Canetic Resources Trust 40-F 2006 FY Annual report (Canada)

EXHIBIT 99.2

2006 HIGHLIGHTS

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	%	—

(1)   Includes the financial and operating results of StarPoint Energy Trust from the date of the merger, January 5, 2006 and the property 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 purchase of StarPoint by Acclaim.  Accordingly, the financial and operating results of StarPoint have been included from the date of acquisition, January 5, 2006.  The comparative results for 2005 are those of Acclaim only.  All disclosures of units and per unit amounts of Acclaim up to the merger on January 5, 2006 have been restated using the exchange ratio of 0.8333 of a Canetic unit for each Acclaim unit.

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

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MANAGEMENT’S DISCUSSION AND ANALYSIS

This Management’s Discussion and Analysis (“MD&A”) should be read in conjunction with the Consolidated Financial Statements and Notes thereto of Canetic Resources 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 accordance with Canadian Generally Accepted Accounting Principles (“GAAP”).  This discussion provides Management’s analysis of Canetic’s historical financial and operating results and provides estimates of Canetic’s future financial and operating performance based on information currently available.  Actual results will vary from estimates and the variances may be material.  You should be aware that historical results are not necessarily indicative of future performance.  Readers are referred to the legal advisories regarding forward-looking information contained in the “Forward-Looking Statements” section of this MD&A.

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

FORWARD-LOOKING STATEMENTS

Certain statements contained in this MD&A constitute forward-looking statements or information (collectively “forward-looking statements”) within the meaning of applicable securities laws.  All statements other than statements of historical fact may be forward looking statements. Statements relating to “reserves” or “resources” are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described can be profitably produced in the future.

The use of any of the words “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “could”, “should”, “believe”, “intend”, “propose”, “budget” and similar expressions are intended to identify forward-looking statements.  These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. We believe the expectations reflected in the forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements are not guarantees of future performance and should not be unduly relied upon. These statements speak only as of the date of this MD&A.

In particular, this MD&A contains forward-looking statements pertaining to the following: business strategies; production volumes, reserves volumes, operating and other costs, commodity prices; future cash distribution levels and taxability; payout ratios; capital spending including timing, allocation and amounts of capital expenditures and the sources of funding thereof; regulatory changes; hedging and other risk management programs; anticipated tax obligations; supply and demand for oil and natural gas; ability to raise capital; ability to add to reserves through acquisitions and development; treatment under governmental regulatory regimes; the impact of acquisitions; future tax treatment of income trusts such as the Trust; and  liquidity and financial capacity.

The forward-looking statements contained in this MD&A are based on a number of expectations and assumptions that may prove to be incorrect. In addition to other assumptions identified in this MD&A, assumptions have been made regarding, among other things: that the Trust will continue to conduct its operations in a manner consistent with past operations; the continuance of existing (and in certain circumstances, proposed) tax and royalty regimes; the general continuance of current industry conditions; the accuracy of the estimates of the Trust’s reserve volumes; the ability of Canetic to obtain equipment, services and supplies in a timely manner to carry out its activities; the ability of Canetic to market oil and natural gas successfully; the timely receipt of required regulatory approvals; the ability of Canetic to obtain financing on acceptable terms; currency, exchange and interest rates; future oil and gas prices and future cost assumptions. No assurance can be given that these factors, expectations and assumptions will prove to be correct.

The actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in this MD&A: volatility in market prices for oil and natural gas; risks and liabilities inherent in oil and natural gas including operations, exploration, development, exploitation, production, marketing and transportation risks; uncertainties associated with estimating oil and natural gas reserves;

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competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel; incorrect assessments of the value of acquisitions; geological, technical, drilling and processing problems; risks and uncertainties involving geology of oil and gas deposits; unanticipated operating results or production declines; fluctuations in foreign exchange, currency or interest rates and stock market volatility; changes in laws and regulations changes including but not limited to those pertaining to income tax, environmental and regulatory matters; failure to realize the anticipated benefits of acquisitions; health, safety and environmental risks; and  the other factors described in Canetic’s public filings from time to time (including under “Risk Management” in this MD&A and under “Risk Factors” in its Annual Information Form) available in Canada at www.sedar.com and in the United States at www.sec.gov. Readers are cautioned that this list of risk factors should not be construed as exhaustive.

The forward-looking statements contained in this MD&A are expressly qualified by this cautionary statement. Canetic undertakes no obligation to publicly update or revise any forward-looking statements except as expressly required by applicable securities law.

Non-GAAP Measures

This MD&A refers to certain financial measures that are not determined in accordance with GAAP.  These measures as presented do not have any standardized meaning prescribed by Canadian GAAP and therefore they may not be comparable with calculations of similar measures for other companies or trusts.

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

We use the term net debt, which we define as long-term debt and working capital, to analyze liquidity and capital resources.  Readers should refer to the “Liquidity and Capital Resources” section of the MD&A for a reconciliation of net debt.

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

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

We use the term total capitalization, which we define as net debt including convertible debentures plus unitholders’ equity, to analyze leverage.  Total capitalization is not intended to represent the total funds from equity and debt received by the Trust.  Readers should refer to the “Liquidity and Capital Resources” section of the 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 more complete understanding of certain aspects of the Trust’s results of operations and financial performance.  Investors are cautioned however, that these measures should not be construed as an alternative to measures determined in accordance with GAAP as an indication of our performance.

OVERVIEW

The year 2006 was a very active year for Canetic.  In January, the Trust closed the acquisition of StarPoint Energy Trust (“StarPoint”), doubling the size of the Trust by production volume and reserves.  Shortly thereafter, on February 15, 2006, Canetic began trading on the New York Stock Exchange under the symbol CNE.  In August, we closed another acquisition which added 13,500 boe/d of production, increased our weighting to natural gas from 41 percent to 47 percent and increased our undeveloped land position by approximately 230,000 net acres.  This acquisition was financed with a combination of trust units, convertible debentures and bank debt totalling approximately $930 million.

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Throughout the year, Canetic was also very busy in the field.  A total of 378 gross (174.4 net) wells were drilled in 2006, a year in which we spent $351.3 million on exploration and development activities.  This level of capital expenditures  will continue into the first quarter of 2007 with 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 to improve somewhat in 2007, other factors such as the uncertainty of commodity prices and the announcement on October 31, 2006 of the Canadian federal government’s proposed taxation of income trusts will impact the Trust’s performance and strategic direction for 2007 and beyond.

FEDERAL GOVERNMENT’S PROPOSED TAXATION OF INCOME TRUSTS

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

Under the proposed rules, distributions paid or payable to unitholders would no longer be deductible at the Trust level,  and would be subject to the new tax at a rate of 31.5 percent. The effect would essentially tax income in the trust structure in a similar manner and at similar rates to public corporations. It is expected that this tax would apply to all of the Trust’s income in excess of available tax shelter.  At the investor level, distributions will be considered taxable dividends and eligible for the dividend tax credit mechanism.  As such, the after-tax yield to taxable Canadian resident investors in 2011 will remain approximately the same.  The after-tax distribution yield for tax-deferred investors will be reduced significantly and be dependent upon the tax shelter available in the Trust.

On December 15, 2006, the Federal Government announced safe harbour guidance with respect to “normal growth” for flow-through entities. Existing income trusts, are provided an exemption from the new tax until 2011, provided these guidelines are respected and the Trust does not experience “undue expansion” in the interim period.  The guidelines are measured by reference to a trust’s market capitalization on October 31, 2006 and allow cumulative increases in equity capital of 40 percent in 2007 and 20 percent each of the subsequent three years providing for a doubling of equity capital to the end of 2010.  Growth in excess of these limits will be considered “undue expansion” and subject the Trust to the new tax regime prior to the end of the four year grace period.  We do not believe these guidelines will materially limit our near-term growth opportunities as the Trust could issue approximately $4.5 billion in additional equity under these guidelines prior to the end of 2010.

On December 21, 2006, the Government released detailed draft legislation with respect to the new tax proposals and have requested comments from interested stakeholders. Recently, these tax proposals have been the subject of special hearings before the House of Commons Standing Committee on Finance. The Committee has subsequently released their findings and have recommended substantial changes to the legislation as currently proposed including a reduction of the rate from 31.5% to 10% and an extension of the grace period for existing trusts from 4 years to 10 years. It is unclear what effect, if any, these recommendations will have on the final form of the legislation to be tabled in the House of Commons. We are also presently unable to predict when these proposals may become enacted into law.

These proposals have had significant implications for the Trust and our investors.  Shortly after the announcement of the new rules, the valuation of Canetic and other trusts 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 investors should be indifferent, the reduced distributions will be  a sunk cost to investors such as pension funds, registered retirement savings plans and non-resident investors who may not be able to utilize the dividend tax credit.

Canetic is currently working with the Canadian Association of Income Funds (CAIF) and the Coalition of Canadian Energy Trusts to effect change to the legislation as proposed.  A main focus is ensuring that the facts related to income trusts are understood and that all data is made available by the Minister to the investing public and other members of Parliament.

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

HIGHLIGHTS

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

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

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

·Acclaim and StarPoint were delisted on January 6, 2006 and Canetic began trading on the Toronto 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.

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

·On August 31, 2006, Canetic closed the acquisition of a private company which included primarily natural gas interests in central Alberta and northeastern British Columbia (the “Samson acquisition”).  Canetic financed the $930 million acquisition with a $690 million bought deal equity and debenture financing which closed August 24, 2006, as well as through available credit facilities.

Production from the Samson acquisition at closing was approximately 13,500 boe/d comprised of 70.0 million cubic feet per day (“mmcf/d”) of natural gas and 1,600 barrels per day (“bbl/d”) of crude oil and natural gas liquids.  At that time, the acquisition increased Canetic’s overall production in excess of 80,000 boe/d and balanced the asset portfolio to 53 percent crude oil and natural gas liquids and 47 percent natural gas.  The acquisition also increased Canetic’s total proved plus probable reserves to nearly 275 million boe.  The assets are complementary to Canetic’s current properties in the Peace River Arch and Rocky areas.  The transaction was effective June 1, 2006.

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

·Annual production 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 quarter totalled 80,276 boe/d compared to 74,475 boe/d in the third quarter of 2006.

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·Funds flow from operations 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 from operations totalled $170.1 million ($0.76 per basic unit) an increase of 60 percent from $106.5 million ($1.16 per basic unit) realized in the same period last year.  Funds flow reported for the third quarter of 2006 totalled $200.3 million ($0.95 per basic unit).  The decrease in the fourth quarter was largely attributed to a 21 percent decrease in average oil prices in the quarter relative to the third quarter of 2006.

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

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

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

·In addition, 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 the Trust was very active integrating the two large acquisitions completed in 2006.

SELECTED CONSOLIDATED FINANCIAL AND OPERATING INFORMATION

The results of operations in 2006 in comparison to 2005 and 2004 are outlined under the section, “Results of 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

(1)  When calculating the weighted average number of units at the end of a quarter, all units outstanding from the previous quarter are deemed to be outstanding for the entire period, whereas in the year to date calculation those units are weighted according to the date of issue.  Consequently, the addition of the quarterly per unit results, will not add to the annual earnings per unit.

(2)  All units of Acclaim up to the merger on January 5, 2006, have been restated using the exchange ratio of 0.8333 of a Canetic trust unit for each Acclaim 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)  When calculating the weighted average number of units at the end of a quarter, all units outstanding from the previous quarter are deemed to be outstanding for the entire period, whereas in the year to date calculation those units are weighted according to the date of issue.  Consequently, the addition of the quarterly per unit results, will not add to the annual earnings per unit.

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

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

The transaction with StarPoint 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 of Acclaim only.

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

The variation of net earnings, quarter over quarter, is primarily a result of changes in depletion rates, the provision for future income taxes and accounting for unrealized gains and losses on financial derivatives.  Net earnings in the fourth quarter reflects a $95.4 million unrealized hedging gain based on the mark-to-market price of crude oil and natural gas at December 31, 2006

RESULTS OF OPERATIONS

PRODUCTION

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

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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 sales averaged 186.3 mmcf/d in 2006, 78 percent higher than the 104.5 mmcf/d reported for the same period in 2005 (2004 — 94.2 mmcf/d). Crude oil and NGLs production averaged 43,358 bbl/d, an increase of 88 percent from 23,046 bbl/d reported in the 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 months ended December 31, 2006, natural gas sales averaged 221.2 mmcf/d, 109 percent more than the 105.8 mmcf/d reported for the fourth quarter 2005.  Crude oil and liquids production increased 98 percent to 43,402 bbl/d from 21,915 bbl/d reported for the same period a year earlier.

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

COMMODITY PRICES

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 Texas Intermediate crude averaged US$66.25/bbl during 2006, up 17 percent from the average price of US$56.56/bbl for the same period in 2005. WTI during the fourth quarter decreased 6 percent from an average of US$70.55/bbl in the third quarter of 2006.

West Texas Intermediate at Cushing, Oklahoma is the benchmark for North American crude oil prices.  Canadian crude oil prices are determined by refiners’ postings at major market hubs as Edmonton and Hardisty, Alberta.  Canadian prices adjust WTI for the Canadian/U.S. exchange rate, transportation and quality differentials.  NYMEX natural gas prices are referenced from Henry Hub, Louisiana.  Western Canadian natural gas prices are referenced from AECO Hub in Alberta and are adjusted for heat 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

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For the year ended December 31, 2006, we received an average oil price of $60.61/bbl as compared to $57.78/bbl for the comparable period in 2005. Our average oil price during the quarter decreased 21 percent from an average of $67.27/bbl reported during the third quarter of 2006. High crude oil inventory levels across North America and pipeline apportionment problems in southeast Saskatchewan have caused Canetic’s corporate average oil price differential to widen in relation to the benchmark NYMEX WTI futures contract over the past year.

Our average natural gas price 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 gas price 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 the fourth quarter of 2006 was 21 percent higher than the third quarter 2006 price of $5.55/mcf.

COMMODITY PRICE RISK MANAGEMENT

The prices we receive for our petroleum and natural gas can fluctuate significantly due to supply and demand fundamentals which are influenced by weather patterns, the economic environment or political uncertainty.

Our commodity price risk management program is designed to provide price protection on a portion of our future production in the event of an adverse commodity price movement, while retaining the opportunity to participate in favorable price movements.  This practice allows us to generate stable cash flow for distributions and to ensure positive economic returns on capital development and acquisition activities.

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

The following commodity commitments have been put in place for 2007 and beyond as noted below:

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 dollar averaged US$0.8819 during 2006 as compared to US$0.8261 for the same period last year.  As the price of WTI crude oil is quoted in U.S. dollars, appreciation in the Canadian dollar reduces the average price received for our production.  Canetic mitigates the impact of exchange rate fluctuations by either entering into foreign exchange contracts directly or executing some portion of our crude oil swaps in Canadian dollars.  In 2006, Canetic had no foreign exchange contracts, but had entered into contracts for 6,000 bbl/d of its crude oil production using Canadian dollar denominated swaps.

9

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 financial derivative gains and losses.

Crude oil and NGLs sales before 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 strong commodity prices throughout the year and the impact of increased production volumes associated with the Samson and StarPoint acquisitions.  Average daily production of crude oil and NGLs increased to 43,358 bbl/d from 23,046 bbl/d in 2005.

Natural gas sales increased 38 percent year-over-year from $346.1 million to $475.9 million.  Natural gas prices in 2006 were 23 percent lower than those received in 2005, which negatively impacted revenue.  Average daily sales of natural gas increased 78 percent to 186.3 mmcf/d in 2006 from 104.5 mmcf/d in 2005 primarily as a result of the volumes acquired from the acquisitions made during the year.

For the three months 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 higher production 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 the owners of the mineral rights with whom we hold leases, including provincial governments.  Overriding royalties are also paid to other parties according to contracts.  In Alberta, where we produce the majority of our natural gas, a Crown royalty is invoiced on the Crown’s share of production based on a monthly established Alberta Reference Price. The Alberta Reference Price is a monthly weighted average price of gas consumed in Alberta and natural gas exported from Alberta reduced for transportation and marketing allowances.  For 2006, the Alberta Reference Price averaged $6.22/Gj or about $6.56/mcf.  There is a maximum rate of 30 percent for new gas and 35 percent on old gas.  The vast majority of our gas production is from new natural gas.  In the 2006 gas price environment, we were subject to the maximum rates. Natural gas cost allowance, low productivity and other incentive schemes serve to reduce our effective royalty rate.

The majority of our oil production is in Alberta and Saskatchewan.  Royalty rates in both Alberta and Saskatchewan vary depending on the rate of production, oil prices and applicable incentives.  For the year ended 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 averaged 18.3 percent during 2006 as compared to 22 percent in the same period in 2005.

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

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

10

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 and natural gas involves many field activities including lifting the oil and natural gas to surface, as well as treating, processing, gathering and storing the commodities.  Other costs involved in the production function include those incurred to operate and maintain the wells along with the leases and well equipment.

Assets most suitable for the trust environment are generally more mature with more predictable production profiles.  Operating costs associated with these types of assets will generally be higher on a unit-of-production basis reflecting the amount of manpower, repairs and maintenance required to keep the wells on production and the recovery techniques utilized to extract the reserves.

Our operating costs net of processing fees and unit-based compensation increased to $249.6 million compared to $125.4 million during the same period a year earlier (2004 - $98.0 million).  On a unit-of-production basis, operating costs 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 been higher field service costs including higher energy and fuel costs, labour, trucking and other related mechanical services.  These increases, combined with the operating cost structures inherited from acquisitions made, caused operating costs year-over-year to increase on a unit-of-production basis.  In addition, certain assets within our portfolio, primarily in east central Alberta, are significantly more costly to operate.  Although these assets increase our operating costs in total and on a per unit basis, they provide positive cash flow during a high commodity price cycle.

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 fourth quarter, operating costs before unit-based compensation totalled $71.4 million or $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 boe operating costs for the fourth quarter was impacted by a plant turnaround at Acheson in October and cold weather and associated repairs and maintenance in November required to restore production.  The increase also reflects cost pressures due to industry activity.

Canetic was also active in 2006 in completing operational activities associated with the EUB’s guidelines for the suspension of existing wells, resulting in incremental costs incurred throughout the year.

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

11

PETROLEUM AND 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 legal custody transfer of the commodity and is dependent upon the type of product being sold, location of the producing asset, availability of pipeline capacity and sales point of the product.

For crude oil, Canetic sells all of its production at the lease.  The purchaser picks up the production at the lease and pays Canetic a price for the applicable 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 its natural gas from the plant gate to certain established market hubs such as AECO C in Alberta, at which point title transfers to the purchaser.  In both cases, transportation costs associated with getting natural gas and clean marketable oil to the point of title transfer are shown separately as a transportation expense.

NETBACKS

Operating netbacks represent the profit margin associated with the production and sale of petroleum and natural gas.  For 2006, our netbacks were influenced by our product mix, commodity prices, financial derivative losses, royalty rates, the appreciation in the Canadian dollar and higher 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

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

During 2006, we increased our head office staff in order to properly manage our business.  The level of activity in the trust sector increased the cost of hiring qualified candidates and retaining existing employees and consultants.  In 2006, approximately 66 percent of our total general and administrative expenses were labour related, including salary, benefits and consulting fees.

For the three months ended December 31, 2006, general and administrative expenses increased slightly to $1.62 per boe (net of unit-based compensation), reflecting costs associated with hiring additional permanent staff, leasing additional office space and integrating the assets acquired during the third quarter.

Unit-based Compensation

On December 19, 2005, the unitholders of Canetic approved a unit award incentive plan.  The plan authorizes the Board of Directors to grant rights to acquire up to five percent of the trust units outstanding to directors, officers, employees and consultants of the Trust and its affiliates.  These rights consist of Restricted Trust Units (“RTUs”) and Performance Trust Units (“PTUs”).  The number of PTUs granted is dependent on the performance of the Trust relative to a peer comparison group of petroleum and natural gas trusts and other companies or other criteria the Board of Directors may determine.  A holder of an RTU or PTU may elect, subject to consent of the Trust, to receive cash upon vesting in lieu of the number of units to be issued.  The plan provides for adjustments to the number of units issued based on the cumulative distributions of the Trust during the period that the RTU or PTU  is outstanding.

The compensation issued upon vesting of the PTUs is dependant upon the performance of the Trust compared to its peers.  The performance multiplier is based on our percentile rank of total unitholder return compared to a select group of peers approved by the Board of Directors.  Total return is calculated as the sum of the change in market price plus distributions in the period divided by the opening market price.  The performance multiplier ranges from zero, where our total return is less than the 35th percentile, to two, if our performance exceeds the 75th percentile.

For the year ended December 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 in the next year of $7.3 million (2005 — $40.8 million) has been classified as a current liability.  The compensation liability is remeasured each period at the current market price.  The December 31, 2006 compensation liability was based on the period-end closing price of $16.44 and the number of RTUs and PTUs outstanding at that time and the number of PTUs expected to vest using a PTU multiplier of 0.6.

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

13

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 debt increased to $53.8 million or $1.98 per boe from $13.8 million or $0.93 per boe a year earlier (2004 - $12.1 million or $0.98/boe).  In addition to slightly higher interest rates due to increases in the Bank of Canada lending rate in 2006, average debt levels have increased as a result of the corporate and property acquisitions made during the year.  At December 31, 2006, $1.29 billion was drawn under our facility.  Although interest rates continue to be favourable 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 Canetic during 2006 averaged approximately 5.1 percent.

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

INTEREST EXPENSE ON CONVERTIBLE DEBENTURES

Interest expense on convertible 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 $230.0 million were issued in conjunction with the Samson acquisition.  At December 31, 2006, debentures totalling $260.6 million remain outstanding.

INTEREST RATE RISK MANAGEMENT

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

DEPLETION, DEPRECIATION AND AMORTIZATION

The current year provision for depletion, depreciation and amortization totalled $645.2 million as 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 acquired in 2006.

FINANCIAL DERIVATIVES

Accounting standards require that we determine the fair value of our financial contracts and record a liability or asset at the end of each accounting period.  Any changes in the fair value of the financial contracts are included in net earnings for the period.  At December 31, 2006, we recorded a current financial derivative liability of $1.1 million and a long-term financial derivative asset of $6.2 million.  The estimated fair value is based on a mark-to-market calculation as at December 31, 2006 to settle the financial contracts.  The actual gain or loss realized upon settlement could vary significantly due to fluctuations in commodity prices.  At December 31, 2006, Canetic recorded an unrealized financial derivative gain of $95.4 million (2005-loss of $20.6 million) which represents the change in the mark-to-market calculations from December 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

ASSET RETIREMENT OBLIGATIONS

The total future asset retirement obligation was estimated by management based on the Trust’s net ownership interest in all wells and facilities, estimated costs to reclaim and abandon the facilities and the estimated timing of the costs to be incurred in future periods.  The costs are expected to be incurred over an average of 15 years.  The estimated cash flow has been calculated using a credit adjusted risk free discount rate of 8 percent and an inflation rate of 2 percent.

As of December 31, 2006, the amount to be recorded as the fair value of the liability was estimated 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 recorded accretion of $11.4 million (2005 - $4.6 million).

INCOME TAXES

Future Income Taxes

Future income taxes arise from differences between the accounting and tax bases of assets and liabilities of certain operating subsidiaries of the Trust.  The future taxes recorded on the balance sheet are expected to be recovered over time through interest and/or royalty payments to the Trust from its operating subsidiaries.  The Trust is a taxable entity under Canadian tax law and is subject to cash taxes only to the extent that income is not distributed or distributable to its unitholders.  As the Trust is required to distribute all of its taxable income to unitholders, the Trust is not expected to be subject to current or future income taxes.

For the period ended December 31, 2006, a future tax recovery of $48.3 million was included in income compared to a future tax expense of $8.6 million in 2005.  The change year-over-year was mainly due to a significant increase in temporary differences arising from the acquisition of StarPoint Energy Trust and increased depletion on recognition of purchase price increments.  Also, reductions to future corporate tax rates were enacted during the year by Federal, Alberta and Saskatchewan governments resulting in a future tax recovery of $32 million.  These were offset by a future tax expense of $33.6 million related to unrealized hedging gains.

On October 31, 2006, the Federal Government announced a proposal to introduce a new tax on publicly traded income trusts beginning in 2011.  On December 21, 2006, draft legislation to implement these proposals was released for comment.  If the legislation becomes enacted as currently proposed, the Trust will effectively become subject to tax on earnings in excess of available tax pools, in a similar manner as a corporation.  It is anticipated that future taxes would be then be adjusted to include temporary differences between accounting and tax bases of assets and liabilities at the Trust level.

Current Income Taxes

In general, both current and future income taxes are transferred to the unitholder level through various interest and/or royalty payments.  There are some corporate entities in the underlying structure which hold minority interests in some of the Trust’s operating partnerships which subject them to a small amount of current income tax.  The Trust has provided $2 million in this respect for the current year and $4 million in respect of prior periods.

Capital Taxes

Federal Large Corporations Tax was eliminated effective January 1, 2006 and thus no amount is provided 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 to the Saskatchewan Resource Surcharge and is higher compared to the previous year due to an increase in oil and gas revenue earned in the Province of Saskatchewan, a result of the significant number of Saskatchewan properties added through the StarPoint acquisition.

15

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 gas reserves are a non-renewable resource.  As they are produced, our objective is to replace those reserves through a combination of property acquisitions and internal drilling opportunities.  In 2005 and 2006, we have continued to increase our focus on upgrading the quality of our asset base through acquisition, exploiting our reserve base, drilling new wells and optimizing 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 and development activities totalled $351.3 million as compared to $172.2 million in 2005 (2004 — $91.8 million).  A total of 378 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) wells during the fourth quarter 2005 resulting in 161 gross (81.9 net) oil wells and 205 gross (85.4 net) natural gas wells.  The increase reflects the larger opportunity associated 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 wells and 32 gross (26.9 net) natural gas wells.

16

The Trust also completed two major acquisitions in 2006 totalling $3.5 billion.  The StarPoint transaction was completed by way of a Plan of Arrangement whereby unitholders of Acclaim received 0.8333 units of Canetic for each unit held and unitholders of StarPoint received one Canetic unit for each unit held.  Costs associated with the transaction were financed through our bank facility.  The merger was strategic in that it provided unitholders with a high quality asset base; a reserve base in excess of 230 million boe on a proved plus probable basis; a reserve life index in excess of 9 years; a diversified production base weighted 60 percent towards primarily light oil and a high quality low risk development drilling program.

On August 31, 2006, we closed the Samson acquisition which included properties in British Columbia and central Alberta.  We acquired approximately 13,500 boe/d of production, 40.1 million boe of proved plus probable reserves and 230,000 net acres of undeveloped land.  The acquisition was financed by the issuance of 20.8 million trust units for net proceeds of $437 million, as well as $230.0 million principal ($220.8 million net) of 6.5% convertible, extendible, unsecured, subordinated debentures.  The balance of the transaction was financed with bank debt.  In addition, Canetic purchased approximately $89.1 million of working capital on May 31, 2006 including $77 million of cash which was financed with long-term debt.

Sources Of Funding Net Capital Expenditures

			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 recognizes goodwill on corporate acquisitions when the total purchase price exceeds the fair value of the net identifiable assets and liabilities of the acquired entity.  Goodwill is tested annually at year-end for impairment or as events occur that could result in impairment.  Impairment is recognized and charged to income in the period in which the impairment occurs when the fair value of the Trust is less than the book value of the Trust.  A write down of goodwill was not required at December 31, 2006 or 2005.

The goodwill balance of $922.0 million arose primarily as a result of the StarPoint acquisition in 2006.  The balance was determined based on the excess of total consideration plus the future income tax liability less the fair value of the assets acquired for accounting purposes.

LIQUIDITY AND CAPITAL RESOURCES

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

The increase in capital expenditures in 2006 reflects both the costs associated with maintaining the larger producing asset base we now have, as well as the execution of growth programs that continue to be developed as we increase our operational knowledge of the properties acquired over the past three years.

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We finance our operations and capital activities primarily with funds generated from operating activities, but also through the issuance of trust units, debentures and borrowings from our credit facility.  The amount of equity we raise through the issuance of trust units depends on many factors including projected cash needs, availability of funding through other sources, our unit price and the state of the capital markets.  We believe our sources of cash, including bank debt, will be sufficient to fund our operations and anticipated capital expenditure program in 2007 as well as make monthly distribution payments.  Our ability to fund will also depend on performance and is subject to commodity prices and other economic conditions which are beyond our control.

In August 2006, in connection with the Samson acquisition, Canetic completed a $690 million bought deal equity and debenture issue.  The net proceeds of $657.8 million in addition to bank borrowings under our credit facility were utilized to fund the acquisition.  In addition, Canetic purchased working capital at May 31, 2006, of $89.1 million by drawing upon its bank facility. Working capital included approximately $77 million of cash.  Under the terms of the agreement Canetic will be kept whole in the event of uncollectability or valuation of working capital.

Canetic’s capital structure 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 unsecured covenant based credit facility with a syndicate of financial institutions in the amount of $1.6 billion including a $50.0 million operating facility.  The facility carries floating interest rates which range between 65.0 and 115.0 basis points over Banker’s Acceptance rates.  This facility was increased in the third quarter from $1.1 billion upon closing of the Samson acquisition.  The loan has a maturity date of May 31, 2009 and is reviewed annually and may be extended at the option of 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 is maintained by drawing from and repaying the unutilized credit facility as needed.  At December 31, 2006, Canetic had a working capital deficiency of $29.8 million including a financial derivative liability of $1.1 million.  The increase in bank debt year-over-year includes $293.5 million drawn on 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 cash at May 31, 2006.

Our net debt at December 31, 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, January 5, 2006

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CONVERTIBLE DEBENTURES

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 StarPoint debentures are described further below.

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

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

·StarPoint 6.5% Debentures (CNE.DB.B) - $18.96. Each $1,000 principal amount of StarPoint 6.5% Debentures is convertible into approximately 52.74 Canetic trust units;

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

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

·Canetic 6.5% Debentures (CNE.DB.E) - $26.55. Each $1,000 principal amount of Canetic 6.5% Debentures is convertible into approximately 37.66 Canetic trust units.

The following tables are a summary of the dollar value of issuances and conversions of the convertible debentures:

	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

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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 acquisition of Samson.  The conversion feature was valued at $2.5 million which has been allocated to equity.  The debentures have a face value of $1,000 per debenture, a coupon of 6.5%, a maturity date of December 31, 2011 and are convertible at any time, at the option of the holder, into the trust units of Canetic at a conversion price of $26.55 per trust unit.  The Trust may redeem the debentures in whole or 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, 2010 and before the maturity date.

On June 15, 2004, Acclaim issued $75.0 million principal amount of 8% convertible, extendible, unsecured, subordinated debentures.  The debentures have a face value of $1,000 per debenture, a coupon of 8.0%, a maturity date of August 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 whole or in part at a redemption price of $1,050 per debenture after August 31, 2007 and at a redemption price of $1,025 per debenture after August 31, 2008 and before the maturity date.

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

Convertible Debentures Assumed on Acquisition of StarPoint

StarPoint issued $60.0 million of 6.5% convertible, extendible, unsecured, subordinated debentures (the “StarPoint 6.5% Debentures”) on May 26, 2005.  The StarPoint 6.5% Debentures mature on July 31, 2010 and are convertible at any time, at the option of the holder, into the trust units of Canetic at a conversion price of $18.96 per trust unit.  The StarPoint 6.5% Debentures are not redeemable at the option of the Trust on or before July 31, 2008. After July 31, 2008, and prior to the maturity date, the StarPoint 6.5% Debentures may be redeemed 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 the StarPoint/APF Energy Trust Combination, and pursuant to a debenture agreement dated June 27, 2005, the 9.4% Debentures were assumed by StarPoint. The 9.4% unsecured, subordinated, convertible debentures are convertible at the holder’s option into fully paid and non-assessable trust units of Canetic at any time prior to July 31, 2008 at a conversion price of $16.02 per trust unit.  The 9.4% Debentures are redeemable at $1,050 per 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 had issued 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 and StarPoint on January 5, 2006, occurred pursuant to a Plan of Arrangement in which Canadian unitholders could elect to exchange their units on a tax-deferred basis.  Each Acclaim unitholder received  0.8333 of a Canetic trust unit for each unit held and each StarPoint unitholder received 1.0000 Canetic trust unit for each unit they held.  A total of 106.2 million units were issued pursuant to the Arrangement.  Also pursuant to the Arrangement, all exchangeable shares were exchanged for trust units.

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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

(1)  All disclosures of Acclaim units up to the merger January 5, 2006 have been restated using the exchange ratio of 0.8333 of a Canetic unit for each 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 from operations as presented is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with GAAP.

Funds flow from operations 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 from operations totalled $750.1 million or $3.57 per diluted unit, representing a 108 percent increase from the $360.5 million, or $3.98 per diluted unit during the same period in 2005 (2004 - $233.5 million or $3.09 per diluted unit).  The increase is due to higher production levels associated with the StarPoint and Samson acquisitions.  Our 2006 funds flow included a realized loss on financial derivative contracts of $8.5 million ($0.04 per diluted unit) as compared to a loss of $80.2 million ($0.88 per diluted unit) in 2005.

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

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We believe that funds generated from our operations, together with borrowings under our credit facility and proceeds from property dispositions, will be sufficient to finance our operations and planned capital expenditure program.  During 2006, funds flow in excess of distributions funded 47 percent of our capital expenditure program.  Our dividend reinvestment program plus additional bank borrowings funded the remaining 53 percent or $186.2 million.  We anticipate that our annual capital expenditures over the next few years will be similar to our capital expenditures in fiscal 2006.  We establish our capital expenditure program based on an annual budget review process, including budgeted cash flow from operations, and we closely monitor changes throughout the year.

CASH DISTRIBUTIONS

Canetic declared cash distributions of $583.5 million ($2.76/unit), representing 78 percent of 2006 funds flow from operations compared to cash distributions of $208.5 million ($2.34/unit), representing 58 percent of funds flow from operations in 2005.  The remaining 22 percent of funds flow in 2006 was utilized to fund 47 percent of Canetic’s 2006 capital program.

Effective with the merger with StarPoint, Canetic set its monthly distribution at $0.23 per unit per month beginning with distributions payable on February 15, 2006.  This represented an 18 percent increase to former Acclaim unitholders and a five percent increase to former StarPoint unitholders.

($000s, except where indicated)	2006		2005		2004
Funds flow from operations	750,146		360,475		233,473
Total distributions	583,528		208,477		176,741
Distributions per unit ($)	2.76		2.34		2.34
Payout ratio (%)	78	%	58	%	74	%

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

We distribute a portion of the funds flow from operations to our Trust unitholders on a monthly basis with a portion withheld to initially repay bank debt and ultimately fund capital expenditures.  Although the level of funds retained for capital expenditures and/or debt repayment typically varies, we monitor our distribution policy with respect to forecasted funds flows from operations, debt levels, spending plans and taxability.

Our 2006 distributions are 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 weaker short-term outlook for commodity prices, Canetic announced on January 15, 2007 that it would reduce the monthly distribution in order to increase the level of cash flow available to fund drilling and development opportunities, bring Canetic’s payout ratio in line with the Trust’s long-term target of 60 to 70 percent of funds flow from operations, and prudently manage the level of Canetic’s long-term debt.  The regular monthly distribution was fixed at $0.19 per trust unit, commencing with the January 31, 2007 distribution paid on February 15, 2007.

For the year ended December 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 cash distributions of $208.5 million ($2.34 per unit) representing a 58 percent payout ratio in 2005.

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

CONTRACTUAL OBLIGATIONS

In addition to financial derivative commitments, the Trust has the following contractual obligations as at 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 a general discussion of the Canadian and U.S. tax consequences of holding Canetic units as capital property.  The summary is not exhaustive in nature and is not intended to provide legal or tax advice.  Unitholders or potential unitholders should consult their own legal or tax advisors as to their particular tax consequences.

CANADIAN TAXPAYERS

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

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

Canetic paid $2.76 per trust unit in cash distributions to unitholders during the period February 2006 to January 2007.  For Canadian tax purposes, 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-deferred return of capital and 68.72 percent taxable.

The taxability of our distributions increased during 2006, a direct result of increased cash flows due to strong commodity prices and limited tax pools associated with the acquired assets.

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U.S. TAXPAYERS

Prior to 2005, U.S. unitholders who received cash distributions were subject to a 15 percent withholding tax, applied only on the taxable portion of the distribution as computed under Canadian tax law.  Legislative changes which took effect on January 1, 2005, imposed an additional 15 percent withholding tax on the non-taxable portion of the distribution.  U.S. taxpayers should be eligible for a foreign tax credit with respect to 100 percent of Canadian withholding taxes paid.

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

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

Canetic paid US$2.23 per trust unit to United States residents during the calendar year 2006.  The portion considered to be a qualified dividend will be announced immediately upon completion of the Trust’s calculation of current earnings and accumulated deficit for the year.

RISK MANAGEMENT

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

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

Acquisition of oil and natural gas assets depends on our assessment of value at the time of acquisition.  Incorrect assessments of value can adversely affect distributions to unitholders and the value of the units.  We employ experienced staff on the business development team and perform stringent levels of due diligence on our analysis of acquisition targets, including a detailed examination of reserve reports; re-engineering of reserves for a large portion of the properties to ensure the results are consistent; site examinations of facilities for environmental liabilities; detailed examination of balance sheet accounts; review of contracts; review of prior year tax returns and modeling of the acquisition to ensure accretive results to the unitholders.  The Board of Directors approves all acquisitions greater than $5 million.

Inherent in development of the existing oil and gas reserves are the risks, among others, of drilling dry holes, encountering production or drilling difficulties or experiencing high decline rates in producing wells.  To minimize these risks, we employ experienced staff to evaluate and operate wells and utilize appropriate technology in our operations.  In addition, we use prudent work practices and procedures, safety programs and risk management principles, including insurance coverage against potential losses.

We are subject to credit risk 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 trust units is based on the underlying value of the oil and natural gas reserves.  Geological and operational risks can affect the quantity and quality of reserves and the cost of ultimately recovering those reserves.  Lower oil and gas prices increase the risk of write-downs on our oil and gas property investments.  In order to mitigate this risk, our proven and probable oil and gas reserves are evaluated each year by a firm of independent reservoir engineers.  A special committee of the Board of Directors reviews and approves the reserve report.

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Our access to commodity markets may be restricted at times by pipeline or processing capacity.  We minimize these risks by controlling as much of our processing and transportation activities as possible and ensuring transportation and processing contracts are in place with reliable cost efficient counterparties.

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

The petroleum and natural gas industry is subject to both environmental regulations and an increased environmental awareness.  We have reviewed our environmental risks and are in compliance with the appropriate environmental legislation and have determined that there is no current material impact on our operations.

We are subject to financial market risk.  In order to achieve substantial rates of growth, we must continue reinvesting in, acquiring or drilling for petroleum and natural gas.  As we distribute the majority of our net cash flow to unitholders, we must finance a large portion of our acquisitions and development activity through continued access to equity and debt capital markets.  One source of funding for our acquisition/expenditure program is through the issuance of equity.  If we are not able to access the equity markets 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 conservative financing structure.

On October 31, 2006, the Canadian federal government announced proposals to introduce a new tax on distributions from existing publicly-traded income trusts.  If enacted as currently proposed, Canetic would be subject to these new taxes beginning in 2011, provided it does not experience “undue expansion” in the intervening period as that term is defined in the recently released federal guidelines on “normal growth”.  The intent of these rules is to impose tax on income trusts in a similar manner and at similar rates as public corporations and the distributions be treated as dividends at the investor level.  Income at the Trust level in excess of available tax shelter would be subject to the new tax at a statutory rate of 31.5 percent which would directly reduce cash available for distribution.  These rules have not been enacted and are discussed in more detail in an earlier section of the MD&A.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The Trust’s significant accounting policies are summarized in Note 1 to the Trust’s audited consolidated financial statements for the years ended December 31, 2006 and 2005. Certain of these policies are recognized as critical because in applying these policies, management is required to make judgments, assumptions and estimates that have a significant impact on the financial results of the Trust.

OIL AND GAS RESERVES

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

FULL COST ACCOUNTING

The Trust follows the full cost method of accounting for oil and natural gas activities.  Using the full cost method of accounting, all costs of acquiring, exploring and developing oil and natural gas properties are capitalized, including unsuccessful drilling costs and administrative costs associated with acquisitions and development.

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

Capitalized costs are depleted using the unit-of-production method based on estimated proved reserves of petroleum and natural gas before royalties as determined by independent petroleum engineers.  Costs relating to unproved properties are excluded from costs subject to depletion and depreciation until it is determined whether or not proved reserves exist or if impairment occurs.  Proved natural gas reserves and production are converted to equivalent volumes of crude petroleum based on the approximate relative energy content ratio of six thousand cubic feet of natural gas to one barrel of crude oil.

ASSET RETIREMENT OBLIGATIONS

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

BUSINESS COMBINATIONS

Management makes various assumptions in determining the fair values of any acquired company’s assets and liabilities in a business combination. The most significant assumptions and judgments made relate to the estimation of the fair value of the oil and natural gas properties. To determine the fair value of these properties we estimated oil and gas reserves and future prices of oil and natural gas.

INCOME TAXES

The Trust is not liable for income tax as it allocates substantially all of its taxable income to its unitholders.  Future income taxes are calculated for the corporate subsidiaries using the liability method whereby tax liabilities and assets are recognized for the estimated tax consequences attributable to differences between amounts reported in the financial statements and their respective tax base using substantively enacted income tax rates. The effect of a change in income tax rates in future tax liabilities and assets are recognized in income in the period in which the change occurs. The determination of income and other tax liabilities requires interpretation of complex laws and regulations. All tax filings are subject to audit and assessment by taxing authorities after the lapse of considerable time.  As a result, the actual income tax liability may differ from that recorded.

RECENT ACCOUNTING PRONOUNCEMENTS

FINANCIAL INSTRUMENTS

Effective January 1, 2007, the Trust will apply the following new CICA Handbook sections: Section 1530-Comprehensive Income; Section 3251-Equity; Section 3855-Financial Instruments — Recognition and Measurement; and Section 3865-Hedges. The new accounting pronouncements are effective for the first quarter of 2007, and address the recognition and measurement of financial assets, financial liabilities and non-financial derivatives.

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

BUSINESS RISKS

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

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DISCLOSURE CONTROLS AND PROCEDURES OVER FINANCIAL REPORTING

Disclosure controls and procedures are designed to provide reasonable assurance that all relevant information is gathered and reported to senior management, including the Chief Executive Officer (CEO) and the Chief Financial Officer (CFO), on a timely basis so appropriate decisions can be made regarding public disclosure. As at December 31, 2006, the CEO and the CFO have evaluated the effectiveness of Canetic’s disclosure controls and procedures as defined in Multilateral Instrument 52-109 (“MI 52-109”) of the Canadian Securities Administrators and have concluded that such disclosure controls and procedures are effective to provide reasonable assurance that material information related to the Trust is made known to them by employees or third party consultants working for the Trust.  It should be noted that while the CEO 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 well conceived or operated, can only provide reasonable assurance, and not absolute assurance, that the objectives of the control system are met.

INTERNAL CONTROLS OVER FINANCIAL REPORTING

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

OUTLOOK

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

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

In 2007, we will continue to actively exploit our asset base.  We have budgeted approximately $350 million for development related expenditures in 2007.  More than 80 percent of that amount will be allocated to drilling and new completion or optimization related activity directly impacting production and reserves performance.  The 2007 operated drilling program is weighted modestly to oil prone plays with substantial development targeting many of the former StarPoint properties which performed very strongly throughout 2006. We continue to target new completions in areas such as Acheson, where we have had significant success identifying and exploiting multiple zones in the large inventory of well bores we acquired through the ChevronTexaco transaction.

In the early part of 2007, our focus has been to tie in production from our successful fourth quarter 2006 drilling program, while also pursuing an aggressive drilling and optimization program on our producing properties.  During the fourth quarter of 2006, Canetic continued its strong performance of efficiently adding reserves and production. We exited the year with approximately 1,400 boe per day behind pipe, led by successful Q4 programs in the Acheson area, Southern and North West Alberta.  Following on the strength of the 2006 program and depth of opportunities, Canetic kicked off the largest first quarter development program in its history in 2007.  Canetic operated five to seven drilling rigs throughout the first quarter of 2007 and to date we have drilled 37 wells.  Canetic’s focus in 2007 will be on gas development in the Willesden Green area where our new 20 mmcf per day gas plant is now on stream, North-East BC where we are excited about the prospect of a Slave Point test and follow-ups, and continued programs in Border Plains and our Southern business unit. In addition, we have an aggressive drilling, new completion 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 a total of approximately 50 operated wells by the end of the first quarter of 2007, depending on seasonal impacts, such as the start of break-up.

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

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

In recent years the oil and 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 following the Canadian Government’s announcement on the taxation of trusts but more importantly in response to the recent weakness and volatility in commodity prices which is expected to result in cutbacks in overall industry drilling activity.  We currently intend to hold operating costs largely flat in 2007 at approximately $9.00 per boe and G&A costs at between $1.30 and $1.40 per boe.

As we look forward, we intend to continue executing our business strategy, which involves a balanced approach to acquisitions and effective asset exploitation and management programs.  Having completed over $4 billion in acquisitions since our inception, Canetic has accumulated an extensive inventory of development opportunities, including nearly one million net undeveloped acres. As a result, we do not feel it is necessary to complete any significant acquisitions in the near term though we will continue to monitor both asset and corporate acquisition opportunities which may arise as a result of the changing environment for trusts in Canada, including potential consolidation opportunities within the sector, unconventional opportunities, or expansion opportunities outside of Canada, particularly in the U.S.  In the meantime, Canetic will continue to focus on the development and exploitation of its significant resource base.

We look forward to an exciting and successful 2007.

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