**EXHIBIT99.2**

**2006HIGHLIGHTS**
| **Year ended December 31**                   | ** ** | **2006(1)** | ** ** | **2005**   | ** ** | **%**      | ** ** |
|-------------------------------------------------------------|------------|-------------|------------|------------|------------|------------|------------|
| **($millions except per unit amounts)** | ** ** | ** **  | ** ** | ** ** | ** ** | ** ** | ** ** |
| **FINANCIAL**                                               |       |        |       |       |       |       |       |
| Gross revenue                                               | ** ** | **1,407.8** |       | 800.2      |       | 76         | %          |
| Funds flow from  operations(3)                              | ** ** | **750.1**   |       | 360.5      |       | 108        | %          |
| Per unit -  basic(2)                                        | ** ** | **3.64**    |       | 4.04       |       | -10        | %          |
| Per unit -  diluted(2)                                      | ** ** | **3.57**    |       | 3.98       |       | -10        | %          |
| Net earnings                                                | ** ** | **223.1**   |       | 65.8       |       | 239        | %          |
| Per unit -  basic(2)                                        | ** ** | **1.08**    |       | 0.74       |       | 46         | %          |
| Per unit -  diluted(2)                                      | ** ** | **1.06**    |       | 0.73       |       | 45         | %          |
| Cash distributions  declared                                | ** ** | **583.5**   |       | 208.5      |       | 180        | %          |
| Per unit(2)                                                 | ** ** | **2.7600**  |       | 2.3401     |       | 18         | %          |
| Payout ratio(3)                                             | ** ** | **78**      | **%**      | 58         | %          | 34         | %          |
| Capital expenditures                                        |       |        |       |       |       |       |       |
| Development  expenditures                                   | ** ** | **351.3**   |       | 172.2      |       | 104        | %          |
| Net capital  expenditures (net of StarPoint)                | ** ** | **1,315.0** |       | 181.2      |       | 626        | %          |
| Total assets                                                | ** ** | **5,831.0** |       | 1,571.1    |       | 271        | %          |
| Long-term debt                                              | ** ** | **1,289.7** |       | 309.1      |       | 317        | %          |
| Net debt (excluding  financial derivatives)(3)              | ** ** | **1,318.3** |       | 331.8      |       | 297        | %          |
| Unitholders’ equity                                    | ** ** | **3,506.9** |       | 764.6      |       | 359        | %          |
| Weighted average trust  units outstanding *(000s)(2)*       | ** ** | **206,081** |       | 89,331     |       | 131        | %          |
| Trust units outstanding  at period end *(000s)(2)*          | ** ** | **225,796** |       | 91,583     |       | 147        | %          |
| **OPERATING**                                               |       |        |       |       |       |       |       |
| Production(3)                                               |       |        |       |       |       |       |       |
| Natural gas*(mmcf/d)*                                       | ** ** | **186.3**   |       | 104.5      |       | 78         | %          |
| Crude oil *(bbl/d)*                                         | ** ** | **37,500**  |       | 17,779     |       | 111        | %          |
| Natural gas  liquids*(bbl/d)*                               | ** ** | **5,858**   |       | 5,267      |       | 11         | %          |
| Crude oil and  NGL’s*(bbl/d)*                          | ** ** | **43,358**  |       | 23,046     |       | 88         | %          |
| Barrel of oil  equivalent*(boe/d,  6:1)*                    | ** ** | **74,409**  |       | 40,460     |       | 84         | %          |
| Average Prices(3)                                           |       |        |       |       |       |       |       |
| Natural gas*($/mcf)*                                        | ** ** | **7.01**    |       | 9.08       |       | -23        | %          |
| Natural gas*($/mcf) (including financial instruments)*      | ** ** | **7.62**    |       | 8.84       |       | -14        | %          |
| Crude oil*($/bbl)*                                          | ** ** | **60.61**   |       | 57.78      |       | 5          | %          |
| Crude oil*($/bbl) (including financial instruments)*        | ** ** | **56.97**   |       | 46.83      |       | 22         | %          |
| Natural gas  liquids*($/bbl)*                               | ** ** | **47.84**   |       | 40.44      |       | 18         | %          |
| Total*($/boe)*                                              | ** ** | **51.83**   |       | 54.19      |       | -4         | %          |
| Total*($/boe)(including financial instruments)*             | ** ** | **51.52**   |       | 48.76      |       | 6          | %          |
| *Drilling activity (gross)*                                 |       |        |       |       |       |       |       |
| Natural gas                                                 | ** ** | **205**     |       | 81         |       | —     |       |
| Oil                                                         | ** ** | **161**     |       | 87         |       | —     |       |
| Other                                                       | ** ** | **5**       |       | 2          |       | —     |       |
| Dry and  abandoned                                          | ** ** | **7**       |       | 2          |       | —     |       |
| Total gross wells                                           | ** ** | **378**     |       | 172        |       | —     |       |
| Total net wells                                             | ** ** | **174.4**   |       | 106.6      |       | —     |       |
| Success rate*(%)*                                           | ** ** | **98**      | **%**      | 99         | %          | —     |       |

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(1)   Includes the financial and operating resultsof StarPoint Energy Trust from the date of the merger, January 5, 2006 and theproperty acquisition from the date of closing August 31, 2006.

(2)   The merger of Acclaim Energy Trust (“Acclaim”)and StarPoint Energy Trust (“StarPoint”) has been accounted for as a purchaseof StarPoint by Acclaim.  Accordingly,the financial and operating results of StarPoint have been included from thedate of acquisition, January 5, 2006. The comparative results for 2005 are those of Acclaim only.  All disclosures of units and per unit amountsof Acclaim up to the merger on January 5, 2006 have been restated using theexchange ratio of 0.8333 of a Canetic unit for each Acclaim unit.

(3)   Please refer to the Advisory section at theend of this report for definitions of Non-GAAP terms and frequently recurringterms and abbreviations.  The payoutratio is based on cash distributions divided by funds flow from operations.

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**MANAGEMENT’SDISCUSSION AND ANALYSIS**

*ThisManagement’s Discussion and Analysis (“MD&A”) should be read in conjunctionwith the Consolidated Financial Statements and Notes thereto of CaneticResources Trust (“Canetic” or the “Trust”) for the year ended December 31,2006. This MD&A is dated March 8, 2007. The Consolidated Financial Statements have been prepared in accordancewith Canadian Generally Accepted Accounting Principles (“GAAP”).  This discussion provides Management’sanalysis of Canetic’s historical financial and operating results and providesestimates of Canetic’s future financial and operating performance based oninformation currently available.  Actualresults will vary from estimates and the variances may be material.  You should be aware that historical resultsare not necessarily indicative of future performance.  Readers are referred to the legal advisoriesregarding forward-looking information contained in the “Forward-LookingStatements” section of this MD&A.*

*Allreferences are to Canadian dollars unless otherwise indicated.  Natural gas volumes recorded in thousandcubic feet (“mcf”) are converted to barrels of oil equivalent (“boe”) using theratio of six (6) thousand cubic feet to one (1) barrel of oil (“bbl”).  BOE’s may be misleading, particularly if usedin isolation.  A BOE conversion ratio of6 mcf: one (1) bbl is based on an energy equivalent conversion method primarilyapplicable at the burner tip and does not represent a value equivalent at thewellhead.*

FORWARD-LOOKINGSTATEMENTS

Certain statementscontained in this MD&A constitute forward-looking statements or information(collectively “forward-looking statements”) within the meaning of applicable securitieslaws.  All statements other thanstatements of historical fact may be forward looking statements. Statementsrelating to “reserves” or “resources” are deemed to be forward-lookingstatements as they involve the implied assessment, based on certain estimatesand assumptions, that the reserves and resources described can be profitablyproduced 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-looking statements.We believe the expectations reflected in the forward-looking statements arereasonable but no assurance can be given that these expectations will prove tobe correct and such forward-looking statements are not guarantees of futureperformance and should not be unduly relied upon. These statements speak onlyas of the date of this MD&A.

In particular, thisMD&A contains forward-looking statements pertaining to the following:business strategies; production volumes, reserves volumes, operating and othercosts, 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; the impact of acquisitions; future tax treatment of incometrusts such as the Trust; and  liquidityand financial capacity.

The forward-lookingstatements contained in this MD&A are based on a number of expectations andassumptions that may prove to be incorrect. In addition to other assumptionsidentified in this MD&A, assumptions have been made regarding, among otherthings: that the Trust will continue to conduct its operations in a mannerconsistent with past operations; the continuance of existing (and in certaincircumstances, proposed) tax and royalty regimes; the general continuance ofcurrent industry conditions; the accuracy of the estimates of the Trust’sreserve volumes; the ability of Canetic to obtain equipment, services andsupplies in a timely manner to carry out its activities; the ability of Caneticto market oil and natural gas successfully; the timely receipt of requiredregulatory approvals; the ability of Canetic to obtain financing on acceptableterms; currency, exchange and interest rates; future oil and gas prices andfuture cost assumptions. No assurance can be given that these factors,expectations and assumptions 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 MD&A:volatility in market prices for oil and natural gas; risks and liabilitiesinherent in oil and natural gas including operations, exploration, development,exploitation, production, marketing and transportation risks; uncertaintiesassociated with estimating oil and natural gas reserves; 

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competition for, amongother things, capital, acquisitions of reserves, undeveloped lands and skilledpersonnel; incorrect assessments of the value of acquisitions; geological,technical, drilling and processing problems; risks and uncertainties involvinggeology of oil and gas deposits; unanticipated operating results or productiondeclines; fluctuations in foreign exchange, currency or interest rates andstock market volatility; changes in laws and regulations changes including butnot limited to those pertaining to income tax, environmental and regulatorymatters; failure to realize the anticipated benefits of acquisitions; health,safety and environmental risks; and  theother factors described in Canetic’s public filings from time to time(including under “Risk Management” in this MD&A and under “Risk Factors” inits Annual Information Form) available in Canada at www.sedar.com and in theUnited States at www.sec.gov. Readers are cautioned that this list of riskfactors should not be construed as exhaustive.

The forward-lookingstatements contained in this MD&A are expressly qualified by thiscautionary statement. Canetic undertakes no obligation to publicly update orrevise any forward-looking statements except as expressly required byapplicable securities law.

**Non-GAAPMeasures**

This MD&A refers tocertain financial measures that are not determined in accordance withGAAP.  These measures as presented do nothave any standardized meaning prescribed by Canadian GAAP and therefore theymay not be comparable with calculations of similar measures for other companiesor 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 termnet debt, which we define as long-term debt and working capital, to analyzeliquidity and capital resources.  Readersshould refer to the “Liquidity and Capital Resources” section of the MD&Afor a reconciliation of net debt.

We use the term payoutratio, which we define as cash distributions to unitholders divided by fundsflow from operations, to analyze financial and operating performance.  Readers should refer to the “CashDistributions” section of the MD&A for the calculation of payout ratio.

We use the termsoperating and cash netbacks to analyze margin and cash flow on each boeproduction.  Operating and cash netbacksshould not be viewed as an alternative to cash flow from operating activities,net earnings per trust unit or other measures of financial performancecalculated in accordance with GAAP. Readers should refer to the “Netbacks” section of the MD&A for areconciliation of operating and cash netbacks.

We use the term totalcapitalization, which we define as net debt including convertible debenturesplus unitholders’ equity, to analyze leverage. Total capitalization is not intended to represent the total funds fromequity and debt received by the Trust. Readers should refer to the “Liquidity and Capital Resources” section ofthe MD&A for a reconciliation of total capitalization.

Management believes that,in conjunction with results presented in accordance with GAAP,  these measures assist in providing a morecomplete understanding of certain aspects of the Trust’s results of operationsand financial performance.  Investors arecautioned however, that these measures should not be construed as analternative to measures determined in accordance with GAAP as an indication ofour performance.

OVERVIEW

The year 2006 was a very active year for Canetic.  In January, the Trust closed the acquisitionof StarPoint Energy Trust (“StarPoint”), doubling the size of the Trust byproduction volume and reserves.  Shortlythereafter, on February 15, 2006, Canetic began trading on the New York StockExchange under the symbol CNE.  InAugust, we closed another acquisition which added 13,500 boe/d of production,increased our weighting to natural gas from 41 percent to 47 percent andincreased our undeveloped land position by approximately 230,000 netacres.  This acquisition was financedwith a combination of trust units, convertible debentures and bank debttotalling approximately $930 million.

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Throughout theyear, Canetic was also very busy in the field. A total of 378 gross (174.4 net) wells were drilled in 2006, a year inwhich we spent $351.3 million on exploration and development activities.  This level of capital expenditures  will continue into the first quarter of 2007with the drilling of approximately 50 gross operated  wells. The year 2006 can be characterized as one where services were scarce,costs were escalating and labour was in short supply.  Although we expect these conditions toimprove somewhat in 2007, other factors such as the uncertainty of commodityprices and the announcement on October 31, 2006 of the Canadian federalgovernment’s proposed taxation of income trusts will impact the Trust’sperformance and strategic direction for 2007 and beyond.

FEDERAL GOVERNMENT’SPROPOSED TAXATION OF INCOME TRUSTS

On October 31,2006, the Federal Minister of Finance announced a Tax Fairness Plan forCanadians.  A principal component of thegovernment’s plan involved changing the taxation rules governingpublicly-listed income trusts and other public “flow-through entities”.  The creation of this new tax regime forpublicly listed flow-through entities reflects a fundamental shift in the taxsystem which will significantly impact the strategic direction of the incometrust model. Existing income trusts, such as Canetic, would  be subject to the new rules starting in 2011.

Under the proposedrules, distributions paid or payable to unitholders would no longer bedeductible at the Trust level,  and wouldbe subject to the new tax at a rate of 31.5 percent. The effect wouldessentially tax income in the trust structure in a similar manner and atsimilar rates to public corporations. It is expected that this tax would applyto all of the Trust’s income in excess of available tax shelter.  At the investor level, distributions will beconsidered taxable dividends and eligible for the dividend tax creditmechanism.  As such, the after-tax yieldto taxable Canadian resident investors in 2011 will remain approximately thesame.  The after-tax distribution yieldfor tax-deferred investors will be reduced significantly and be dependent uponthe tax shelter available in the Trust.

On December 15,2006, the Federal Government announced safe harbour guidance with respect to “normalgrowth” for flow-through entities. Existing income trusts, are provided anexemption from the new tax until 2011, provided these guidelines are respectedand the Trust does not experience “undue expansion” in the interim period.  The guidelines are measured by reference to atrust’s market capitalization on October 31, 2006 and allow cumulativeincreases in equity capital of 40 percent in 2007 and 20 percent each of thesubsequent three years providing for a doubling of equity capital to the end of2010.  Growth in excess of these limitswill be considered “undue expansion” and subject the Trust to the new taxregime prior to the end of the four year grace period.  We do not believe these guidelines willmaterially limit our near-term growth opportunities as the Trust could issueapproximately $4.5 billion in additional equity under these guidelines prior tothe end of 2010.

On December 21, 2006, theGovernment released detailed draft legislation with respect to the new taxproposals and have requested comments from interested stakeholders. Recently, thesetax proposals have been the subject of special hearings before the House ofCommons Standing Committee on Finance. The Committee has subsequently releasedtheir findings and have recommended substantial changes to the legislation ascurrently proposed including a reduction of the rate from 31.5% to 10% and anextension of the grace period for existing trusts from 4 years to 10 years. Itis unclear what effect, if any, these recommendations will have on the finalform of the legislation to be tabled in the House of Commons. We are alsopresently unable to predict when these proposals may become enacted into law.

These proposals have had significant implications forthe Trust and our investors.  Shortlyafter the announcement of the new rules, the valuation of Canetic and othertrusts was significantly reduced to reflect the loss of our tax advantage.  In 2011, when the rules are effective,distributions will be reduced to reflect the tax.  Although most taxable Canadian investorsshould be indifferent, the reduced distributions will be  a sunk cost to investors such as pensionfunds, registered retirement savings plans and non-resident investors who maynot be able to utilize the dividend tax credit.

Canetic iscurrently working with the Canadian Association of Income Funds (CAIF) and theCoalition of Canadian Energy Trusts to effect change to the legislation asproposed.  A main focus is ensuring thatthe facts related to income trusts are understood and that all data is madeavailable by the Minister to the investing public and other members ofParliament.

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It is premature at this time to determine what Canetic’scourse of action will be as 2011 approaches. Until the legislation is enacted, the rules fully understood and alloptions have been assessed, we are not in a position to commit to any strategicchanges.  In the short-term, we arefocused on our business and executing on our capital program.

HIGHLIGHTS

·                  OnJanuary 5, 2006, Acclaim Energy Trust (“Acclaim”) and StarPoint completed themerger of the two trusts to form Canetic.

Pursuant to the merger, each Acclaim unitholder received 0.8333 of aCanetic trust unit for each Acclaim unit held and each StarPoint unitholderreceived 1.000 Canetic trust unit for each StarPoint unit they held.  In addition, unitholders of both trustsreceived common shares and warrants in TriStar Oil and Gas Ltd. (“TriStar”), anew publicly traded junior exploration company with assets contributed by bothAcclaim and StarPoint.

The transaction between Acclaim and StarPoint was accounted for as anacquisition of StarPoint by Acclaim, therefore, Acclaim’s results and operatinghistory have been utilized for comparative purposes.  The operating and financial results for theperiod include the StarPoint operations from the date of closing, January 5,2006.

·                  Acclaimand StarPoint were delisted on January 6, 2006 and Canetic began trading on theToronto Stock Exchange (symbol:  CNE.UN)on January 9, 2006.  Subsequently,Canetic began trading on the New York Stock Exchange (symbol:  CNE) on February 15, 2006.

·                  Effectivewith the merger, Canetic increased its monthly distribution to $0.23 per unit,representing an 18 percent increase for Acclaim unitholders and a 5 percentincrease for StarPoint unitholders.  ToDecember 31, 2006, this represented 51 continuous months of consistent orincreasing distributions.  To reflect theimpact of lower commodity prices, we reduced our distributions to $0.19 perunit commencing with the January 2007 distributions paid February 15, 2007.

·                  OnAugust 31, 2006, Canetic closed the acquisition of a private company whichincluded primarily natural gas interests in central Alberta and northeasternBritish Columbia (the “Samson acquisition”). Canetic financed the $930 million acquisition with a $690 million boughtdeal equity and debenture financing which closed August 24, 2006, as well asthrough available credit facilities.

Production from the Samson acquisition at closing was approximately13,500 boe/d comprised of 70.0 million cubic feet per day (“mmcf/d”) of naturalgas and 1,600 barrels per day (“bbl/d”) of crude oil and natural gasliquids.  At that time, the acquisitionincreased Canetic’s overall production in excess of 80,000 boe/d and balancedthe asset portfolio to 53 percent crude oil and natural gas liquids and 47percent natural gas.  The acquisitionalso increased Canetic’s total proved plus probable reserves to nearly 275million boe.  The assets arecomplementary to Canetic’s current properties in the Peace River Arch and Rockyareas.  The transaction was effectiveJune 1, 2006.

Under the bought dealfinancing, Canetic issued 20,769,000 trust units at $22.15 per trust unit forgross proceeds of $460 million and $230 million principal amount of 6.5%convertible extendible unsecured subordinated debentures.  The debentures have a face value of $1,000per debenture, a coupon of 6.5%, a maturity date of December 31, 2011 and areconvertible into trust units of Canetic at a price of $26.55 per trust unit.  The convertible debentures pay interest semi-annuallyon June 30 and December 31.  The initialinterest payment was made on December 31, 2006.

·                  Annualproduction averaged approximately 74,409 boe/d for 2006, an increase of  84 percent from 40,460 boe/d in 2005.  Average production in the fourth quartertotalled 80,276 boe/d compared to 74,475 boe/d in the third quarter of 2006.

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·                  Funds flow fromoperations totalled $750.1 million ($3.64 per basic unit) in 2006 compared to$360.5 million ($4.04 per basic unit) in 2005, an increase of 108 percent.  During the fourth quarter, funds flow fromoperations totalled $170.1 million ($0.76 per basic unit) an increase of 60percent from $106.5 million ($1.16 per basic unit) realized in the same periodlast year.  Funds flow reported for thethird quarter of 2006 totalled $200.3 million ($0.95 per basic unit).  The decrease in the fourth quarter waslargely attributed to a 21 percent decrease in average oil prices in thequarter relative to the third quarter of 2006.

·                  Operationally,we completed the most active development program in Canetic’s history withdevelopment expenditures of $351.3 million. In 2006, Canetic’s drilling program resulted in the drilling of 378gross (174.4 net) wells, with an overall success rate of 98 percent.

·                  Canetic’sdevelopment program replaced 76 percent of its 2006 production on a proved plusprobable basis at a finding and development (F&D) cost of $16.93 per boe,excluding future development capital and $19.21 per boe including futuredevelopment capital.

·                  Canetic’stotal capital program including acquisitions replaced 237% of its 2006production on a proved plus probable basis at a finding, development andacquisition (FD&A) cost of $20.41 per boe, excluding future developmentcapital and $23.30 per boe including future development capital.

·                  Inaddition, Canetic replaced production in 2006 at a very strong efficiency of$20,300 per boe/d based on 2006 exit rates. These very strong efficiencies were achieved during a period when theTrust was very active integrating the two large acquisitions completed in 2006.

SELECTED CONSOLIDATEDFINANCIAL AND OPERATING INFORMATION

The results of operationsin 2006 in comparison to 2005 and 2004 are outlined under the section, “Resultsof Operations”.

**A)  ANNUAL FINANCIAL INFORMATION**
| **Year ended December 31**                | ** ** | **2006**      | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|----------------------------------------------------------|------------|---------------|------------|------------|------------|------------|------------|
| **($000s except per unit amounts)**  | ** ** | ** **    | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Petroleum  and natural gas sales**                     | ** ** | **1,407,754** |       | 800,249    |       | 521,514    |       |
| **Funds  flow from operations**                          | ** ** | **750,146**   |       | 360,475    |       | 233,473    |       |
| Per unit - basic(1)(2)                                   | ** ** | **3.64**      |       | 4.04       |       | 3.13       |       |
| Per unit - diluted(1)(2)                                 | ** ** | **3.57**      |       | 3.98       |       | 3.09       |       |
|                                                     |       |          |       |       |       |       |       |
| **Net  earnings**                                        | ** ** | **223,101**   |       | 65,848     |       | 31,263     |       |
| Per unit - basic(1)(2)                                   | ** ** | **1.08**      |       | 0.74       |       | 0.42       |       |
| Per unit - diluted(1)(2)                                 | ** ** | **1.06**      |       | 0.73       |       | 0.42       |       |
| **Balance  Sheet Information**                           |       |          |       |       |       |       |       |
| Total  distributions                                     | ** ** | **583,528**   |       | 208,477    |       | 176,741    |       |
| Distributions  per unit(2)                               | ** ** | **2.76**      |       | 2.34       |       | 2.34       |       |
| Total assets                                             | ** ** | **5,830,976** |       | 1,571,097  |       | 1,559,201  |       |
| Working capital  deficiency                              | ** ** | **29,794**    |       | 45,630     |       | 27,800     |       |
| Long-term debt                                           | ** ** | **1,289,678** |       | 309,146    |       | 283,845    |       |
| Unitholders’  equity                                | ** ** | **3,506,915** |       | 764,583    |       | 780,980    |       |
| Weighted average  trust units outstanding***(thousands)* |       | **206,081**   |       | 89,331     |       | 74,650     |       |
| Trust units outstanding  at year end***(thousands)*      | ** ** | **225,796**   |       | 91,583     |       | 86,313     |       |

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*(1)  Whencalculating the weighted average number of units at the end of a quarter, allunits outstanding from the previous quarter are deemed to be outstanding forthe entire period, whereas in the year to date calculation those units areweighted according to the date of issue. Consequently, the addition of the quarterly per unit results, will notadd to the annual earnings per unit.*

*(2)  All units of Acclaim up to the merger on January 5, 2006, have beenrestated using the exchange ratio of 0.8333 of a Canetic trust unit for eachAcclaim trust unit.*

 

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**B)QUARTERLY FINANCIAL AND OPERATING INFORMATION**
| ** **                                              | ** ** | **2006**         | ** ** | **2005**          | ** ** |
|---------------------------------------------------------|------------|------------------|------------|-------------------|------------|
| **Earnings Information**                           | ** ** | **Dec. 31** | ** ** | **Sept. 30** | ** ** | **Jun. 30** | ** ** | **Mar. 31** | ** ** | **Dec. 31** | ** ** | **Sept. 30** | ** ** | **Jun. 30** | ** ** | **Mar. 31** | ** ** |
| **($000s except per unit amounts)** | ** ** | ** **       | ** ** | ** **        | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                              |       |             |       |              |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Production                                              |       |             |       |              |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Oil and NGLs***(bbl/d)*                                 |       | **43,402**       | ** ** | **44,239**        | ** ** | **42,391** | ** ** | **43,388** |   | 21,915 |   | 22,323 |   | 23,249 |   | 24,741 |   |
| Natural gas***(mmcf/d)*                                 |       | **221.2**        | ** ** | **181.4**         | ** ** | **166.0** | ** ** | **176.1** |   | 105.8 |   | 107.4 |   | 100.6 |   | 104.1 |   |
| Boe/d                                                   |       | **80,276**       | ** ** | **74,475**        | ** ** | **70,061** | ** ** | **72,737** |   | 39,541 |   | 40,227 |   | 40,017 |   | 42,089 |   |
| Petroleum and natural  gas sales                        |       | **347,701**      | ** ** | **368,502**       | ** ** | **341,205** | ** ** | **350,346** |   | 234,098 |   | 217,449 |   | 177,501 |   | 171,201 |   |
| Funds flow from  operations                             |       | **170,084**      | ** ** | **200,268**       | ** ** | **185,053** | ** ** | **194,741** |   | 106,477 |   | 92,679 |   | 80,516 |   | 80,803 |   |
| Per unit - basic*(1)(2)*                                |       | **0.76**         | ** ** | **0.95**          | ** ** | **0.92** | ** ** | **0.97** |   | 1.16 |   | 1.03 |   | 0.92 |   | 0.92 |   |
| Per unit -  diluted*(1)(2)*                             |       | **0.75**         | ** ** | **0.93**          | ** ** | **0.89** | ** ** | **0.96** |   | 1.14 |   | 1.02 |   | 0.91 |   | 0.91 |   |
| Net earnings (loss)                                     |       | **(21,632**      | **)**      | **102,663**       | ** ** | **82,875** | ** ** | **59,195** |   | 48,662 |   | 6,538 |   | 27,473 |   | (16,825 | ) |
| Per unit - basic*(1)(2)*                                |       | **(0.10**        | **)**      | **0.49**          | ** ** | **0.41** | ** ** | **0.29** |   | 0.53 |   | 0.07 |   | 0.31 |   | (0.19 | ) |
| Per unit -  diluted*(1)(2)*                             |       | **(0.10**        | **)**      | **0.48**          | ** ** | **0.40** | ** ** | **0.29** |   | 0.53 |   | 0.07 |   | 0.31 |   | (0.19 | ) |
| Distributions declared                                  |       | ** **       | ** ** | ** **        | ** ** | ** ** | ** ** | ** ** |   |   |   |   |   |   |   |   |   |
| Per unit                                                |       | **0.69**         | ** ** | **0.69**          | ** ** | **0.69** | ** ** | **0.69** |   | 0.5850 |   | 0.5850 |   | 0.5850 |   | 0.5850 |   |

----

*(1)  Whencalculating the weighted average number of units at the end of a quarter, allunits outstanding from the previous quarter are deemed to be outstanding forthe entire period, whereas in the year to date calculation those units areweighted according to the date of issue. Consequently, the addition of the quarterly per unit results, will notadd to the annual earnings per unit.*

*(2)  All unitsof Acclaim up to the merger on January 5, 2006, have been restated using theexchange ratio of 0.8333 of a Canetic trust unit for each Acclaim trust unit.*

Production volumesaveraged 80,276 boe/d during the three months ended December 31, 2006, anincrease of 8 percent from 74,475 boe/d reported for the third quarter of2006.  Crude oil prices weakened with theWest Texas Intermediate (“WTI”) price averaging US$60.22 per barrel in the fourthquarter, as compared to US$70.55 per barrel in the third quarter of 2006.  The AECO Daily Spot price for natural gashowever, averaged $6.69/mcf in the fourth quarter as compared to $5.55/mcfduring the third quarter of 2006.  Theresults of operations include a full quarter of Samson productivity.

The transaction withStarPoint was accounted for as a purchase of StarPoint by Acclaim. Accordingly,the financial and operating results for the year ended December 31, 2006,include those of the StarPoint assets from the date of acquisition, January 5,2006.  Comparative results are those ofAcclaim only.

Quarter over quarterpetroleum and natural gas sales are influenced by increases in productionvolumes and changes in commodity prices. Although commodity prices have increased significantly since the fourthquarter of 2004, some of the gains in oil prices were taken back during thisquarter.  In combination with increasedproduction volumes from the ChevronTexaco property acquisition in June 2004,the StarPoint merger in January 2006 and the most recent acquisition whichclosed August 31, 2006, petroleum and natural gas sales have increased.

The variation of netearnings, quarter over quarter, is primarily a result of changes in depletionrates, the provision for future income taxes and accounting for unrealizedgains and losses on financial derivatives. Net earnings in the fourth quarter reflects a $95.4 million unrealizedhedging gain based on the mark-to-market price of crude oil and natural gas atDecember 31, 2006

RESULTS OFOPERATIONS

**PRODUCTION**

Production volumesaveraged 74,409 boe/d in 2006, compared to 40,460 boe/d in 2005 (2004 - 33,421boe/d).  The 84 percent increase inaverage 2006 production results from the StarPoint and Samson acquisitionswhich closed on January 5 and August 31, 2006 respectively.  At the time of acquisition, the StarPointassets were producing approximately 35,000 boe/d and the Samson assetsapproximately 13,500 boe/d.

7

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| **Production By Product**           | ** ** | **2006**   | ** ** | **2005** | ** ** | **2004** | ** ** |
|-----------------------------------------------|------------|------------|------------|----------|------------|----------|------------|
| Natural gas  (mmcf/d)                         | ** ** | **186.3**  |       | 104.5    |       | 94.2     |       |
| Crude oil  (bbl/d)                            | ** ** | **37,500** |       | 17,779   |       | 13,731   |       |
| Natural gas  liquids (bbl/d)                  | ** ** | **5,858**  |       | 5,267    |       | 3,988    |       |
| Barrels of oil  equivalent (boe/d)            | ** ** | **74,409** |       | 40,460   |       | 33,421   |       |
| Percentage  natural gas                       | ** ** | **42**     | **%**      | 43       | %          | 47       | %          |
| Percentage crude oil  and natural gas liquids | ** ** | **58**     | **%**      | 57       | %          | 53       | %          |

Natural gas salesaveraged 186.3 mmcf/d in 2006, 78 percent higher than the 104.5 mmcf/d reportedfor the same period in 2005 (2004 — 94.2 mmcf/d). Crude oil and NGLs productionaveraged 43,358 bbl/d, an increase of 88 percent from 23,046 bbl/d reported inthe prior year (2004 — 17,719  bbl/d).
| **Production By Jurisdiction** | ** ** | **United States** | ** ** | **B.C.** | ** ** | **Alberta** | ** ** | **Sask.** | ** ** | **Manitoba** | ** ** | **Total** | ** ** |
|------------------------------------------|------------|------------------------|------------|----------|------------|-------------|------------|-----------|------------|--------------|------------|-----------|------------|
| Natural gas  (mmcf/d)                    |       | 1.9                    |       | 21.6     |       | 155.0       |       | 7.8       |       | —       |       | 186.3     |       |
| Crude oil  (bbl/d)                       |       | 268                    |       | 201      |       | 19,073      |       | 16,765    |       | 1,193        |       | 37,500    |       |
| Natural gas  liquids (bbl/d)             |       | —                 |       | 200      |       | 5,621       |       | 37        |       | —       |       | 5,858     |       |
| Total (boe/d)                            |       | 585                    |       | 4,001    |       | 50,527      |       | 18,102    |       | 1,193        |       | 74,409    |       |
| Percentage                               |       | 0.8                    | %          | 5.4      | %          | 67.9        | %          | 24.3      | %          | 1.6          | %          | 100.0     | %          |

For the three monthsended December 31, 2006, natural gas sales averaged 221.2 mmcf/d, 109 percentmore than the 105.8 mmcf/d reported for the fourth quarter 2005.  Crude oil and liquids production increased 98percent to 43,402 bbl/d from 21,915 bbl/d reported for the same period a yearearlier.

Production volumesfluctuate day to day based on pipeline capacity restrictions, natural declines,inclement weather, down time due to normal repairs and maintenance and thetiming of when new wells are brought on production.  In 2006, our quarterly production volumeswere impacted by unplanned turnarounds, tie-in delays and spring break-up.  Fourth quarter production was affected by aplanned September turnaround at Mitsue which extended into October andunseasonably cold weather in November and December which increased well downtime.

**COMMODITYPRICES**
| **Benchmark Prices - ***(Annual Average)* | ** ** | **2006**   | ** ** | **2005** | ** ** | **2004** | ** ** |
|---------------------------------------------------------------|------------|------------|------------|----------|------------|----------|------------|
| WTI crude oil  (US$/bbl)                                      | ** ** | **66.25**  |       | 56.56    |       | 41.40    |       |
| NYMEX natural  gas (US$/mcf)                                  | ** ** | **7.07**   |       | 8.55     |       | 6.14     |       |
| AECO natural gas  monthly index ($/mcf)                       | ** ** | **6.98**   |       | 8.48     |       | 6.79     |       |
| Canadian/U.S. dollar exchange  rate                           | ** ** | **0.8819** |       | 0.8253   |       | 0.7683   |       |

The price of West TexasIntermediate crude averaged US$66.25/bbl during 2006, up 17 percent from theaverage price of US$56.56/bbl for the same period in 2005. WTI during thefourth quarter decreased 6 percent from an average of US$70.55/bbl in the thirdquarter of 2006.

West Texas Intermediateat Cushing, Oklahoma is the benchmark for North American crude oil prices.  Canadian crude oil prices are determined byrefiners’ postings at major market hubs as Edmonton and Hardisty, Alberta.  Canadian prices adjust WTI for theCanadian/U.S. exchange rate, transportation and quality differentials.  NYMEX natural gas prices are referenced fromHenry Hub, Louisiana.  Western Canadiannatural gas prices are referenced from AECO Hub in Alberta and are adjusted forheat content.
| **Average Prices ***(before financial derivatives)* | ** ** | **2006**  | ** ** | **2005** | ** ** | **2004** | ** ** |
|-------------------------------------------------------------------------|------------|-----------|------------|----------|------------|----------|------------|
| Natural gas  ($/mcf)                                                    | ** ** | **7.01**  |       | 9.08     |       | 6.91     |       |
| Crude oil  ($/bbl)                                                      | ** ** | **60.61** |       | 57.78    |       | 46.44    |       |
| Natural gas liquids ($/bbl)                                             | ** ** | **47.84** |       | 40.44    |       | 34.18    |       |

 

8

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For the year endedDecember 31, 2006, we received an average oil price of $60.61/bbl as comparedto $57.78/bbl for the comparable period in 2005. Our average oil price duringthe quarter decreased 21 percent from an average of $67.27/bbl reported duringthe third quarter of 2006. High crude oil inventory levels across North Americaand pipeline apportionment problems in southeast Saskatchewan have causedCanetic’s corporate average oil price differential to widen in relation to thebenchmark NYMEX WTI futures contract over the past year.

Our average natural gasprice was $7.01/mcf for the year ended December 31, 2006 as compared to$9.08/mcf during the same period in 2005. The fourth quarter natural gas price averaged $6.90/mcf as compared to$6.21/mcf in the third quarter.

The AECO Daily Index gasprice averaged $6.43/mcf during 2006, down 26 percent from the average price of$8.73/mcf for the same period in 2005. The AECO Daily Index price for thefourth quarter of 2006 was 21 percent higher than the third quarter 2006 priceof $5.55/mcf.

**COMMODITYPRICE RISK MANAGEMENT**

The prices we receive forour petroleum and natural gas can fluctuate significantly due to supply anddemand fundamentals which are influenced by weather patterns, the economicenvironment or political uncertainty.

Our commodity price riskmanagement program is designed to provide price protection on a portion of ourfuture production in the event of an adverse commodity price movement, whileretaining the opportunity to participate in favorable price movements.  This practice allows us to generate stablecash flow for distributions and to ensure positive economic returns on capitaldevelopment and acquisition activities.

During 2006, we recordeda realized financial derivative loss of $8.5 million as compared to a loss of$80.2 million in 2005 (2004 - $39.4 million).

The followingcommodity commitments have been put in place for 2007 and beyond as notedbelow:

**COMMODITY CONTRACTS**
| ** **                     | ** ** | ** **       | ** ** | ** **       | ** ** | ** **       | ** ** | ** **       | ** ** | **Annual Average** | ** ** |
|--------------------------------|------------|------------------|------------|------------------|------------|------------------|------------|------------------|------------|-------------------------|------------|
| **Natural Gas**           | ** ** | **Q1 2007** | ** ** | **Q2 2007** | ** ** | **Q3 2007** | ** ** | **Q4 2007** | ** ** | **2007**                | ** ** | **2008** | ** ** |
| Fixed Price  Volume (Gj/d)     |       | 5,000            |       | 50,000           |       | 50,000           |       | 20,163           |       | 31,250                  |       | — |   |
| Fixed Price  Average ($CDN/Gj) |       | $                | 8.47       |             | $          | 7.32             |       | $                | 7.32       |                    | $          | 7.51 |   | $ | 7.40 |   | — |   |
| Collar Volume  (Gj/d)          |       | 100,000          |       | 80,000           |       | 80,000           |       | 86,667           |       | 86,667                  |       | 22,500 |   |
| Collar Floors  ($CDN/Gj)       |       | $                | 7.70       |             | $          | 6.74             |       | $                | 6.74       |                    | $          | 6.92 |   | $ | 7.06 |   | $ | 7.00 |   |
| Collar Caps  ($CDN/Gj)         |       | $                | 13.08      |             | $          | 9.62             |       | $                | 9.62       |                    | $          | 10.74 |   | $ | 10.90 |   | $ | 11.23 |   |
| Total Volume Hedged  (Gj/d)    |       |  105,000    |       |  130,000    |       |  130,000    |       |  106,830    |       |  117,917           |       | 22,500 |   |

 
| **Crude Oil**                              | ** ** | **Q1 2007** | ** ** | **Q2 2007** | ** ** | **Q3 2007** | ** ** | **Q4 2007** | ** ** | **2007**     | ** ** | **2008** | ** ** |
|-------------------------------------------------|------------|------------------|------------|------------------|------------|------------------|------------|------------------|------------|--------------|------------|----------|------------|
| CDN Denominated  Fixed Price Volume (bbl/d)     |       | 8,000            |       | 8,000            |       | 8,000            |       | 8,000            |       | 8,000        |       | 250      |       |
| CDN Denominated  Fixed Price Average ($CDN/bbl) |       | $                | 67.26      |             | $          | 67.26            |       | $                | 67.26      |         | $          | 67.26    |       | $ | 67.26 |   | $ | 72.20 |   |
| US Denominated  Fixed Price Volume (bbl/d)      |       | 1,500            |       | 1,500            |       | 1,500            |       | 1,500            |       | 1,500        |       | —   |       |
| US Denominated  Fixed Price Average ($US/bbl)   |       | $                | 48.11      |             | $          | 48.11            |       | $                | 48.11      |         | $          | 48.11    |       | $ | 48.11 |   | — |   |
| Collar Volume  (bbl/d)                          |       | 6,000            |       | 6,000            |       | 6,000            |       | 6,000            |       | 6,000        |       | 5,000    |       |
| Collar Floors  ($US/bbl)                        |       | $                | 58.00      |             | $          | 58.00            |       | $                | 58.00      |         | $          | 58.00    |       | $ | 58.00 |   | $ | 63.00 |   |
| Collar Caps  ($US/bbl)                          |       | $                | 80.76      |             | $          | 80.76            |       | $                | 80.76      |         | $          | 80.76    |       | $ | 80.76 |   | $ | 83.23 |   |
| Total Volume Hedged  (bbl/d)                    |       |  15,500     |       |  15,500     |       |  15,500     |       |  15,500     |       |  15,500 |       | 5,250    |       |

**CURRENCY RISK MANAGEMENT**

The Canadian dollaraveraged US$0.8819 during 2006 as compared to US$0.8261 for the same periodlast year.  As the price of WTI crude oilis quoted in U.S. dollars, appreciation in the Canadian dollar reduces theaverage price received for our production. Canetic mitigates the impact of exchange rate fluctuations by eitherentering into foreign exchange contracts directly or executing some portion ofour crude oil swaps in Canadian dollars. In 2006, Canetic had no foreign exchange contracts, but had entered intocontracts for 6,000 bbl/d of its crude oil production using Canadian dollardenominated swaps.

9

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**PETROLEUM AND NATURAL GAS SALES**
| **Revenue(1) **               | ** ** | **2006**      | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|------------------------------------|------------|---------------|------------|------------|------------|------------|------------|
| **($000s)**                        | ** ** | ** **    | ** ** | ** ** | ** ** | ** ** | ** ** |
| Crude oil and  natural gas liquids | ** ** | **931,884**   |       | 454,124    |       | 283,292    |       |
| Natural gas                        | ** ** | **475,870**   |       | 346,125    |       | 238,222    |       |
| Petroleum and natural  gas sales   | ** ** | **1,407,754** |       | 800,249    |       | 521,514    |       |

----

(1)          Before financialderivative gains and losses.

Crude oil and NGLs salesbefore derivative gains and losses increased 105 percent during the year to$931.9 million from $454.1 million in 2005 (2004 - $283.3 million).  The increase is attributable to strongcommodity prices throughout the year and the impact of increased productionvolumes associated with the Samson and StarPoint acquisitions.  Average daily production of crude oil andNGLs increased to 43,358 bbl/d from 23,046 bbl/d in 2005.

Natural gas salesincreased 38 percent year-over-year from $346.1 million to $475.9 million.  Natural gas prices in 2006 were 23 percentlower than those received in 2005, which negatively impacted revenue.  Average daily sales of natural gas increased78 percent to 186.3 mmcf/d in 2006 from 104.5 mmcf/d in 2005 primarily as aresult of the volumes acquired from the acquisitions made during the year.

For the threemonths ended December 31, 2006, petroleum and natural gas revenue totalled$347.7 million as compared to $234.1 million for the same period in 2005.  The increase is attributable to higherproduction volumes.

**ROYALTIES**
| **Royalties **                     | ** ** | **2006**    | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|-----------------------------------------|------------|-------------|------------|------------|------------|------------|------------|
| **($000s)**                             | ** ** | ** **  | ** ** | ** ** | ** ** | ** ** | ** ** |
| Royalties, net  of ARTC                 | ** ** | **258,260** |       | 175,723    |       | 103,957    |       |
| % of petroleum  and natural gas revenue | ** ** | **18.3**    | **%**      | 22.0       | %          | 19.9       | %          |
| $/boe                                   | ** ** | **$**       | **9.51**   |       | $          | 11.90      |       | $ | 8.50 |   |
|                                         |            |             |            |            |            |            |            |  |  |  |

We pay royalties to theowners of the mineral rights with whom we hold leases, including provincialgovernments.  Overriding royalties arealso paid to other parties according to contracts.  In Alberta, where we produce the majority ofour natural gas, a Crown royalty is invoiced on the Crown’s share of productionbased on a monthly established Alberta Reference Price. The Alberta ReferencePrice is a monthly weighted average price of gas consumed in Alberta andnatural gas exported from Alberta reduced for transportation and marketingallowances.  For 2006, the AlbertaReference Price averaged $6.22/Gj or about $6.56/mcf.  There is a maximum rate of 30 percent for newgas and 35 percent on old gas.  The vastmajority of our gas production is from new natural gas.  In the 2006 gas price environment, we weresubject to the maximum rates. Natural gas cost allowance, low productivity andother incentive schemes serve to reduce our effective royalty rate.

The majority ofour oil production is in Alberta and Saskatchewan.  Royalty rates in both Alberta andSaskatchewan vary depending on the rate of production, oil prices andapplicable incentives.  For the yearended December 31, 2006, royalties totalled $258.3 million as compared to$175.7 million during the same period a year earlier.  As a percentage of sales, royalties averaged18.3 percent during 2006 as compared to 22 percent in the same period in 2005.

For 2006, royaltiesaveraged $9.51/boe or approximately 18.3 percent of Canetic’s total petroleumand natural gas sales price (before hedging) of $51.83/boe.  This compares to $11.90/boe or 22.0 percentof average sales price reported for the same period in 2005 (2004 -$8.50/boe).  The reduced effectiveroyalty rate results from the acquisition of properties that carry a lowerroyalty burden.

For the three monthsended December 31, 2006, royalties totalled $63.6 million as compared to $52.3million during the same period a year earlier due to higher productionvolumes.  During the fourth quarter,royalties as a percentage of sales averaged approximately 18.3 percent ascompared to 16.9 percent in the third quarter.

10

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**OPERATING COSTS**
| **Operating Costs **                     | ** ** | **2006**    | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|----------------------------------------------------|------------|-------------|------------|------------|------------|------------|------------|
| **($000s)**                                        | ** ** | ** **  | ** ** | ** ** | ** ** | ** ** | ** ** |
| Operating costs  before unit-based compensation    | ** ** | **249,623** |       | 125,448    |       | 98,001     |       |
| Unit-based  compensation:                          |       |        |       |       |       |       |       |
| Cash expense                                       | ** ** | **412**     |       | 124        |       | 251        |       |
| Non-cash unit-based compensation                   | ** ** | **2,107**   |       | 4,074      |       | 1,102      |       |
| Total operating  costs and unit-based compensation | ** ** | **252,142** |       | 129,646    |       | 99,354     |       |
| $/boe before  unit-based compensation              | ** ** | **$**       | **9.19**   |       | $          | 8.49       |       | $ | 8.01 |   |
| $/boe after unit-based  compensation               | ** ** | **$**       | **9.28**   |       | $          | 8.78       |       | $ | 8.12 |   |

Producing petroleum andnatural gas involves many field activities including lifting the oil and naturalgas to surface, as well as treating, processing, gathering and storing thecommodities.  Other costs involved in theproduction function include those incurred to operate and maintain the wellsalong with the leases and well equipment.

Assets most suitablefor the trust environment are generally more mature with more predictableproduction profiles.  Operating costsassociated with these types of assets will generally be higher on aunit-of-production basis reflecting the amount of manpower, repairs andmaintenance required to keep the wells on production and the recoverytechniques utilized to extract the reserves.

Our operating costs net of processing fees andunit-based compensation increased to $249.6 million compared to $125.4 millionduring the same period a year earlier (2004 - $98.0 million).  On a unit-of-production basis, operatingcosts averaged $9.19/boe compared to $8.49/boe for the prior year (2004 -$8.01/boe). A general theme throughout the industry in 2005 and 2006 has beenhigher field service costs including higher energy and fuel costs, labour,trucking and other related mechanical services. These increases, combined with the operating cost structures inheritedfrom acquisitions made, caused operating costs year-over-year to increase on aunit-of-production basis.  In addition,certain assets within our portfolio, primarily in east central Alberta, aresignificantly more costly to operate. Although these assets increase our operating costs in total and on a perunit basis, they provide positive cash flow during a high commodity pricecycle.
| **Production Expense Variance Analysis ** | ** ** | ** ** | ** ** | **% Change** | ** ** |
|---------------------------------------------------------------|------------|------------|------------|-------------------|------------|
| **($000s)**                                                   | ** ** | ** ** | ** ** | ** **        | ** ** |
| Reported  operating costs - 2005                              |       | 125,448    |       |              |       |
| Increase due to  production volumes                           |       | 105,260    |       | 85                |       |
| Increase due to  increased costs                              |       | 18,915     |       | 15                |       |
| Total increase                                                |       | 124,175    |       | 100               |       |
| Reported operating  costs - 2006                              |       | 249,623    |       |              |       |

During the fourthquarter, operating costs before unit-based compensation totalled $71.4 millionor $9.67 per boe as compared to $32.9 million or $9.05 per boe in 2005.  Our estimate of $8.50 - $9.50 per boeoperating costs for the fourth quarter was impacted by a plant turnaround atAcheson in October and cold weather and associated repairs and maintenance inNovember required to restore production. The increase also reflects cost pressures due to industry activity.

Canetic was alsoactive in 2006 in completing operational activities associated with the EUB’sguidelines for the suspension of existing wells, resulting in incremental costsincurred throughout the year.

Although operatingcosts year-over-year increased on a unit-of-production basis, we are committedto managing operational efficiencies and maximizing field netbacks in all areaswhere we do business.  As we continue toexperience higher field costs throughout our asset base, considerable effortand focus is being given to operational efficiencies which will controloperating costs on a unit-of- production basis. To date, Canetic has been successful in maintaining control of ouroperational costs in a high priced operating environment and will continue tofocus on doing so in 2007.

11

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**PETROLEUMAND NATURAL GAS TRANSPORTATION**
| **Transportation ** | ** ** | **2006**   | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|--------------------------|------------|------------|------------|------------|------------|------------|------------|
| **($000s)**              | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Transportation  expense  | ** ** | **18,968** | ** ** | **9,897**  |       | 8,807      |       |
| $/boe                    | ** ** | **$**      | **0.70**   | ** ** | **$**      | **0.67**   |       | $ | 0.72 |   |
|                          |            |            |            |            |            |            |            |  |  |  |

Transportation costs are defined by the point of legalcustody transfer of the commodity and is dependent upon the type of productbeing sold, location of the producing asset, availability of pipeline capacityand sales point of the product.

For crude oil, Canetic sellsall of its production at the lease.  Thepurchaser picks up the production at the lease and pays Canetic a price for theapplicable crude type based upon a price posted at the appropriate market hub,less the transportation costs between that market hub and the lease.  For natural gas, Canetic transports itsnatural gas from the plant gate to certain established market hubs such as AECOC in Alberta, at which point title transfers to the purchaser.  In both cases, transportation costsassociated with getting natural gas and clean marketable oil to the point oftitle transfer are shown separately as a transportation expense.

**NETBACKS**

Operating netbacksrepresent the profit margin associated with the production and sale ofpetroleum and natural gas.  For 2006, ournetbacks were influenced by our product mix, commodity prices, financialderivative losses, royalty rates, the appreciation in the Canadian dollar andhigher operating costs.
| **Cash Netbacks Per Unit Of Production** | ** ** | **Oil**          | ** ** | ** **  | ** ** | ** **           | ** ** | ** **     | ** ** |
|-------------------------------------------------------------------|------------|------------------|------------|-------------|------------|----------------------|------------|----------------|------------|
| ** **                                                        | ** ** | **Conventional** | ** ** | **Heavy**   | ** ** | **Natural Gas** | ** ** | **NGL’s** | ** ** | **Total** | ** ** |
| ** **                                                        | ** ** | **($/bbl)**      | ** ** | **($/bbl)** | ** ** | **($/mcf)**          | ** ** | **($/bbl)**    | ** ** | **($/boe)** | ** ** |
| Sales Price                                                       |       | 63.39            |       | 43.57       |       | 7.01                 |       | 47.84          |       | 51.83 |   |
| Less:                                                             |       |             |       |        |       |                 |       |           |       |   |   |
| Royalties                                                         |       | 10.58            |       | 6.54        |       | 1.42                 |       | 11.77          |       | 9.51 |   |
| Operating costs                                                   |       | 10.80            |       | 12.97       |       | 1.44                 |       | —         |       | 9.19 |   |
| Transportation                                                    |       | 0.24             |       | 0.23        |       | 0.22                 |       | 0.25           |       | 0.70 |   |
| Cash Netbacks Per Unit  Of Production                             |       | 41.77            |       | 23.83       |       | 3.93                 |       | 35.82          |       | 32.43 |   |

Components of our netbacks are as follows:
| **Netbacks **                               | ** ** | **2006**   | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|--------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| **($/boe)**                                      | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Petroleum and  natural gas revenue               | ** ** | **51.83**  |       | 54.19      |       | 42.63      |       |
| Less:                                            |       |       |       |       |       |       |       |
| Royalties                                        | ** ** | **9.51**   |       | 11.90      |       | 8.50       |       |
| Operating costs                                  | ** ** | **9.19**   |       | 8.49       |       | 8.01       |       |
| Transportation                                   | ** ** | **0.70**   |       | 0.67       |       | 0.72       |       |
| Cash net  operating income                       | ** ** | **32.43**  |       | 33.13      |       | 25.40      |       |
| General and  administrative                      | ** ** | **1.46**   |       | 1.46       |       | 1.39       |       |
| Interest on long  term debt                      | ** ** | **1.98**   |       | 0.93       |       | 0.98       |       |
| Interest on  convertible debentures              | ** ** | **0.32**   |       | 0.30       |       | 0.37       |       |
| Realized loss on  financial derivatives          | ** ** | **0.31**   |       | 5.43       |       | 3.21       |       |
| Capital tax                                      | ** ** | **0.64**   |       | 0.54       |       | 0.21       |       |
| Cash netback  from operations                    | ** ** | **27.72**  |       | 24.47      |       | 19.24      |       |
| Non-cash  unit-based compensation                | ** ** | **0.62**   |       | 1.90       |       | 0.74       |       |
| Depletion, depreciation  and amortization        | ** ** | **23.76**  |       | 15.82      |       | 14.68      |       |
| Accretion                                        | ** ** | **0.42**   |       | 0.31       |       | 0.25       |       |
| Unrealized  (gain) loss on financial derivatives | ** ** | **(3.51**  | **)**      | 1.40       |       | 0.91       |       |
| Future income  taxes (recovery)                  | ** ** | **(1.78**  | **)**      | 0.58       |       | 0.10       |       |
| Net earnings                                     | ** ** | **8.21**   |       | 4.46       |       | 2.56       |       |

 

12

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**GENERAL AND ADMINISTRATIVE EXPENSES**
| **General and Administrative Expenses ** | ** ** | **2006**    | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|--------------------------------------------------------------|------------|-------------|------------|------------|------------|------------|------------|
| **($000s)**                                                  | ** ** | ** **  | ** ** | ** ** | ** ** | ** ** | ** ** |
| G&A expenses                                             | ** ** | **60,631**  |       | 31,885     |       | 21,356     |       |
| Overhead recoveries                                          | ** ** | **(20,925** | **)**      | (10,299    | )          | (4,343     | )          |
| Cash G&A expenses  before unit-based compensation        | ** ** | **39,706**  |       | 21,586     |       | 17,013     |       |
| Unit-based  compensation:                                    |       |        |       |       |       |       |       |
| Cash expense                                                 | ** ** | **2,336**   |       | 695        |       | 1,421      |       |
| Non-cash  unit-based compensation                            | ** ** | **11,941**  |       | 23,091     |       | 6,242      |       |
| Total G&A and  unit-based compensation                   | ** ** | **53,983**  |       | 45,372     |       | 24,676     |       |
| $/boe before unit-based  compensation                        | ** ** | **$**       | **1.46**   |       | $          | 1.46       |       | $ | 1.39 |   |
| $/boe after unit-based compensation                          | ** ** | **$**       | **1.99**   |       | $          | 3.07       |       | $ | 2.02 |   |

General andadministrative expenses net of overhead recoveries and unit-based compensationtotalled $39.7 million in 2006, as compared to $21.6 million in 2005 (2004 -$17.0 million).  On a unit-of-productionbasis, general and administrative expenses averaged $1.46 per boe as comparedto $1.46 per boe for the same period in 2005 (2004 - $1.39 per boe).

During 2006, weincreased our head office staff in order to properly manage our business.  The level of activity in the trust sectorincreased the cost of hiring qualified candidates and retaining existingemployees and consultants.  In 2006,approximately 66 percent of our total general and administrative expenses werelabour related, including salary, benefits and consulting fees.

For the threemonths ended December 31, 2006, general and administrative expenses increasedslightly to $1.62 per boe (net of unit-based compensation), reflecting costsassociated with hiring additional permanent staff, leasing additional officespace and integrating the assets acquired during the third quarter.

**Unit-basedCompensation**

On December 19, 2005, theunitholders of Canetic approved a unit award incentive plan.  The plan authorizes the Board of Directors togrant rights to acquire up to five percent of the trust units outstanding todirectors, officers, employees and consultants of the Trust and itsaffiliates.  These rights consist ofRestricted Trust Units (“RTUs”) and Performance Trust Units (“PTUs”).  The number of PTUs granted is dependent onthe performance of the Trust relative to a peer comparison group of petroleumand natural gas trusts and other companies or other criteria the Board ofDirectors may determine.  A holder of anRTU or PTU may elect, subject to consent of the Trust, to receive cash uponvesting in lieu of the number of units to be issued.  The plan provides for adjustments to thenumber of units issued based on the cumulative distributions of the Trustduring the period that the RTU or PTU  isoutstanding.

The compensation issuedupon vesting of the PTUs is dependant upon the performance of the Trustcompared to its peers.  The performancemultiplier is based on our percentile rank of total unitholder return comparedto a select group of peers approved by the Board of Directors.  Total return is calculated as the sum of thechange in market price plus distributions in the period divided by the openingmarket price.  The performance multiplierranges from zero, where our total return is less than the 35th percentile, to two, if our performance exceedsthe 75th percentile.

For the year endedDecember 31, 2006, the Trust recorded a compensation expense of $16.8 million(2005 - $28.0 million) and capitalized unit-based compensation of $3.4 million(2005 - $11.0 million).  Upon vesting,the obligation may be settled in units or cash, therefore, the amounts due inthe next year of $7.3 million (2005 — $40.8 million) has been classified as acurrent liability.  The compensationliability is remeasured each period at the current market price.  The December 31, 2006 compensation liabilitywas based on the period-end closing price of $16.44 and the number of RTUs andPTUs outstanding at that time and the number of PTUs expected to vest using aPTU multiplier of 0.6.

As of December 31, 2006,there were 915,916 RTUs and 1,386,377 PTUs outstanding.

13

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**NTEREST EXPENSE ON LONG-TERM DEBT**
| **Interest Expense ** | ** ** | **2006**      | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|---------------------------------|------------|---------------|------------|------------|------------|------------|------------|
| **($000s)**                     | ** ** | ** **    | ** ** | ** ** | ** ** | ** ** | ** ** |
| Interest expense                | ** ** | **53,809**    |       | 13,752     |       | 12,054     |       |
| Bank loans,  December 31        | ** ** | **1,289,678** |       | 309,146    |       | 283,845    |       |
| Debt to funds flow              | ** ** | **1.7**       |       | 0.9        |       | 1.2        |       |

Interest expense, representing interest on bank debtincreased to $53.8 million or $1.98 per boe from $13.8 million or $0.93 per boea year earlier (2004 - $12.1 million or $0.98/boe).  In addition to slightly higher interest ratesdue to increases in the Bank of Canada lending rate in 2006, average debtlevels have increased as a result of the corporate and property acquisitionsmade during the year.  At December 31,2006, $1.29 billion was drawn under our facility.  Although interest rates continue to befavourable and are not expected to increase substantially in the short-term,interest expense in future periods will reflect our higher debt levels.  Average interest rates incurred by Caneticduring 2006 averaged approximately 5.1 percent.

For the three monthsended December 31, 2006, interest expense increased to $19.6 million reflectingthe increased debt levels incurred to finance the Samson acquisition.

**INTERESTEXPENSE ON CONVERTIBLE DEBENTURES**

Interest expense onconvertible debentures totalled $8.6 million for the year ended December 31,2006 as compared to $4.4 million for the same period in 2005.  During the year, debentures totalling $230.0million were issued in conjunction with the Samson acquisition.  At December 31, 2006, debentures totalling$260.6 million remain outstanding.

**INTERESTRATE RISK MANAGEMENT**

Canetic has assumedthrough the StarPoint arrangement, fixed interest rate swaps between January 6,2006 and September 30, 2007 covering $40.0 million of principal, with interestrates varying between 3.58 percent and 3.65 percent, plus a stamping fee.  The fair value of the fixed interest swaps atDecember 31, 2006 was a gain of approximately $0.3 million.

**DEPLETION,DEPRECIATION AND AMORTIZATION**

The current yearprovision for depletion, depreciation and amortization totalled $645.2 millionas compared to $233.7 million in 2005 (2004 - $179.6 million).  On a unit-of-production basis, depletion,depreciation and amortization costs averaged $23.76 per boe as compared to$15.82 per boe in 2005 (2004 - $14.68 per boe). The increase in the 2006 depletion rate results from the assets acquiredin 2006.

**FINANCIALDERIVATIVES**

Accounting standardsrequire that we determine the fair value of our financial contracts and recorda liability or asset at the end of each accounting period.  Any changes in the fair value of thefinancial contracts are included in net earnings for the period.  At December 31, 2006, we recorded a currentfinancial derivative liability of $1.1 million and a long-term financialderivative asset of $6.2 million.  Theestimated fair value is based on a mark-to-market calculation as at December31, 2006 to settle the financial contracts. The actual gain or loss realized upon settlement could varysignificantly due to fluctuations in commodity prices.  At December 31, 2006, Canetic recorded anunrealized financial derivative gain of $95.4 million (2005-loss of $20.6million) which represents the change in the mark-to-market calculations fromDecember 31, 2005.
| **Gain (Loss) On Financial Derivatives ** | ** ** | **2006**   | ** ** | **2005**   | ** ** |
|--------------------------------------------------------------------|------------|------------|------------|------------|------------|
| **($000s)**                                                        | ** ** | ** ** | ** ** | ** ** | ** ** |
|                                                               |       |       |       |       |       |
| Realized cash  loss on financial derivatives                       |       | **(8,465** | )          | (80,157    | )          |
| Unrealized gain  (loss) on financial derivatives                   |       | **95,371** |       | (20,635    | )          |
| Gain (loss) on  financial derivatives                              |       | **86,906** |       | (100,792   | )          |

14

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**ASSET RETIREMENT OBLIGATIONS**

The total futureasset retirement obligation was estimated by management based on the Trust’snet ownership interest in all wells and facilities, estimated costs to reclaimand abandon the facilities and the estimated timing of the costs to be incurredin future periods.  The costs areexpected to be incurred over an average of 15 years.  The estimated cash flow has been calculatedusing a credit adjusted risk free discount rate of 8 percent and an inflationrate of 2 percent.

As of December 31,2006, the amount to be recorded as the fair value of the liability wasestimated to be $191.9 million (December 31, 2005 - $68.2 million).  During this year, Canetic incurred $16.9 million(2005 - $6.3 million) of actual abandonment and reclamation costs and recordedaccretion of $11.4 million (2005 - $4.6 million).

**INCOMETAXES**

**Future Income Taxes**

Future income taxes arisefrom differences between the accounting and tax bases of assets and liabilitiesof certain operating subsidiaries of the Trust. The future taxes recorded on the balance sheet are expected to berecovered over time through interest and/or royalty payments to the Trust fromits operating subsidiaries.  The Trust isa taxable entity under Canadian tax law and is subject to cash taxes only tothe extent that income is not distributed or distributable to itsunitholders.  As the Trust is required todistribute all of its taxable income to unitholders, the Trust is not expectedto be subject to current or future income taxes.

For the periodended December 31, 2006, a future tax recovery of $48.3 million was included inincome compared to a future tax expense of $8.6 million in 2005.  The change year-over-year was mainly due to asignificant increase in temporary differences arising from the acquisition ofStarPoint Energy Trust and increased depletion on recognition of purchase priceincrements.  Also, reductions to futurecorporate tax rates were enacted during the year by Federal, Alberta andSaskatchewan governments resulting in a future tax recovery of $32million.  These were offset by a futuretax expense of $33.6 million related to unrealized hedging gains.

On October 31, 2006, theFederal Government announced a proposal to introduce a new tax on publiclytraded income trusts beginning in 2011. On December 21, 2006, draft legislation to implement these proposals wasreleased for comment.  If the legislationbecomes enacted as currently proposed, the Trust will effectively becomesubject to tax on earnings in excess of available tax pools, in a similarmanner as a corporation.  It isanticipated that future taxes would be then be adjusted to include temporarydifferences between accounting and tax bases of assets and liabilities at theTrust level.

**Current Income Taxes**

In general, both currentand future income taxes are transferred to the unitholder level through variousinterest and/or royalty payments.  Thereare some corporate entities in the underlying structure which hold minorityinterests in some of the Trust’s operating partnerships which subject them to asmall amount of current income tax.  TheTrust has provided $2 million in this respect for the current year and $4million in respect of prior periods.

**Capital Taxes**

Federal LargeCorporations Tax was eliminated effective January 1, 2006 and thus no amount isprovided for federal capital taxes in respect of 2006.

The Trust has recorded$12 million of capital tax for the year, of this amount, $11 million relates tothe Saskatchewan Resource Surcharge and is higher compared to the previous yeardue to an increase in oil and gas revenue earned in the Province ofSaskatchewan, a result of the significant number of Saskatchewan propertiesadded through the StarPoint acquisition.

15

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| **Estimated Income Tax Pools ** | ** ** | **December 31, 2006** | ** ** |
|-----------------------------------------------------|------------|---------------------------------|------------|
| **($000s)**                                         | ** ** | ** **                      | ** ** |
| Undepreciated  capital costs                        |       | 505,232                         |       |
| Canadian oil and  gas property expenses             |       | 611,509                         |       |
| Canadian  exploration expenses                      |       | 2,966                           |       |
| Canadian  development expenses                      |       | 285,662                         |       |
| Non-capital losses                                  |       | 276,270                         |       |
| Financing  charges                                  |       | 48                              |       |
| Total estimated income  tax pools                   |       | 1,681,687                       |       |

**CAPITAL EXPENDITURES**

Petroleum and natural gasreserves are a non-renewable resource. As they are produced, our objective is to replace those reserves througha combination of property acquisitions and internal drillingopportunities.  In 2005 and 2006, we havecontinued to increase our focus on upgrading the quality of our asset basethrough acquisition, exploiting our reserve base, drilling new wells andoptimizing existing production.
| **Capital Expenditures **               | ** ** | **2006**      | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|---------------------------------------------------|------------|---------------|------------|------------|------------|------------|------------|
| **($000s)**                                       | ** ** | ** **    | ** ** | ** ** | ** ** | ** ** | ** ** |
|                                              |       |          |       |       |       |       |       |
| Land                                              | ** ** | **14,868**    |       | 13,361     |       | 3,792      |       |
| Geological and  geophysical                       | ** ** | **2,783**     |       | 3,139      |       | 1,067      |       |
| Drilling and  completion                          | ** ** | **215,593**   |       | 100,182    |       | 56,493     |       |
| Production  equipment and facilities              | ** ** | **118,044**   |       | 55,539     |       | 30,418     |       |
|                                              |       |          |       |       |       |       |       |
| Net development  expenditures                     | ** ** | **351,288**   |       | 172,221    |       | 91,770     |       |
| Major  acquisitions                               |       |          |       |       |       |       |       |
| StarPoint                                         | ** ** | **2,511,746** |       | —     |       | —     |       |
| Samson                                            | ** ** | **924,635**   |       | —     |       | —     |       |
| Producing properties                              | ** ** | **23,869**    |       | —     |       | 477,168    |       |
| Minor property  acquisitions                      | ** ** | **32,416**    |       | 13,554     |       | 10,447     |       |
| Minor property  dispositions                      | ** ** | **(17,167**   | **)**      | (4,610     | )          | (9,280     | )          |
|                                              |       |          |       |       |       |       |       |
| Net capital  expenditures                         | ** ** | **3,826,787** |       | 181,165    |       | 570,105    |       |
| Office                                            | ** ** | **8,134**     |       | 4,667      |       | 3,609      |       |
| Asset retirement  obligation - change in estimate | ** ** | **56,537**    |       | 11,319     |       | 13,043     |       |
| Asset retirement  obligation - Samson             | ** ** | **18,228**    |       | —     |       | —     |       |
| Capitalized  non-cash compensation                | ** ** | **3,365**     |       | 11,016     |       | —     |       |
| Other non-cash                                    | ** ** | **11,000**    |       | —     |       | —     |       |
| Total capital  expenditures                       | ** ** | **3,924,051** |       | 208,167    |       | 586,757    |       |

During 2006, expenditures for exploration anddevelopment activities totalled $351.3 million as compared to $172.2 million in2005 (2004 — $91.8 million).  A total of378 gross (174.4 net) wells were drilled during the year, including 118 gross(50.4 net) wells in the fourth quarter, compared to 82 gross (52.4 net) wellsduring the fourth quarter 2005 resulting in 161 gross (81.9 net) oil wells and205 gross****(85.4 net) natural gas wells.  The increase reflects the larger opportunityassociated with our assets as a result of the acquisitions made in 2006.  Of the total wells drilled in 2006, 102 gross(90.6 net) were operated by Canetic resulting in 64 gross (58.0 net) oil wellsand 32 gross (26.9 net) natural gas wells.

16

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The Trust alsocompleted two major acquisitions in 2006 totalling $3.5 billion.  The StarPoint transaction was completed byway of a Plan of Arrangement whereby unitholders of Acclaim received 0.8333units of Canetic for each unit held and unitholders of StarPoint received oneCanetic unit for each unit held.  Costsassociated with the transaction were financed through our bank facility.  The merger was strategic in that it providedunitholders with a high quality asset base; a reserve base in excess of 230million boe on a proved plus probable basis; a reserve life index in excess of9 years; a diversified production base weighted 60 percent towards primarilylight oil and a high quality low risk development drilling program.

On August 31, 2006, weclosed the Samson acquisition which included properties in British Columbia andcentral Alberta.  We acquired approximately13,500 boe/d of production, 40.1 million boe of proved plus probable reservesand 230,000 net acres of undeveloped land. The acquisition was financed by the issuance of 20.8 million trust unitsfor net proceeds of $437 million, as well as $230.0 million principal ($220.8million net) of 6.5% convertible, extendible, unsecured, subordinateddebentures.  The balance of thetransaction was financed with bank debt. In addition, Canetic purchased approximately $89.1 million of workingcapital on May 31, 2006 including $77 million of cash which was financed withlong-term debt.

**Sources Of Funding Net CapitalExpenditures**
| ** **                | ** ** | ** **               | ** ** | **Acquisitions** | ** ** | ** ** | ** ** |
|---------------------------|------------|--------------------------|------------|------------------|------------|------------|------------|
| **($ million)**      | ** ** | **Net Development** | ** ** | **StarPoint**    | ** ** | **Samson** | ** ** | **Other** | ** ** | **Total** | ** ** |
| * *                  | ** ** | ** **               |       |             |       |       |       |   |   |   |   |
| Net Capital  Expenditures |       | 351.3                    |       | 2,511.7          |       | 924.6      |       | 39.2 |   | 3,826.8 |   |
| Percentage  funded by:    | ** ** | ** **               |       |             |       |       |       |   |   |   |   |
| Cashflow                  |       | 47                       | %          | —           |       | —     |       | — |   | 5 | % |
| DRIP                      |       | 14                       | %          | —           |       | —     |       | — |   | 1 | % |
| Issuance of equity        |       | —                   |       | 99               | %          | 47         | %          | — |   | 77 | % |
| Issuance of debentures    |       | —                   |       | —           |       | 24         | %          | — |   | 6 | % |
| Bank debt                 |       | 39                       | %          | 1                | %          | 29         | %          | 100 | % | 11 | % |
|                      |       | 100                      | %          | 100              | %          | 100        | %          | 100 | % | 100 | % |

**GOODWILL**

The Trust recognizesgoodwill on corporate acquisitions when the total purchase price exceeds thefair value of the net identifiable assets and liabilities of the acquiredentity.  Goodwill is tested annually atyear-end for impairment or as events occur that could result inimpairment.  Impairment is recognized andcharged to income in the period in which the impairment occurs when the fairvalue of the Trust is less than the book value of the Trust.  A write down of goodwill was not required atDecember 31, 2006 or 2005.

The goodwill balance of$922.0 million arose primarily as a result of the StarPoint acquisition in2006.  The balance was determined basedon the excess of total consideration plus the future income tax liability lessthe fair value of the assets acquired for accounting purposes.

**LIQUIDITYAND CAPITAL RESOURCES**

As an oil  and gas trust we have a declining asset baseand therefore rely on acquisitions and ongoing development activities tomitigate production and reserve declines. Future production volumes and reserves are highly dependent on oursuccess in exploiting our asset base and acquiring addition reserves.

The increase in capitalexpenditures in 2006 reflects both the costs associated with maintaining thelarger producing asset base we now have, as well as the execution of growthprograms that continue to be developed as we increase our operational knowledgeof the properties acquired over the past three years.

17

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We finance ouroperations and capital activities primarily with funds generated from operatingactivities, but also through the issuance of trust units, debentures andborrowings from our credit facility.  Theamount of equity we raise through the issuance of trust units depends on manyfactors including projected cash needs, availability of funding through othersources, our unit price and the state of the capital markets.  We believe our sources of cash, including bankdebt, will be sufficient to fund our operations and anticipated capitalexpenditure program in 2007 as well as make monthly distribution payments.  Our ability to fund will also depend onperformance and is subject to commodity prices and other economic conditionswhich are beyond our control.

In August 2006, inconnection with the Samson acquisition, Canetic completed a $690 million boughtdeal equity and debenture issue.  The netproceeds of $657.8 million in addition to bank borrowings under our credit facilitywere utilized to fund the acquisition. In addition, Canetic purchased working capital at May 31, 2006, of $89.1million by drawing upon its bank facility. Working capital includedapproximately $77 million of cash.  Underthe terms of the agreement Canetic will be kept whole in the event ofuncollectability or valuation of working capital.

Canetic’s capitalstructure at December 31, 2006 is reconciled as follows:
| ** **                          | ** ** | **2006**      | ** ** | **2005** | ** ** |
|-------------------------------------|------------|---------------|------------|----------|------------|
| **($000s except per unit amounts)** | ** ** | **Amount**    | ** ** | **%**    | ** ** | **$/unit** | ** ** | **Amount** | ** ** | **%** | ** ** | **$/unit** | ** ** |
| Debt                                |       |          |       |     |       |   |   |   |   |   |   |   |   |
| Bank debt                           | ** ** | **1,289,678** | ** ** | **25**   | ** ** | **5.71** |   | 309,146 |   | 28 |   | 3.38 |   |
| Working capital  deficiency         | ** ** | **29,794**    | ** ** | **1**    | ** ** | **0.13** |   | 45,630 |   | 4 |   | 0.50 |   |
| Net debt                            | ** ** | **1,319,472** | ** ** | **26**   | ** ** | **5.84** |   | 354,776 |   | 32 |   | 3.88 |   |
| Convertible debentures              | ** ** | **258,959**   | ** ** | **5**    | ** ** | **1.15** |   | 16,289 |   | 1 |   | 0.18 |   |
| Unitholders’ equity            | ** ** | **3,506,915** | ** ** | **69**   | ** ** | **15.53** |   | 764,583 |   | 67 |   | 8.35 |   |
| Total capitalization                | ** ** | **5,085,346** | ** ** | **100**  | ** ** | **22.52** |   | 1,135,648 |   | 100 |   | 12.41 |   |

**BANK DEBT**

Canetic has an unsecuredcovenant based credit facility with a syndicate of financial institutions inthe amount of $1.6 billion including a $50.0 million operating facility.  The facility carries floating interest rateswhich range between 65.0 and 115.0 basis points over Banker’s Acceptancerates.  This facility was increased inthe third quarter from $1.1 billion upon closing of the Samsonacquisition.  The loan has a maturitydate of May 31, 2009 and is reviewed annually and may be extended at the optionof the lender for an additional 1 year period. The loan has therefore been classified as long-term on the balance sheet.

At December 31, 2006,$1.29 billion was drawn under the facility. Working capital liquidity ismaintained by drawing from and repaying the unutilized credit facility asneeded.  At December 31, 2006, Canetichad a working capital deficiency of $29.8 million including a financialderivative liability of $1.1 million. The increase in bank debt year-over-year includes $293.5 million drawnon the facility related to the acquisition of Samson which closed on August 31,2006.  As part of this acquisition,Canetic acquired $89.1 million of working capital including $77 million of cashat May 31, 2006.

Our net debt at December31, 2006 and 2005 is reconciled as follows:
| ** **                  | ** ** | **December 31, 2006** | ** ** | **December 31, 2005** | ** ** |
|-----------------------------|------------|---------------------------------|------------|---------------------------------|------------|
| **($000s)**                 | ** ** | ** **                      | ** ** | **Acclaim**                     | ** ** | **StarPoint(1)** | ** ** | **Total** | ** ** |
| Bank debt                   | ** ** | **1,289,678**                   |       | 309,146                         |       | 434,123 |   | 743,269 |   |
| Working capital  deficiency | ** ** | **29,794**                      |       | 45,630                          |       | 101,477 |   | 147,107 |   |
| Net debt                    | ** ** | **1,319,472**                   |       | 354,776                         |       | 535,600 |   | 890,376 |   |

----

(1)          As at closing, January5, 2006

18

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**CONVERTIBLEDEBENTURES**

As at December 31,2006, we had convertible debentures outstanding of $260.7 million.  The debentures consist of  the StarPoint 9.4% convertible, unsecured,subordinated debentures; StarPoint 6.5% convertible, extendible, unsecured,subordinated debentures; Acclaim 8% convertible, extendible, unsecured,subordinated debentures; Acclaim 11% convertible, extendible, unsecured,subordinated debentures and Canetic 6.5% convertible, extendible, unsecured,subordinated debentures.  The StarPointdebentures are described further below.

The debentures areconvertible into Canetic trust units at the following conversion prices:

·                                          StarPoint9.4% Debentures (CNE.DB.A) - $16.02. Each $1,000 principal amount of 9.4%Debentures is convertible into approximately 62.42 Canetic trust units;

·                                          StarPoint6.5% Debentures (CNE.DB.B) - $18.96. Each $1,000 principal amount of StarPoint6.5% Debentures is convertible into approximately 52.74 Canetic trust units;

·                                          Acclaim8% Debentures (CNE.DB.C) - $15.56. Each $1,000 principal amount of 8%Debentures is convertible into approximately 64.27 Canetic trust units;

·                                          Acclaim11% Debentures (CNE.DB.D) - $11.24. Each $1,000 principal amount of 11%Debentures is convertible into approximately 88.97 Canetic trust units; and

·                                          Canetic6.5% Debentures (CNE.DB.E) - $26.55. Each $1,000 principal amount of Canetic6.5% Debentures is convertible into approximately 37.66 Canetic trust units.

The following tables area summary of the dollar value of issuances and conversions of the convertibledebentures:
| *** ***                | ** ** | **9.4%**       | ** ** | **6.5%**       | ** ** | **8%**         | ** ** | **11%**        | ** ** | **6.5%**       | ** ** | ** ** | ** ** |
|-----------------------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|------------|------------|
| **($000s)**                 | ** ** | **(CNE.DB.A)** | ** ** | **(CNE.DB.B)** | ** ** | **(CNE.DB.C)** | ** ** | **(CNE.DB.D)** | ** ** | **(CNE.DB.E)** | ** ** | **Total**  | ** ** |
|                        |       |           |       |           |       |           |       |           |       |           |       |       |       |
| Balance,  December 31, 2004 |       | —         |       | —         |       | 72,901         |       | 6,562          |       | —         |       | 79,463     |       |
| Converted to  units         |       | —         |       | —         |       | (59,330        | )          | (3,844         | )          | —         |       | (63,174    | )          |
| Balance,  December 31, 2005 |       | —         |       | —         |       | 13,571         |       | 2,718          |       | —         |       | 16,289     |       |
| Acquisition of  StarPoint   |       | 9,255          |       | 43,944         |       | —         |       | —         |       | —         |       | 53,199     |       |
| Acquisition of  Samson      |       | —         |       | —         |       | —         |       | —         |       | 227,470        |       | 227,470    |       |
| Converted to  units         |       | (3,633         | )          | (26,123        | )          | (5,525         | )          | (1,021         | )          | —         |       | (36,302    | )          |
| Balance, December 31,  2006 |       | 5,622          |       | 17,821         |       | 8,046          |       | 1,697          |       | 227,470        |       | 260,656    |       |

 
| ** **                                        | ** ** | **9.4%**       | ** ** | **6.5%**       | ** ** | **8%**         | ** ** | **11%**        | ** ** | **6.5%**       | ** ** | ** ** | ** ** |
|---------------------------------------------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|------------|------------|
| **Units Issuable Upon Conversion** | ** ** | **(CNE.DB.A)** | ** ** | **(CNE.DB.B)** | ** ** | **(CNE.DB.C)** | ** ** | **(CNE.DB.D)** | ** ** | **(CNE.DB.E)** | ** ** | **Total**  | ** ** |
| **(000s)**                                        | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** | ** ** | ** ** |
|                                              |       |           |       |           |       |           |       |           |       |           |       |       |       |
| Balance,  December 31, 2004                       |       | —         |       | —         |       | 5,401          |       | 672            |       | —         |       | 6,073      |       |
| Converted to  units                               |       | —         |       | —         |       | (4,395         | )          | (394           | )          | —         |       | (4,789     | )          |
| Balance,  December 31, 2005                       |       | —         |       | —         |       | 1,006          |       | 278            |       | —         |       | 1,284      |       |
| Adjustment to  conversion ratio                   |       | —         |       | —         |       | (135           | )          | (36            | )          | —         |       | (171       | )          |
| Acquisition of  StarPoint                         |       | 576            |       | 2,313          |       | —         |       | —         |       | —         |       | 2,889      |       |
| Acquisition of  Samson                            |       | —         |       | —         |       | —         |       | —         |       | 8,663          |       | 8,663      |       |
| Converted to  units                               |       | (225           | )          | (1,373         | )          | (354           | )          | (90            | )          | —         |       | (2,042     | )          |
| Balance, December 31,  2006                       |       | 351            |       | 940            |       | 517            |       | 152            |       | 8,663          |       | 10,623     |       |

 

19

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On August 24,2006, Canetic issued $230.0 million principal amount of 6.5% convertible,extendible, unsecured, subordinated debentures to partially fund the acquisitionof Samson.  The conversion feature wasvalued at $2.5 million which has been allocated to equity.  The debentures have a face value of $1,000per debenture, a coupon of 6.5%, a maturity date of December 31, 2011 and areconvertible at any time, at the option of the holder, into the trust units ofCanetic at a conversion price of $26.55 per trust unit.  The Trust may redeem the debentures in wholeor in part at a redemption price of $1,050 per debenture after December 31,2009 and at a redemption price of $1,025 per debenture after December 31, 2010and before the maturity date.

On June 15, 2004, Acclaimissued $75.0 million principal amount of 8% convertible, extendible, unsecured,subordinated debentures.  The debentureshave a face value of $1,000 per debenture, a coupon of 8.0%, a maturity date ofAugust 31, 2009 and are convertible at any time, at the option of the holder,into trust units of Canetic at a price of $15.56 per trust unit.  The Trust may redeem the debentures in wholeor in part at a redemption price of $1,050 per debenture after August 31, 2007and at a redemption price of $1,025 per debenture after August 31, 2008 andbefore the maturity date.

In December 2002, Acclaimissued $45.0 million principal amount of 11% convertible, extendible,unsecured, subordinated debentures.  Thedebentures have a face value of $1,000 per debenture, a coupon of 11%, amaturity date of December 31, 2007 and are convertible at any time, at theoption of the holder, into trust units of Canetic at a price of $11.24 pertrust unit.  The Trust may redeem thedebentures in whole or in part at a redemption price of $1,025 per debenturebefore the maturity date.

**ConvertibleDebentures Assumed on Acquisition of StarPoint**

StarPoint issued $60.0million of 6.5% convertible, extendible, unsecured, subordinated debentures(the “StarPoint 6.5% Debentures”) on May 26, 2005.  The StarPoint 6.5% Debentures mature on July31, 2010 and are convertible at any time, at the option of the holder, into thetrust units of Canetic at a conversion price of $18.96 per trust unit.  The StarPoint 6.5% Debentures are notredeemable at the option of the Trust on or before July 31, 2008. After July31, 2008, and prior to the maturity date, the StarPoint 6.5% Debentures may beredeemed in whole or in part, at a price of $1,050 per debenture after July 31,2008 and after July 31, 2009 at a price of $1,025 per debenture.

In connection with theStarPoint/APF Energy Trust Combination, and pursuant to a debenture agreementdated June 27, 2005, the 9.4% Debentures were assumed by StarPoint. The 9.4%unsecured, subordinated, convertible debentures are convertible at the holder’soption into fully paid and non-assessable trust units of Canetic at any timeprior to July 31, 2008 at a conversion price of $16.02 per trust unit.  The 9.4% Debentures are redeemable at $1,050per 9.4% Debenture, in whole or in part, after July 31, 2006 and redeemable at$1,025 per debenture after July 31, 2007 and before maturity.

**TRUST UNIT CAPITAL**

As at December 31, 2006,we had issued capital of 225.8 million units and as at March 7, 2007, we hadissued capital of 226.6 million units. If all the outstanding convertible debentures were converted into units,a total of 236.4 million units would have been outstanding as at December 31,2006 and 237.2 million units as at March 7, 2007.

The merger of Acclaim andStarPoint on January 5, 2006, occurred pursuant to a Plan of Arrangement inwhich Canadian unitholders could elect to exchange their units on atax-deferred basis.  Each Acclaimunitholder received  0.8333 of a Canetictrust unit for each unit held and each StarPoint unitholder received 1.0000Canetic trust unit for each unit they held. A total of 106.2 million units were issued pursuant to theArrangement.  Also pursuant to theArrangement, all exchangeable shares were exchanged for trust units.

20

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| **a) Trust Units**               | ** **   | **2006**        | ** **   | **2005**           | ** **   |
|--------------------------------------------|--------------|-----------------|--------------|--------------------|--------------|
| ** **                                 | *** *** | **Units ** | *** *** | **Amount* *** | *** *** | **Units(1) ** | *** *** | **Amount** | *** *** |
| ** **                                 | ** **   | **(000s)**      | ** **   | **($000s)**        | ** **   | **(000s)** | ** ** | **($000s)** | ** ** |
| Balance,  beginning of year                | ** **   | **91,583**      | ** **   | **1,087,459**      |         | 86,313 |   | 1,003,294 |   |
| Issued:                                    | ** **   | ** **      | ** **   | ** **         |         |   |   |   |   |
| Bought deal  financing, net of costs       | ** **   | **20,769**      | ** **   | **437,001**        |         | — |   | — |   |
| Pursuant to  equity offering, net of costs | ** **   | **—**      | ** **   | **—**         | **#**        | — |   | (350 | ) |
| Employee Unit  Savings Plan                | ** **   | **274**         | ** **   | **6,184**          |         | 89 |   | 1,646 |   |
| Distribution  reinvestment plan            | ** **   | **2,470**       | ** **   | **44,825**         |         | 456 |   | 8,492 |   |
| Issued pursuant  to Arrangement            | ** **   | **106,242**     | ** **   | **2,562,563**      |         | — |   | — |   |
| Properties  contributed to TriStar         | ** **   | **—**      | ** **   | **(5,000**         | **)**        | — |   | — |   |
| Conversion of  debentures                  | ** **   | **2,042**       | ** **   | **36,302**         |         | 3,990 |   | 63,174 |   |
| Conversion of  debentures - equity portion | ** **   | **—**      | ** **   | **4,636**          |         | — |   | — |   |
| Conversion of  exchangeable shares         | ** **   | **358**         | ** **   | **3,804**          |         | 357 |   | 4,033 |   |
| Unit award  incentive plan                 | ** **   | **2,058**       | ** **   | **46,696**         |         | 378 |   | 7,170 |   |
|                                       | ** **   | ** **      | ** **   | ** **         |         |   |   |   |   |
| **Balance, end of year**                   | ** **   | **225,796**     | ** **   | **4,224,470**      |         | 91,583 |   | 1,087,459 |   |

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*(1)  All disclosures of Acclaim units up to the merger January 5, 2006have been restated using the exchange ratio of 0.8333 of a Canetic unit foreach Acclaim unit.*
| ** **                                     | ** **   | **Units**  | ** ** | **Amount**  | ** **   |
|------------------------------------------------|--------------|------------|------------|-------------|--------------|
| **b) Exchangeable Shares**           | *** *** | **(000s)** | ** ** | **($000s)** | *** *** |
| Balance,  December 31, 2004                    |         | 673        |       | 7,837       |         |
| Shares exchanged                               |         | (357       | )          | (4,033      | )            |
| Adjustment to exchange ratio for distributions |         | 42         |       | —      |         |
| Balance,  December 31, 2005                    |         | 358        |       | 3,804       |         |
| Shares exchanged                               |         | (358       | )          | (3,804      | )            |
| **Balance, December 31, 2006**                 | ** **   | **—** | ** ** | **—**  | ** **   |

**FUNDS FLOW FROM OPERATIONS**

Funds flow fromoperations as presented is not intended to represent operating cash flow oroperating profits for the period nor should it be viewed as an alternative tocash flow from operating activities, net earnings or other measures offinancial performance calculated in accordance with GAAP.

Funds flow fromoperations is reconciled as follows:
| **Funds Flow**                 | ** ** | **2006**      | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|------------------------------------------|------------|---------------|------------|------------|------------|------------|------------|
| **($000s)**                              | ** ** | ** **    | ** ** | ** ** | ** ** | ** ** | ** ** |
| Net Earnings                             | ** ** | **223,101**   |       | 65,848     |       | 31,263     |       |
| Adjustments for:                         |       |          |       |       |       |       |       |
| Unit-based compensation expense          | ** ** | **14,049**    |       | 27,166     |       | 7,344      |       |
| Depletion, depreciation and amortization | ** ** | **645,203**   |       | 233,693    |       | 179,557    |       |
| Accretion                                | ** ** | **11,410**    |       | 4,560      |       | 3,045      |       |
| Unrealized gain on financial derivatives | ** ** | **(95,371**   | **)**      | 20,635     |       | 11,093     |       |
| Future income taxes                      | ** ** | **(48,246**   | **)**      | 8,573      |       | 1,171      |       |
| Funds flow from  operations              | ** ** | **750,146**   |       | 360,475    |       | 233,473    |       |
| Unitholder’s equity                 | ** ** | **3,506,915** |       | 764,583    |       | 780,980    |       |

For the year ended December 31, 2006, funds flow fromoperations totalled $750.1 million or $3.57 per diluted unit, representing a108 percent increase from the $360.5 million, or $3.98 per diluted unit duringthe same period in 2005 (2004 - $233.5 million or $3.09 per diluted unit).  The increase is due to higher productionlevels associated with the StarPoint and Samson acquisitions.  Our 2006 funds flow included a realized losson financial derivative contracts of $8.5 million ($0.04 per diluted unit) ascompared to a loss of $80.2 million ($0.88 per diluted unit) in 2005.

Funds flow for the fourthquarter was $170.1 million or $0.75 per diluted unit as compared to $106.5million or $1.15 per diluted unit during the same quarter in 2005 (2004 - $73.8million or $0.84 per diluted unit).  Theincrease is attributable to an increase in production due to the StarPoint andSamson acquisitions.

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We believe that fundsgenerated from our operations, together with borrowings under our creditfacility and proceeds from property dispositions, will be sufficient to financeour operations and planned capital expenditure program.  During 2006, funds flow in excess ofdistributions funded 47 percent of our capital expenditure program.  Our dividend reinvestment program plusadditional bank borrowings funded the remaining 53 percent or $186.2million.  We anticipate that our annualcapital expenditures over the next few years will be similar to our capitalexpenditures in fiscal 2006.  Weestablish our capital expenditure program based on an annual budget reviewprocess, including budgeted cash flow from operations, and we closely monitorchanges throughout the year.

**CASH DISTRIBUTIONS**

Canetic declared cashdistributions of $583.5 million ($2.76/unit), representing 78 percent of 2006funds flow from operations compared to cash distributions of $208.5 million($2.34/unit), representing 58 percent of funds flow from operations in2005.  The remaining 22 percent of fundsflow in 2006 was utilized to fund 47 percent of Canetic’s 2006 capital program.

Effective with the mergerwith StarPoint, Canetic set its monthly distribution at $0.23 per unit permonth beginning with distributions payable on February 15, 2006.  This represented an 18 percent increase toformer Acclaim unitholders and a five percent increase to former StarPointunitholders.
| **($000s, except where indicated)** | ** ** | **2006**    | ** ** | **2005** | ** ** | **2004** | ** ** |
|----------------------------------------------------|------------|-------------|------------|----------|------------|----------|------------|
| Funds flow from  operations                        | ** ** | **750,146** |       | 360,475  |       | 233,473  |       |
| Total  distributions                               | ** ** | **583,528** |       | 208,477  |       | 176,741  |       |
| Distributions  per unit ($)                        | ** ** | **2.76**    |       | 2.34     |       | 2.34     |       |
| Payout ratio (%)                                   | ** ** | **78**      | **%**      | 58       | %          | 74       | %          |

In aggregate ourdistributions and net capital expenditure program totalled approximately $4.4billion or approximately 586 percent of our 2006 cash flow of $750.1million.  We fund our distributions andcapital expenditure programs with cash flow, but also supplement growth andfund acquisitions with long-term debt and equity.

We distribute a portionof the funds flow from operations to our Trust unitholders on a monthly basiswith a portion withheld to initially repay bank debt and ultimately fundcapital expenditures.  Although the levelof funds retained for capital expenditures and/or debt repayment typicallyvaries, we monitor our distribution policy with respect to forecasted fundsflows from operations, debt levels, spending plans and taxability.

Our 2006 distributionsare summarized as follows:
| ** **                                        | ** ** | **Total**         | ** ** | **Distributions** | ** ** | **Value of Units**    | ** ** | **Number of**    | ** ** | **DRIP Unit**        | ** ** |
|---------------------------------------------------|------------|-------------------|------------|-------------------|------------|---------------------------------|------------|-----------------------|------------|---------------------------|------------|
| **($000, except where indicated)** | ** ** | **Distributions** | ** ** | **Paid**          | ** ** | **Issued under DRIP** | ** ** | **Units Issued** | ** ** | **Price *($/unit)*** | ** ** |
| Distributions  declared:                          |       |              |       |              |       |                            |       |                  |       |                      |       |
| December 2006                                     |       | $                 | 51,933     |              | $          | 47,793                          |       | $                     | 4,140      |                      | 284,172    |   | $ | 14.57 |   |
| November 2006                                     |       | 51,848            |       | 46,743            |       | 5,104                           |       | 330,490               |       | $                         | 15.44      |   |
| October 2006                                      |       | 51,739            |       | 45,419            |       | 6,321                           |       | 424,474               |       | $                         | 14.90      |   |
| September 2006                                    |       | 51,642            |       | 45,289            |       | 6,353                           |       | 374,054               |       | $                         | 16.98      |   |
| August 2006                                       |       | 51,577            |       | 47,029            |       | 4,548                           |       | 225,495               |       | $                         | 20.18      |   |
| July 2006                                         |       | 46,699            |       | 41,236            |       | 5,463                           |       | 252,973               |       | $                         | 21.61      |   |
| June 2006                                         |       | 46,583            |       | 42,538            |       | 4,045                           |       | 189,023               |       | $                         | 21.40      |   |
| May 2006                                          |       | 46,516            |       | 42,570            |       | 3,946                           |       | 184,238               |       | $                         | 21.48      |   |
| April 2006                                        |       | 46,439            |       | 43,175            |       | 3,264                           |       | 145,356               |       | $                         | 22.46      |   |
| March 2006                                        |       | 46,272            |       | 43,230            |       | 3,042                           |       | 130,570               |       | $                         | 23.29      |   |
| February 2006                                     |       | 46,208            |       | 43,629            |       | 2,579                           |       | 119,674               |       | $                         | 21.55      |   |
| January 2006                                      |       | 46,072            |       | 46,000            |       | 72                              |       | 3,175                 |       | $                         | 22.70      |   |
| Total                                             |       | $                 | 583,528    |              | $          | 534,651                         |       | $                     | 48,877     |                      | 2,663,694  |   |   |   |

 

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In light of the weakershort-term outlook for commodity prices, Canetic announced on January 15, 2007that it would reduce the monthly distribution in order to increase the level ofcash flow available to fund drilling and development opportunities, bring Canetic’spayout ratio in line with the Trust’s long-term target of 60 to 70 percent offunds flow from operations, and prudently manage the level of Canetic’slong-term debt.  The regular monthlydistribution was fixed at $0.19 per trust unit, commencing with the January 31,2007 distribution paid on February 15, 2007.

For the year endedDecember 31, 2006, we declared distributions of $583.5 million ($2.76 per unit)which represented 78 percent of funds flow from operations as compared to cashdistributions of $208.5 million ($2.34 per unit) representing a 58 percentpayout ratio in 2005.

For the three monthsended December 31, 2006, our payout ratio increased to 91 percent as wegenerated $170.1 million of funds flow from operations and distributed $155.5 million.

**CONTRACTUAL OBLIGATIONS**

In addition to financialderivative commitments, the Trust has the following contractual obligations asat December 31, 2006:
| **($000s)**             | ** ** | **Total** | ** ** | **2007** | ** ** | **2008** | ** ** | **2009**  | ** ** | **2010**   | ** ** | **2011** | ** ** | **Thereafter** | ** ** |
|-------------------------|------------|-----------|------------|----------|------------|----------|------------|-----------|------------|------------|------------|----------|------------|----------------|------------|
| Bank debt               |       | 1,289,678 |       | —   |       | —   |       | 1,289,678 | ** ** | **—** |       | —   |       | —         |       |
| Convertible  debentures |       | 260,656   |       | 1,697    |       | 5,622    |       | 8,046     |       | 17,821     |       | 227,470  |       | —         |       |
| Office lease            |       | 24,659    |       | 6,415    |       | 6,295    |       | 6,295     |       | 3,231      |       | 2,423    |       | —         |       |
| Pipeline  contract      |       | 6,116     |       | 636      |       | 802      |       | 814       |       | 877        |       | 823      |       | 2,164          |       |
| Total                   |       | 1,581,109 |       | 8,748    |       | 12,719   |       | 1,304,833 |       | 21,929     |       | 230,716  |       | 2,164          |       |

TAXATION OF CASH DISTRIBUTIONS

The following sets out ageneral discussion of the Canadian and U.S. tax consequences of holding Caneticunits as capital property.  The summaryis not exhaustive in nature and is not intended to provide legal or taxadvice.  Unitholders or potentialunitholders should consult their own legal or tax advisors as to theirparticular tax consequences.

**CANADIAN TAXPAYERS**

The Trust qualifies as amutual fund trust under the Income Tax Act (Canada) and, accordingly, trustunits are qualified investments for RRSP’s, RRIF’s, RESP’s and DPSP’s.  Each year, the Trust is required to file anincome tax return and any taxable income of the Trust is allocated tounitholders.

Unitholders are requiredto include in computing income their pro-rata share of any taxable incomeearned by the Trust in that year.  Aninvestor’s adjusted cost base (“ACB”) in a trust unit equals the purchase priceof the unit less any non-taxable cash distributions received from the date ofacquisition.  To the extent theunitholders’ ACB is reduced below zero, such amount will be deemed to be acapital gain to the unitholder and the unitholders’ ACB will be brought to nil.

Canetic paid $2.76 pertrust unit in cash distributions to unitholders during the period February 2006to January 2007.  For Canadian taxpurposes, 100 percent of these distributions are taxable as other income.  During the same period in 2005, the Trust paid$1.95 per trust unit in cash distributions, of which 31.28 percent was a tax-deferredreturn of capital and 68.72 percent taxable.

The taxability of ourdistributions increased during 2006, a direct result of increased cash flowsdue to strong commodity prices and limited tax pools associated with theacquired assets.

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## **U.S. TAXPAYERS**

## Prior to 2005, U.S.unitholders who received cash distributions were subject to a 15 percentwithholding tax, applied only on the taxable portion of the distribution ascomputed under Canadian tax law. Legislative changes which took effect on January 1, 2005, imposed anadditional 15 percent withholding tax on the non-taxable portion of thedistribution.  U.S. taxpayers should beeligible for a foreign tax credit with respect to 100 percent of Canadianwithholding taxes paid.

The taxable portion of thecash distributions is determined by the Trust in relation to its current andaccumulated earnings and profit using U.S. tax principles.  The taxable portion so determined, isconsidered to be a dividend for U.S. tax purposes.  For most taxpayers, these dividends should beconsidered “Qualifying Dividends” and eligible for a reduced rate of tax.

The non-taxable portionof the cash distributions is a return of the cost (or other basis).  The cost (or other basis) is reduced by thisamount for computing any gain or loss from disposition.  However, if the full amount of the cost (orother basis) has been recovered, any further non-taxable distributions shouldbe reported as a gain.

Canetic paid US$2.23 pertrust unit to United States residents during the calendar year 2006.  The portion considered to be a qualifieddividend will be announced immediately upon completion of the Trust’scalculation of current earnings and accumulated deficit for the year.

RISK MANAGEMENT

Investors who purchaseour units are participating in the net funds flow from a portfolio of westernCanadian crude oil and natural gas producing properties.  As such, the funds flow paid to investors andthe value of the units are subject to numerous risks inherent in the industry.

Our expected funds flowfrom operations depends largely on the volume of petroleum and natural gasproduction and the price received for such production, along with theassociated operating costs and taxability of distributions.  The price we receive for our oil depends on anumber of factors, including West Texas Intermediate oil prices, Canadian/U.S.currency exchange rates, quality differentials and Edmonton par oilprices.  The price we receive for ournatural gas production is primarily dependent on current Alberta market prices.Canetic has an ongoing commodity price risk management policy that provides fordownside protection on a portion of its future production while allowing accessto the upside price movements.

Acquisition of oil andnatural gas assets depends on our assessment of value at the time ofacquisition.  Incorrect assessments ofvalue can adversely affect distributions to unitholders and the value of theunits.  We employ experienced staff onthe business development team and perform stringent levels of due diligence onour analysis of acquisition targets, including a detailed examination ofreserve reports; re-engineering of reserves for a large portion of theproperties to ensure the results are consistent; site examinations offacilities for environmental liabilities; detailed examination of balance sheetaccounts; review of contracts; review of prior year tax returns and modeling ofthe acquisition to ensure accretive results to the unitholders.  The Board of Directors approves allacquisitions greater than $5 million.

Inherent in developmentof the existing oil and gas reserves are the risks, among others, of drillingdry holes, encountering production or drilling difficulties or experiencinghigh decline rates in producing wells. To minimize these risks, we employ experienced staff to evaluate andoperate wells and utilize appropriate technology in our operations.  In addition, we use prudent work practicesand procedures, safety programs and risk management principles, includinginsurance coverage against potential losses.

We are subject to creditrisk associated with the purchase of the commodities produced.  In order to mitigate the risk of non-payment,we minimize the total sales value with any particular purchaser.

The value of our trustunits is based on the underlying value of the oil and natural gasreserves.  Geological and operationalrisks can affect the quantity and quality of reserves and the cost ofultimately recovering those reserves. Lower oil and gas prices increase the risk of write-downs on our oil andgas property investments.  In order tomitigate this risk, our proven and probable oil and gas reserves are evaluatedeach year by a firm of independent reservoir engineers.  A special committee of the Board of Directorsreviews and approves the reserve report.

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## Our access to commoditymarkets may be restricted at times by pipeline or processing capacity.  We minimize these risks by controlling asmuch of our processing and transportation activities as possible and ensuring transportationand processing contracts are in place with reliable cost efficientcounterparties.

## The petroleum and naturalgas industry is subject to extensive controls, regulatory policies and incomeand resource taxes imposed by various levels of government.  These regulations, controls and taxationpolicies are amended from time to time. We have no control over the level of**governmentintervention or taxation in the petroleum and natural gas industry.  However, we operate in such a manner toensure that we are in compliance with all applicable regulations and are ableto respond to changes as they occur.

## The petroleum and naturalgas industry is subject to both environmental regulations and an increasedenvironmental awareness.  We havereviewed our environmental risks and are in compliance with the appropriateenvironmental legislation and have determined that there is no current materialimpact on our operations.

We are subject tofinancial market risk.  In order toachieve substantial rates of growth, we must continue reinvesting in, acquiringor drilling for petroleum and natural gas. As we distribute the majority of our net cash flow to unitholders, wemust finance a large portion of our acquisitions and development activitythrough continued access to equity and debt capital markets.  One source of funding for ouracquisition/expenditure program is through the issuance of equity.  If we are not able to access the equitymarkets due to unfavorable market conditions for an extended period of time,this may adversely impact our growth rate. We minimize the financial market risk by maintaining a conservativefinancing structure.

On October 31, 2006, theCanadian federal government announced proposals to introduce a new tax ondistributions from existing publicly-traded income trusts.  If enacted as currently proposed, Caneticwould be subject to these new taxes beginning in 2011, provided it does notexperience “undue expansion” in the intervening period as that term is definedin the recently released federal guidelines on “normal growth”.  The intent of these rules is to impose tax onincome trusts in a similar manner and at similar rates as public corporationsand the distributions be treated as dividends at the investor level.  Income at the Trust level in excess ofavailable tax shelter would be subject to the new tax at a statutory rate of31.5 percent which would directly reduce cash available for distribution.  These rules have not been enacted and arediscussed in more detail in an earlier section of the MD&A.

CRITICAL ACCOUNTINGPOLICIES AND ESTIMATES

The Trust’s significantaccounting policies are summarized in Note 1 to the Trust’s auditedconsolidated financial statements for the years ended December 31, 2006 and2005. Certain of these policies are recognized as critical because in applyingthese policies, management is required to make judgments, assumptions andestimates that have a significant impact on the financial results of the Trust.

**OIL AND GAS RESERVES**

Reserves estimates andrevisions to those reserves, although not reported as part of the Trust’sfinancial statements, can have a significant impact on net earnings as a resultof their impact on depletion, depletion rates, asset retirement obligations,asset impairments and purchase price allocations. In adherence with NationalInstrument 51-101, 100 percent of the Trust’s proved plus probable oil and gasreserves were evaluated and reported on by independent petroleum engineers GLJPetroleum Consultants Ltd. and Sproule Associates Limited.  However, the process of estimating oil andgas reserves is complex and is subject to uncertainties and interpretations.Estimating reserves requires significant judgments based on availablegeological and reservoir data, past production and operating performance andforecasted economic and operating conditions. These estimates may changesubstantially as additional data from ongoing development, testing andproduction becomes available, and due to unforeseen changes in economicconditions which impact oil and gas prices and costs.

**FULL COST ACCOUNTING**

The Trust follows thefull cost method of accounting for oil and natural gas activities.  Using the full cost method of accounting, allcosts of acquiring, exploring and developing oil and natural gas properties arecapitalized, including unsuccessful drilling costs and administrative costsassociated with acquisitions and development.

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In accordance with fullcost accounting, a ceiling test is performed, on a quarterly basis, to test forasset impairment. An impairment loss is recorded if the sum of the undiscountedcash flows expected from the production of the proved reserves and the lower ofcost and market of unproved properties does not exceed the carrying values ofthe oil and gas assets. An impairment loss is recognized to the extent that thecarrying value exceeds the sum of the discounted cash flow expected from theproduction of proved and probable reserves and the lower of cost and market ofunproved properties.  The cash flow usedin testing for impairment is based on the estimates of remaining proved andprobable reserves, future commodity prices and future operating costs.

Capitalized costs aredepleted using the unit-of-production method based on estimated proved reservesof petroleum and natural gas before royalties as determined by independentpetroleum engineers.  Costs relating tounproved properties are excluded from costs subject to depletion anddepreciation until it is determined whether or not proved reserves exist or ifimpairment occurs.  Proved natural gasreserves and production are converted to equivalent volumes of crude petroleumbased on the approximate relative energy content ratio of six thousand cubicfeet of natural gas to one barrel of crude oil.

**ASSET RETIREMENT OBLIGATIONS**

Management calculates theasset retirement obligation based on estimated costs to abandon and reclaim itsnet ownership interest in all wells and facilities and the estimated timing ofthe costs to be incurred in future periods. The fair value estimate is capitalizedto property, plant and equipment as part of the cost of the related asset andamortized over its useful life.

**BUSINESS COMBINATIONS**

Management makes variousassumptions in determining the fair values of any acquired company’s assets andliabilities in a business combination. The most significant assumptions andjudgments made relate to the estimation of the fair value of the oil andnatural gas properties. To determine the fair value of these properties weestimated oil and gas reserves and future prices of oil and natural gas.

**INCOMETAXES**

The Trust is not liablefor income tax as it allocates substantially all of its taxable income to itsunitholders.  Future income taxes arecalculated for the corporate subsidiaries using the liability method whereby taxliabilities and assets are recognized for the estimated tax consequencesattributable to differences between amounts reported in the financialstatements and their respective tax base using substantively enacted income taxrates. The effect of a change in income tax rates in future tax liabilities andassets are recognized in income in the period in which the change occurs. Thedetermination of income and other tax liabilities requires interpretation ofcomplex laws and regulations. All tax filings are subject to audit andassessment by taxing authorities after the lapse of considerable time.  As a result, the actual income tax liabilitymay differ from that recorded.

RECENT ACCOUNTINGPRONOUNCEMENTS

**FINANCIAL INSTRUMENTS**

Effective January 1,2007, the Trust will apply the following new CICA Handbook sections: Section1530-Comprehensive Income; Section 3251-Equity; Section 3855-FinancialInstruments — Recognition and Measurement; and Section 3865-Hedges. The newaccounting pronouncements are effective for the first quarter of 2007, andaddress the recognition and measurement of financial assets, financialliabilities and non-financial derivatives.

The Trust has assessedthe requirements under these sections, and has noted no current impact on thefinancial statements. Financial assets, financial liabilities and non-financialderivatives acquired in future periods will be evaluated under the frameworkset forth in the new pronouncements

BUSINESS RISKS

The operations of Caneticare subject to underlying risks associated with the business of the Trust. Fora detailed discussion of business risks, please refer to “Risk Factors” in theTrust’s most recently filed Annual Information Form.

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DISCLOSURE CONTROLS ANDPROCEDURES OVER FINANCIAL REPORTING

Disclosure controls andprocedures are designed to provide reasonable assurance that all relevantinformation is gathered and reported to senior management, including the ChiefExecutive Officer (CEO) and the Chief Financial Officer (CFO), on a timelybasis so appropriate decisions can be made regarding public disclosure. As atDecember 31, 2006, the CEO and the CFO have evaluated the effectiveness ofCanetic’s disclosure controls and procedures as defined in MultilateralInstrument 52-109 (“MI 52-109”) of the Canadian Securities Administrators andhave concluded that such disclosure controls and procedures are effective toprovide reasonable assurance that material information related to the Trust ismade known to them by employees or third party consultants working for theTrust.  It should be noted that while theCEO and CFO believe that the disclosure controls and procedures are effective,they do not expect that they will prevent all errors and fraud.  A control system, regardless of how wellconceived or operated, can only provide reasonable assurance, and not absoluteassurance, that the objectives of the control system are met.

INTERNAL CONTROLS OVERFINANCIAL REPORTING

The CEO and CFO areresponsible for designing, or causing to be designed, internal controls over financialreporting as defined in MI 52-109 in order to provide reasonable assuranceregarding the reliability of financial reporting and the preparation offinancial statements for external purposes, in accordance with Canadian GAAP.  There have been no changes in the Trust’sinternal controls over financial reporting that occurred during the threemonths ended December 31, 2006, that have materially affected, or arereasonably likely to affect the Trust’s internal controls over financialreporting.

OUTLOOK

Our long-termstrategy has always been to build a significant asset base and a team of peoplethat could generate long-term value for our stakeholders. We have pursued ourobjectives aggressively over the past four years and today, with the merger ofAcclaim and StarPoint and the recent addition of the Samson assets we believewe have created a trust with substantial financial strength and a great assetand opportunity base capable of delivering that value.

With the growth ofCanetic and expansion of the opportunity base, exploitation has become asignificant component of our business strategy. In 2006, we reported solid results from Canetic’s development programdelivering what we believe will be top quartile finding, development andacquisition costs and strong production efficiencies.

In 2007, we will continueto actively exploit our asset base.  Wehave budgeted approximately $350 million for development related expendituresin 2007.  More than 80 percent of thatamount will be allocated to drilling and new completion or optimization relatedactivity directly impacting production and reserves performance.  The 2007 operated drilling program isweighted modestly to oil prone plays with substantial development targetingmany of the former StarPoint properties which performed very stronglythroughout 2006. We continue to target new completions in areas such asAcheson, where we have had significant success identifying and exploitingmultiple zones in the large inventory of well bores we acquired through the ChevronTexacotransaction.

In the early part of2007, our focus has been to tie in production from our successful fourthquarter 2006 drilling program, while also pursuing an aggressive drilling andoptimization program on our producing properties.  During the fourth quarter of 2006, Caneticcontinued its strong performance of efficiently adding reserves and production.We exited the year with approximately 1,400 boe per day behind pipe, led bysuccessful Q4 programs in the Acheson area, Southern and North WestAlberta.  Following on the strength ofthe 2006 program and depth of opportunities, Canetic kicked off the largestfirst quarter development program in its history in 2007.  Canetic operated five to seven drilling rigsthroughout the first quarter of 2007 and to date we have drilled 37 wells.  Canetic’s focus in 2007 will be on gasdevelopment in the Willesden Green area where our new 20 mmcf per day gas plantis now on stream, North-East BC where we are excited about the prospect of aSlave Point test and follow-ups, and continued programs in Border Plains andour Southern business unit. In addition, we have an aggressive drilling, newcompletion and facility de-bottlenecking program underway in the Acheson area.This program is in follow-up to a large and successful fourth quarter program,where we added incremental reserves and production. 

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We anticipate drilling atotal of approximately 50 operated wells by the end of the first quarter of2007, depending on seasonal impacts, such as the start of break-up.

Results to date from bothour drilling and new completion and optimization programs are meeting ourexpectations, and in areas such as Acheson, we continue to be excited by boththe results we are seeing and the inventory that we have in front of us.

For the year, we continueto target annual average production of approximately 75,500 to 80,000 boe perday.  Given current commodity prices,this production target should result in a payout ration of 65 to 75 percent atcurrent distribution levels of $0.19 per unit per month.  The balance of cash flow available should besufficient to finance the majority of our capital expenditure program.

In recent years the oiland natural gas industry has experienced significant increases in costs,including labour, both in the field and head office, and all services,including power, pipe and drilling. We believe this trend may change followingthe Canadian Government’s announcement on the taxation of trusts but moreimportantly in response to the recent weakness and volatility in commodityprices which is expected to result in cutbacks in overall industry drillingactivity.  We currently intend to holdoperating costs largely flat in 2007 at approximately $9.00 per boe and G&Acosts at between $1.30 and $1.40 per boe.

As we look forward, weintend to continue executing our business strategy, which involves a balancedapproach to acquisitions and effective asset exploitation and managementprograms.  Having completed over $4billion in acquisitions since our inception, Canetic has accumulated anextensive inventory of development opportunities, including nearly one millionnet undeveloped acres. As a result, we do not feel it is necessary to completeany significant acquisitions in the near term though we will continue tomonitor both asset and corporate acquisition opportunities which may arise as aresult of the changing environment for trusts in Canada, including potentialconsolidation opportunities within the sector, unconventional opportunities, orexpansion opportunities outside of Canada, particularly in the U.S.  In the meantime, Canetic will continue tofocus on the development and exploitation of its significant resource base.

We look forward to anexciting and successful 2007.

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