidential, anonymous submission by employees and others of concernsregarding questionable accounting or auditing matters;

(i)                                     reviewing and approving allhiring of employees and former employees of the present or former externalauditors of the Trust or the Corporation and reviewing and approving the Trust’sand Canetic’s policies with respect thereto;

(j)                                     reviewing the Committee’s termsof reference annually and submitting any changes to the Nominating andCorporate Governance Committee for review and recommendation to the Board; and

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

**D.**                                    ACCOUNTABILITY

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

The Committee’sperformance shall be evaluated annually pursuant to the assessment processestablished by the Nominating and Corporate Governance Committee and the Board.

**E.**                                      STANDARDS OFLIABILITY

Nothing contained inthese terms of reference is intended to expand applicable standards ofliability under statutory, regulatory or other legal requirements for the Boardor members of the Committee.  Thepurposes and responsibilities outlined in these terms of reference are meant toserve as guidelines rather than inflexible rules and the Committee may adoptsuch additional procedures and standards as it deems necessary from time totime to fulfill its responsibilities.

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