Canetic Resources Trust 6-K Current report (foreign)

Exhibit 99.2

MANAGEMENT’S

DISCUSSION

AND ANALYSIS

This Management’s Discussion and Analysis (“MD&A”) should be read in conjunction with the audited Consolidated Financial Statements and Notes thereto of Canetic Resources Trust (“Canetic”, the “Trust”, “we”, “our” or “us”) for the year ended December 31, 2006, Canetic’s MD&A for the year ended December 31, 2006, and the unaudited Consolidated Financial Statements of Canetic and Notes thereto for the six months ended June 30, 2007.  This MD&A is dated August 9, 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”).  BOEs 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 law.  These statements relate to future events or future performances.  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 and expenses; 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; sources of funding operations and distributions and the sufficiency thereof; estimates of funds flow from operations; royalty rates; interest rates; asset retirement obligations; hedging and other risk management programs; debt levels, future tax treatment of income trusts such as the Trust and unitholders; income tax pools, 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 reserves volumes; the ability of Canetic to obtain equipment, services and supplies in a timely manner to carry

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out our 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; 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 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 Factors" in our 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 the following 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 GAAP and therefore 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 changes in non-cash working capital and asset retirement costs incurred to analyze operating performance and leverage.  “Funds flow from operations” should not be construed as an alternative to net earnings, cash flow from operating activities or other measures of financial performance calculated in accordance with GAAP.  Funds flow from operations cannot be assured and our future distributions may vary.  Readers should refer to the “Funds Flow From Operations” section of the MD&A for a reconciliation of funds flow from operations to net earnings.

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 funds flow on each boe of 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.

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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.  Readers 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.

FEDERAL INCOME TAX CHANGES

Bill C-52 (Budget Implementation Act, 2007) (the “SIFT Tax Act”) which contains the Specified Investment Flow-Through Rules (the “SIFT Rules”) received Royal Assent and became law on June 22, 2007.  Under the SIFT Rules, commencing January 1, 2011 (provided the Trust experiences only "normal growth" and no "undue expansion" as discussed below) certain of our distributions that would have otherwise been deductible by the Trust for tax purposes will be subject to a special tax at a rate of 31.5 percent (the “Distribution Tax”).  The intent of these rules is to impose tax on income trusts in a similar manner and at rates comparable to existing Canadian public corporations and to treat our distributions as dividends in the hands of our unitholders.  Effectively, trust level taxable income will be subject to the Distribution Tax and any taxes payable as a result will directly reduce cash available for distribution.  The funds flow impact will be minimized to the extent the Trust has tax pools available to shelter the Distribution Tax.  Currently, the Trust has approximately $1.6 billion of tax pools that may be used to offset future taxes.  This should allow us to defer payment of cash taxes beyond 2011.

Generally, trusts that were publicly traded on October 31, 2006 will have a four-year transition period (the “Transition Period”) and, subject to compliance with the Department of Finance’s Guidelines on “normal growth “ as described below, will not be subject to the SIFT Rules until January 1, 2011.

On December 15, 2006, the Department of Finance issued guidelines with respect to what is meant by "normal growth" and “undue expansion” which guidelines have been incorporated in the SIFT Rules.  Specifically, the Department of Finance stated that "normal growth" would include equity growth within certain "safe harbour" limits, measured by reference to the market capitalization of a Specified Investment Flow-Through Entity (a “SIFT”) as of the end of trading on October 31, 2006 (which would include only the market value of the SIFT's issued and outstanding publicly-traded trust units, and not any convertible debt, options or other interests convertible into or exchangeable for trust units) (the "Benchmark").  Those safe harbour limits are 40 percent of the Benchmark for the period from November 1, 2006 to December 31, 2007, and 20 percent of the Benchmark each for calendar 2008, 2009 and 2010.  Moreover, these limits are cumulative so that any unused limit for a period carries over into the subsequent period.  Additional details of the Department of Finance's guidelines include the following:

(a) new equity for these purposes includes units and debt that is convertible into units (and may include other substitutes for equity if attempts are made to develop those);

(b) replacing debt that was outstanding as of October 31, 2006 with new equity, whether by a conversion into trust units of convertible debentures or otherwise, will not be considered growth for these purposes and will therefore not affect the safe harbour;

(c) the exchange, for trust units, of exchangeable partnership units or exchangeable shares that were outstanding on October 31, 2006 will not be considered growth for those purposes and will therefore not affect the safe harbour where the issuance of the trust units is made in satisfaction of the exercise of the exchange right by a person other than the SIFT; and

(d) the merger of two or more SIFTs, each of which was publicly-traded on October 31, 2006, or a reorganization of such a SIFT, will not be considered growth to the extent that there is no net addition to equity as a result of the merger or reorganization.

Under the SIFT Rules, our total Benchmark at October 31, 2006 was approximately $4.5 billion.  Available safe harbour through to December 31, 2007 will be approximately $1.8 billion, which is 40 percent of the Benchmark.  The safe harbour for each of 2008, 2009, and 2010 is approximately $900 million, which is 20 percent of the Benchmark.  Should any portion of the safe harbour not be utilized in any period, this portion will be available in a subsequent period.

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While these guidelines are such that it is unlikely they alone would affect our ability to raise the capital required to maintain and grow our existing operations in the ordinary course during the Transition Period, they could adversely affect the cost of raising capital and our ability to undertake more significant acquisitions.

Distributions to individual Canadian resident unitholders will be treated as dividends from a taxable Canadian corporation and will be eligible for a dividend tax credit.  Distributions to corporations resident in Canada will be eligible for full deduction as tax-free inter-corporate dividends and potentially subject to a 33 1/3 percent refundable tax.  Tax-deferred accounts will continue to pay no tax on distributions.  Non-resident unitholders will be taxed on distributions at the non-resident withholding tax rate for dividends which potentially may be recovered as a foreign tax credit.  The impact of the Distribution Tax on cash distributions to unitholders post-2010 will be affected, to a large extent, by the amount of tax pools available to the Trust.  In the Transition Period, our objective will be to preserve and maximize tax pools that may be used to reduce or defer the incidence of cash taxes.

As a result of enactment of the SIFT Rules, the Trust has recognized additional future tax expense of approximately $330 million for the second quarter 2007.  This represents the tax effect on timing differences between the accounting and tax basis of net assets held at the trust level and in other flow-through entities.  These timing differences were not previously given recognition under GAAP.  This adjustment is a non-cash expense and has no immediate impact on funds flow from operations.

RESULTS OF OPERATIONS

QUARTERLY FINANCIAL AND OPERATING INFORMATION

	2007						2006									2005
($000s except per unit amounts)	June 30			Mar. 31			Dec. 31			Sept. 30		Jun. 30		Mar. 31		Dec. 31		Sept. 30
Production
Oil and NGLs (bbl/d)		42,592			43,337			43,402			44,239		42,391		43,388		21,915		22,323
Natural gas (mmcf/d)		211.0			220.1			221.2			181.4		166.0		176.1		105.8		107.4
Boe/d @ 6:1		77,765			80,027			80,276			74,475		70,061		72,737		39,541		40,227
Petroleum and natural gas sales		372,385			366,209			347,701			368,502		341,205		350,346		234,098		217,449
Funds flow from operations		192,044			190,368			170,084			200,268		185,053		194,741		106,477		92,679
Per unit - basic(1)(2)		0.84			0.84			0.76			0.95		0.92		0.97		1.16		1.03
Per unit - diluted(1)(2)		0.84			0.83			0.75			0.93		0.89		0.96		1.14		1.02
Net earnings (loss)		(301,798	)		(6,870	)		(21,632	)		102,663		82,875		59,195		48,662		6,538
Per unit - basic(1)(2)		(1.33	)		(0.03	)		(0.10	)		0.49		0.41		0.29		0.53		0.07
Per unit - diluted(1)(2)		(1.33	)		(0.03	)		(0.10	)		0.48		0.40		0.29		0.53		0.07
Distributions declared
Per unit		0.570			0.570			0.690			0.690		0.690		0.690		0.585		0.585

 (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) 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.  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.

Production volumes averaged 77,765 boe per day for the three months ended June 30, 2007 reflecting continued strength in our production volumes, offset during the quarter by expected turnaround and weather related downtime, as well as the sale of approximately 1,000 boe per day (600 boe per day for the quarter).  Crude oil prices continued to strengthen with the West Texas Intermediate (“WTI”) price averaging US$65.02 per barrel in the second quarter, as compared to US$58.23 per barrel in the first quarter 2007.  The AECO Monthly Spot price for natural gas averaged $7.37/mcf in the second quarter as compared to $7.46/mcf during the first quarter 2007.

The quarterly financial and operating results during the past eight quarters have been influenced by two major acquisitions.  On January 5, 2006, Canetic was formed on the completion of the merger of Acclaim Energy Trust

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(“Acclaim”) and StarPoint Energy Trust (“StarPoint”).  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 for 2005 are those of Acclaim only.  At the time of the merger the StarPoint assets were producing approximately 35,000 boe per day.  On August 31, 2006, we closed the Samson acquisition for approximately $900 million.  At closing, the Samson assets were producing approximately 13,500 boe per day including 70.0 million cubic feet (“mmcf”) per day of natural gas.

Quarter-over-quarter petroleum and natural gas sales are influenced by changes in production volumes and commodity prices.  Although commodity prices have generally increased over the past two years, there are fluctuations quarter-over-quarter which impact petroleum and natural gas revenues.  In combination with increased production volumes from the StarPoint merger in January 2006 and the Samson acquisition, which closed August 31, 2006, petroleum and natural gas sales have increased relative to 2005.

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.  The net loss in the most recent quarter reflects the adjustment made to future income taxes as a result of the SIFT Rules enacted during the quarter (See “Federal Income Tax Changes”, Page 4).  The effect of this legislation is to increase Canetic’s future income tax expense and liability by approximately $330 million.  This adjustment represents the tax effect on timing differences between the accounting and tax basis of net assets held.  These timing differences were not previously given recognition.  This adjustment is a non-cash expense and has no immediate impact on funds flow from operations available for distribution to unitholders.  In the absence of the charge to reflect the SIFT Tax enactment, net earnings for the quarter and first half of 2007 would have been $28.2 million and $21.3 million respectively.

PRODUCTION

Production volumes averaged 78,890 boe per day for the six months ended June 30, 2007 compared to 71,392 boe per day for the same period in 2006.  The 11 percent increase in average production volumes resulted primarily from the Samson acquisition. Relative to the first quarter 2007, production volumes were slightly lower due to spring break-up, plant turnarounds, wet weather, and natural production declines.  In addition, we sold approximately 1,000 boe per day of production, primarily natural gas, in Northeast Alberta effective April 30, 2007.  The impact on second quarter production was approximately 600 boe per day.

Wet weather and an extended spring break-up during the second quarter 2007 led to prolonged road bans and regulatory and lease access restrictions as well as delays in the execution of various repair and maintenance and well completion projects.  Expanded turnaround activity and unplanned third party facility outages also had significant impacts on production volumes through the quarter.  In total, we estimate approximately 1,000 boe per day of production was lost as a result of turnarounds and facility outages, weather, and extended spring break-up related restrictions.  We anticipate continued turnaround activity in the third quarter with a scheduled outage in the Kaybob South and Simonette fields (impact of approximately 1,500 to 1,800 boe per day to Canetic through July), as well as a scheduled outage by Canetic at our Gilby 5-5 facility in September (impact of approximately 1,500 boe per day for approximately three weeks).  In addition, we are planning an outage at our Pouce Coupe battery and gas handling facilities in September, and may take advantage of the softness in natural gas prices to complete a number of smaller turnarounds prior to the winter heating season. These turnarounds are all for preventative maintenance purposes in accordance with good operating practices.

	Three Months Ended June 30						Six Months Ended June 30
Production	2007			2006			2007			2006
Natural gas (mmcf/d)		211.0			166.0			215.6			171.0
Crude oil (bbl/d)		35,928			37,348			36,173			37,486
Natural gas liquids (bbl/d)		6,664			5,043			6,789			5,401
Barrels of oil equivalent (boe/d, 6:1)		77,765			70,061			78,890			71,392
Percentage natural gas		45	%		39	%		46	%		40	%
Percentage crude oil and natural gas liquids		55	%		61	%		54	%		60	%

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Crude oil and natural gas liquids production for the first six months of 2007 averaged 42,962 bbl per day, essentially unchanged from 42,887 bbl per day reported for the corresponding period in 2006.  Production in the second quarter 2007 averaged 42,592 bbl per day as compared to 42,391 bbl per day in the second quarter 2006.

Natural gas sales for the first six months of the year averaged 215.6 mmcf per day, 26 percent higher than the 171.0 mmcf per day reported for the first six months of 2006.  During the second quarter, natural gas sales averaged 211.0 mmcf per day, a 27 percent increase from 166.0 mmcf per day reported during the same quarter in 2006.

COMMODITY PRICES

	Three Months Ended June 30				Six Months Ended June 30
Benchmark Prices - (Quarterly Averages)	2007		2006		2007		2006
WTI crude oil (US$/bbl)		65.02		70.70		61.64		67.14
NYMEX natural gas averaged near month contract (US$/mcf)		7.54		6.89		7.39		8.56
AECO natural gas monthly index ($/mcf)		7.37		6.27		7.42		7.78
Canadian/U.S. dollar exchange rate		0.9113		0.8914		0.8825		0.8788

The price of WTI crude averaged US$65.02 per bbl during the second quarter 2007, down eight percent from the average price of US$70.70 per bbl for the same period in 2006.  For the first six months of 2007, West Texas Intermediate crude averaged US$61.64 per bbl compared to US$67.14 per bbl for the same period in 2006.  The AECO Monthly Index gas price averaged $7.37 per mcf in the second quarter of 2007, up 18 percent from $6.27 per mcf received in the second quarter 2006.  Year-to-date, the AECO Monthly Index price has averaged $7.42 per mcf, down five percent from the $7.78 per mcf received for the same period in 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 such as Edmonton and Hardisty, Alberta.  Canadian prices adjust WTI for the Canadian to U.S. dollar 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 quoted on either a monthly or daily index basis.

	Three Months Ended June 30				Six Months Ended June 30
Average Prices - (before financial derivatives)	2007		2006		2007		2006
Natural gas ($/mcf)		7.72		5.97		7.68		7.49
Crude oil ($/bbl)		59.95		67.29		58.59		60.82
Natural gas liquids ($/bbl)		46.85		48.90		44.96		47.82

For the six months ended June 30, 2007, we received an average oil price of $58.59 per bbl as compared to $60.82 per bbl for the comparable period in 2006.  Our average oil price of $59.95 per bbl during the quarter represents a decrease of 11 percent from an average of $67.29 per bbl reported during the same period in 2006.

Our average natural gas price was $7.68 per mcf for the six months ended June 30, 2007 as compared to $7.49 per mcf during the same period in 2006.  Our average natural gas price for the quarter was $7.72 per mcf which represents a 29 percent increase from the second quarter in 2006.

COMMODITY PRICE RISK MANAGEMENT

The prices we receive for 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 adverse commodity price movements, while retaining the opportunity to participate in favourable price movements.  This practice is designed to allow us to generate stable funds flow for distributions and achieve positive economic returns on capital development and acquisition activities.

During the second quarter 2007, we recorded a realized financial derivative gain of $0.6 million as compared to a loss of $5.6 million for the same period in 2006.

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

Commodity Contracts					Annual Average
Natural Gas	Q3 2007		Q4 2007		2008
Fixed Price Volume (Gj/d)		50,000		20,000		-
Fixed Price Average ($/Gj)	$	7.32	$	7.51		-
Collars Volume (Gj/d)		80,000		86,667		22,500
Collar Floors ($/Gj)	$	6.74	$	6.92	$	7.00
Collar Caps ($/Gj)	$	9.62	$	10.74	$	11.23
Total Volume Hedged (Gj/d)		130,000		106,667		22,500

Crude Oil	Q3 2007		Q4 2007		2008
CDN Denominated Fixed Price Volumes (bbl/d)		8,000		8,000		250
CDN Denominated Fixed Price Average ($CDN/bbl)	$	67.26	$	67.26	$	72.20
U.S. Denominated Fixed Price Volume (bbl/d)		1,500		1,500		-
U.S. Denominated Fixed Price Average ($US/bbl)	$	48.11	$	48.11		-
Collars Volume (bbl/d)		6,000		6,000		10,000
Collar Floors ($US/bbl)	$	58.00	$	58.00	$	64.00
Collar Caps ($US/bbl)	$	80.76	$	80.76	$	81.67
Total Volume Hedged (bbl/d)		15,500		15,500		10,250

CURRENCY RISK MANAGEMENT

The Canadian dollar averaged US$0.8825 during the first six months of 2007 as compared to US$0.8788 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 often seeks to mitigate 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 2007, Canetic had no foreign exchange contracts, but had entered into contracts for 8,000 bbl per day of its crude oil production using Canadian dollar denominated swaps.

PETROLEUM AND NATURAL GAS SALES

	Three Months Ended June 30				Six Months Ended June 30
Revenue($000s)	2007		2006		2007		2006
Crude oil and natural gas liquids		224,219		250,939		438,846		459,611
Natural gas		148,166		90,266		299,748		231,940
Petroleum and natural gas sales		372,385		341,205		738,594		691,551

Crude oil and NGL sales before derivative gains and losses decreased five percent for the six months ended June 30, 2007 to $438.8 million from $459.6 million in 2006.  The decrease is attributable to lower crude oil and natural gas liquids prices as compared to the same period a year earlier, offset by slightly higher production levels.  Revenue for the second quarter 2007 decreased 11 percent to $224.2 million from $250.9 million during the same period in 2006.

Natural gas sales increased 29 percent from $231.9 million to $299.7 million during the six months ended June 30, 2007.  Increased sales volumes combined with strong natural gas prices during the second quarter relative to the same period in 2006 were responsible for the strength in natural gas revenues.  Average daily sales of natural gas increased 27 percent to 211.0 mmcf per day in the second quarter 2007 from 166.0 mmcf per day in 2006 primarily as a result of the volumes acquired in the Samson acquisition net of property dispositions made during the quarter.

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ROYALTIES

	Three Months Ended June 30						Six Months Ended June 30
Royalties($000s)	2007			2006			2007			2006
Royalties, net of ARTC		67,506			65,095			134,289			132,219
Percentage of Petroleum and natural gas revenue		18.1	%		19.1	%		18.2	%		19.1	%
$/boe		9.54			10.21			9.40			10.23

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 our 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.  There is a maximum rate of 30 percent for new gas, which represents the vast majority of our natural gas production.  Using second quarter gas prices, we are 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 six months ended June 30, 2007, royalties totalled $134.3 million as compared to $132.2 million during the same period a year earlier.  As a percentage of sales, royalties averaged 18.2 percent during the six months ended June 30, 2007 as compared to 19.1 percent in the same period in 2006.  The change in royalty rate reflects the lower royalty burden carried on crude oil as compared to natural gas.

During the second quarter, royalties averaged $9.54 per boe or approximately 18.1 percent of Canetic’s total petroleum and natural gas sales price (before hedging) of $52.62 per boe.  This compares to $10.21 per boe or 19.1 percent of average sales price reported for the same period in 2006.

We expect that the average royalty rate for the remainder of 2007, based on current commodity prices, to approximate 18.0 to 19.0 percent.

OPERATING COSTS

	Three Months Ended June 30				Six Months Ended June 30
Operating Costs ($000s)	2007		2006		2007		2006
Operating costs before unit-based compensation		72,845		56,082		141,607		111,647
Unit-based compensation:
Cash expense		17		-		330		-
Non-cash unit-based compensation		689		1,755		666		2,800
Total operating costs and unit-based compensation		73,551		57,837		142,603		114,447
$/boe before unit-based compensation		10.29		8.80		9.92		8.64
$/boe after unit-based compensation		10.39		9.07		9.99		8.86

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 an income trust 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 personnel, repairs and maintenance required to keep the wells on production, and the recovery techniques utilized to extract the reserves.

8

Our operating costs, net of processing fees and before unit-based compensation, increased during the quarter to $72.8 million as compared to $56.1 million during the same period a year earlier.  On a unit-of-production basis, operating costs averaged $10.29 per boe compared to $8.80 per boe a year earlier, an increase of 17 percent.  During the first quarter 2007, operating costs before unit-based compensation totalled $68.8 million or $9.55 per boe.  As has been the case over the past 12 - 24 months, a general theme throughout the industry has been higher field service costs including fuel and power, labour, trucking, and other related mechanical services.  These increases have caused operating costs quarter-over-quarter and year-over-year to increase on a unit-of-production basis.

Our previous estimate of $8.50 - $9.50 per boe operating costs for 2007 has been impacted by cold weather and associated repairs and maintenance, plant turnarounds, processing fees, property taxes, and slightly lower production volumes.  The increase also reflects continued cost pressures due to historically high levels of industry activity.

Although operating costs continue to be a challenge, we maintain our commitment to managing operational efficiencies and optimizing 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 help to control operating costs on a unit-of-production basis, including the divestiture of assets which have a high cost base.

Based on the foregoing, we now estimate operating costs to average $10.00 - $11.00 per boe for the remainder of 2007.  This estimate reflects the current cost environment that exists in Western Canada and the cost pressures on our production operations.

PETROLEUM AND NATURAL GAS TRANSPORTATION

	Three Months Ended June 30				Six Months Ended June 30
Transportation ($000s)	2007		2006		2007		2006
Transportation expense		4,749		4,292		11,907		8,736
$/boe		0.67		0.67		0.83		0.68

Transportation costs are defined by the point of legal custody transfer of the commodity and are 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, adjusted for the quality of Canetic’s crude, 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.

In British Columbia, Westcoast Energy Inc. (operated by Spectra Energy) controls most of the gas processing infrastructure.  Individual producers negotiate tolls with Spectra, under light-handed NEB regulations, for gathering, processing, and transmission.  These tolls are included in the transportation expense.

NETBACKS

Cash net operating income represents the profit margin associated with the production and sale of petroleum and natural gas.  For the six months ended June 30, 2007, our netbacks were influenced by our product mix, commodity prices, financial derivative gains, royalty rates, the Canadian dollar relative to the U.S. dollar, and higher operating costs.

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Components of our netbacks are as follows:

	Three Months Ended June 30						Six Months Ended June 30
Netbacks($/boe)	2007			2006			2007			2006
Petroleum and natural gas revenue		52.62			53.52			51.73			53.52
Less:
Royalties		9.54			10.21			9.40			10.23
Operating costs (before unit-based compensation)		10.29			8.80			9.92			8.64
Transportation		0.67			0.67			0.83			0.68
Cash net operating income		32.12			33.84			31.58			33.97
General and administrative (before unit-based compensation)		1.77			1.79			1.60			1.49
Interest on long-term debt		2.24			1.74			2.22			1.57
Interest on convertible debentures		0.64			0.23			0.66			0.16
Realized (gain) loss on financial derivatives		(0.08	)		0.89			(0.30	)		1.06
Current income taxes		0.08			(0.04	)		0.17			(0.02	)
Capital tax		0.34			0.21			0.32			0.31
Cash netback from operations		27.13			29.02			26.91			29.40
Reconciliation to net earnings (loss):
Unit-based compensation		0.67			1.83			0.47			1.44
Depletion, depreciation and amortization		24.84			23.52			24.68			23.25
Accretion		0.55			0.39			0.54			0.38
Unrealized (gain) on financial derivatives		(6.63	)		(0.37	)		(0.10	)		(0.57	)
Future income taxes (recovery)		50.35			(9.35	)		22.94			(6.12	)
Net earnings (loss)		(42.65	)		13.00			(21.62	)		11.02

GENERAL AND ADMINISTRATIVE EXPENSES

	Three Months Ended June 30						Six Months Ended June 30
General and Administrative Expenses ($000s)	2007			2006			2007			2006
G&A expenses		18,455			15,972			36,105			28,187
Overhead recoveries		(5,924	)		(4,550	)		(13,247	)		(8,894	)
Cash G&A expenses before unit-based compensation		12,531			11,422			22,858			19,293
Unit-based compensation:
Cash expense		99			-			1,872			-
Non-cash unit-based compensation		3,905			9,942			3,775			15,870
Total G&A and unit-based compensation		16,535			21,364			28,505			35,163
$/boe before unit-based compensation		1.77			1.79			1.60			1.49
$/boe after unit-based compensation		2.34			3.35			2.00			2.72

General and administrative expenses, net of overhead recoveries and before unit-based compensation, totalled $22.9 million for the six months ended June 30, 2007 as compared to $19.3 million for the same period a year earlier.  On a unit-of-production basis, general and administrative expenses averaged $1.60 per boe as compared to $1.49 per boe for the same period in 2006.  During the past eighteen months, Canetic has increased the amount of production owned from approximately 39,541 boe per day on January 1, 2006 to approximately 77,765 boe per day at June 30, 2007, necessitating increased staffing and administration levels.

For the three months ended June 30, 2007, general and administrative expenditures before unit-based compensation totalled to $12.5 million, 10 percent higher than the $11.4 million recorded in the second quarter 2006.  The increase resulted primarily from costs associated with Canetic’s short-term incentive program which is determined and paid annually on April 15^th.  Payments in the current year exceeded our anticipated payout by approximately $1.0 million and consequently increased general and administrative expenses on a unit-of-production basis by approximately $0.07 per boe.

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General and administrative expenses for each of the next two quarters of 2007 are expected to average approximately $1.40 per boe before unit-based compensation.

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 units issuable pursuant to the PTUs 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.  Based on this criteria, the PTUs are assigned a PTU multiplier between the range of zero and two.  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.

For the six months ended June 30, 2007, the Trust recorded a unit-based compensation expense of $6.6 million (2006 - $18.7 million) and capitalized unit-based compensation of $4.5 million (2006 - $6.7 million).  Upon vesting, the obligation may be settled in units or cash.  The amounts due in the current year are $9.1 million (2006 - $16.6 million) which are reflected as a current liability in the financial statements.  The compensation liability is remeasured each period at the current market price.  The June 30, 2007 compensation liability was based on the period-end closing price of $17.32 and the number of RTUs and PTUs outstanding at that time, with the PTUs adjusted for the PTU multiplier.  Each tranche of PTUs issued potentially has a different PTU multiplier.  As of June 30, 2007, there were 791,679 RTUs and 1,323,073 PTUs outstanding.

INTEREST EXPENSE ON LONG-TERM DEBT

	Three Months Ended June 30				Six Months Ended June 30
Interest Expense ($000s)	2007		2006		2007		2006
Interest expense		15,824		11,103		31,713		20,289
Bank loans		1,342,738		893,792		1,342,738		893,792
Debt to annualized funds flow		1.7		1.2		1.8		1.2

Interest expense, representing interest on bank debt, increased to $31.7 million or $2.22 per boe from $20.3 million or $1.57 per boe a year earlier.  Average debt levels have increased as a result of the Samson acquisition made during 2006.  At June 30, 2007, $1.34 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 continue to reflect our higher debt levels.  Average interest rates incurred by Canetic during the quarter averaged approximately five percent.

Interest expense for the three months ended June 30, 2007 totalled $15.8 million as compared to $11.1 million during the same period in 2006.

INTEREST EXPENSE ON CONVERTIBLE DEBENTURES

Interest expense on convertible debentures totalled $9.4 million for the six months ended June 30, 2007 as compared to $2.1 million for the same period in 2006.  During 2006, debentures totalling $230.0 million were issued in conjunction with the Samson acquisition.  At June 30, 2007, debentures totalling $260.3 million remain outstanding.

DEPLETION, DEPRECIATION AND AMORTIZATION

The current quarter provision for depletion, depreciation and amortization totalled $175.8 million as compared to $150.0 million in 2006.  On a unit-of-production basis, depletion, depreciation and amortization costs averaged $24.84 per boe as compared to $23.52 per boe for the same period in 2006.

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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 June 30, 2007, we recorded a net financial derivative asset of $6.5 million.  The estimated fair value is based on a mark-to-market calculation as at June 30, 2007 to settle the financial contracts.  The actual gain or loss realized upon settlement could vary significantly due to fluctuations in commodity prices.  At June 30, 2007, Canetic recorded an unrealized financial derivative gain of $1.5 million (2006 - gain of $7.3 million) which represents the change in the mark-to-market calculations from December 31, 2006.

	Three Months Ended June 30					Six Months Ended June 30
Gain (Loss) on Financial Derivatives ($000s)	2007		2006			2007		2006
Realized cash gain (loss) on financial derivatives		575		(5,646	)		4,286		(13,675	)
Unrealized gain (loss) on financial derivatives		46,898		2,372			1,482		7,306
Gain (loss) on financial derivatives		47,473		(3,274	)		5,768		(6,369	)

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 funds flow has been calculated using a credit adjusted risk free discount rate of eight percent and an inflation rate of two percent.

As of June 30, 2007, the amount to be recorded as the fair value of the liability was estimated to be $194.0 million (2006 - $123.0 million).  During the six months ended June 30, 2007, Canetic incurred $7.1 million (2006 - $5.9 million) of actual abandonment and reclamation costs and recorded accretion of $7.7 million (2006 - $4.9 million).

INCOME TAXES

Enactment of Bill C-52, Budget Implementation Act, 2007

As a result of enactment of the SIFT Rules (see “Federal Income Tax Changes”, Page 4), the Trust has recognized additional future income tax expense and corresponding future income tax liability of approximately $330 million during the quarter.  This represents the incremental future income taxes on differences between the accounting and tax basis of assets and liabilities currently held at the trust level which are expected to remain at the time the Distribution Tax becomes effective.  Prior to this legislation, future income taxes were only recognized on timing differences arising in corporate subsidiaries which were not considered to be flow-through entities for tax purposes.  While this adjustment has a significant impact on earnings for the period, this is a non-cash expense which has no immediate impact on funds flow from operations available for distribution to unitholders.

The Trust currently has approximately $1.6 billion in tax pools which may be used in the future to shelter the Distribution Tax.  In the Transition Period, our objective will be to preserve and maximize tax pools that will be available to reduce or defer the incidence of cash taxes.

Future Income Taxes

For the six months ended June 30, 2007, the Trust recognized future tax expense of $328 million compared with a future tax recovery of $79 million for the same period in 2006.  The extraordinary increase is due to the one-time charge to future tax expense associated with the enactment of the SIFT Tax Act as described above.  This was partially offset by future tax recoveries of $4 million as a result of an additional 0.5 percent reduction to the federal general corporate tax rate also enacted during the period and $17 million from the change in timing differences in respect of the current period.  The Trust has also provided $20 million as a reserve against future income taxes due to uncertainty in the ability to fully access a portion of our successored tax pools over time under the SIFT Tax Act.

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Current Income Taxes

Although the Trust is not subject to the Distribution Tax until the year 2011, there are certain corporate entities in the underlying structure which hold minority interests in some of the Trust’s operating partnerships which are subject to a small amount of current income tax.  Current taxes of $2.4 million were accrued for the six months ended June 30, 2007.  $1.2 million of this amount is non-recurring and arose on the merger of Acclaim and StarPoint.

Capital Taxes

The Trust accrued $4.6 million of capital tax for the six months ended June 30, 2007 attributable to the Saskatchewan Resource Surcharge. Federal capital taxes were eliminated in 2006.

ESTIMATED INCOME TAX POOLS

Estimated Income Tax Pools ($000s)	June 30, 2007
Undepreciated capital costs		554,311
Canadian oil and gas property expense		505,787
Canadian exploration expense		23,820
Canadian development expense		344,543
Non-capital losses		144,386
Other		38,653
Total estimated income tax pools		1,611,500

CAPITAL EXPENDITURES

	Three Months Ended June 30						Six Months Ended June 30
Capital Expenditures ($000s)	2007			2006			2007			2006
Land		2,187			5,015			3,946			7,797
Geological and geophysical		2,010			600			2,150			1,733
Drilling and completion		59,874			63,636			163,553			118,084
Production equipment and facilities		25,103			16,525			67,598			25,176
Net development expenditures		89,174			85,776			237,247			152,790
StarPoint acquisition		-			-			-			2,511,746
Minor property acquisitions		917			23,869			1,836			23,869
Minor property dispositions		(46,470	)		(5,000	)		(49,427	)		(5,000	)
Net capital expenditures		43,621			104,645			189,656			2,683,405
Office		1,849			2,710			4,948			3,063
Asset retirement obligation change in estimate		223			547			1,493			1,472
Capitalized compensation		4,535			4,095			6,097			6,654
Total capital expenditures		50,228			111,997			202,194			2,694,594

During the six months ended June 30, 2007, expenditures for development activities totalled $237.2 million as compared to $152.8 million for the same period in 2006.  A total of 124 gross (69.2 net) wells were drilled during the period, including 51 gross (27.3 net) natural gas wells and 61 gross (39.2 net) oil wells, 7 gross (1.1 net) service wells, and 5 gross (1.6 net) dry and abandoned wells.  The increase in drilling activity reflects opportunities associated with our asset base as a result of the acquisitions made in 2006 and a decision by Canetic to become more active in the early months of the year.  Of the total wells drilled, 51 gross (47.0 net) were operated by Canetic resulting in 37 gross (34.7 net) oil wells, 13 gross (11.3 net) natural gas wells, and 1 gross (1.0 net) dry and abandoned (“D&A”).  Canetic has also changed the profile of our operated drilling program in 2007 over 2006.  We are targeting deeper and consequently higher cost targets such as the Slave Point development in Clarke Lake.  This compares to a higher proportion of shallow operated wells in 2006, which also included a large shallow high working interest Coal-Bed-Methane program in Big Bend.

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During the second quarter, development expenditures totalled $89.2 million as compared to $85.8 million for the same period in 2006.  Included in drilling and completion costs of $59.9 million are $38.3 million of optimization and workover costs incurred during the three-month period to maximize production efficiencies and mitigate production declines.  Canetic also completed net property dispositions totalling $46.5 million.  Proceeds from the dispositions were initially utilized to reduce bank indebtedness, but subsequently utilized to fund a portion of the 2007 capital expenditure program.

Sources of Funding Net Capital Expenditures

($millions)
Net Capital Expenditures	Six Months Ended June 30, 2007
Percentage funded by:
Funds flow		143.6	76%
DRIP		20.0	10%
Bank debt and non-cash working capital		26.1	14%
		189.7	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 June 30, 2007.

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

Typical of oil and gas trusts, Canetic’s asset base is anticipated to decline over time and therefore we 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 additional reserves.

The increase in capital expenditures in the fourth quarter 2006 and the first half of 2007 reflects the costs associated with maintaining our larger producing asset base and the execution of expanded growth programs as we increase our operational knowledge of the properties acquired over the past number of years.

Canetic finances 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 anticipated financings and bank debt, will be sufficient to fund our operations and planned capital expenditure program in 2007 as well as make monthly distribution payments.  Our ability to fund distributions also depends on performance and is subject to commodity prices and other economic conditions beyond our control.

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Canetic’s capital structure at June 30, 2007 is reconciled as follows:

	Six Months Ended June 30
	2007					2006
($000s except per unit amounts)	Amount		%	$/unit		Amount		%	$/unit
Debt
Bank debt		1,342,738	29		5.90		893,792	21		4.41
Working capital deficiency		29,108	1		0.13		86,047	2		0.42
Net debt		1,371,846	30		6.03		979,839	23		4.83
Convertible debentures (long-term portion)(1)		250,550	5		1.10		36,850	1		0.18
Unitholders’ equity		2,968,103	65		13.03		3,247,548	76		16.04
Total capitalization		4,590,499	100		20.16		4,264,237	100		21.05

⁽¹⁾ Net of deferred transaction costs.

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 2006 from $1.1 billion upon closing of the Samson acquisition.  The loan has a maturity date of May 31, 2009, is reviewed annually, and may be extended at the option of the lender for an additional one-year period.  The loan has therefore been classified as long-term on the balance sheet.

At June 30, 2007, $1.3 billion was drawn under the facility. Working capital liquidity is maintained by drawing from and repaying the unutilized credit facility as needed.  At June 30, 2007, Canetic had a working capital deficiency of $29.1 million.  Although our debt levels may fluctuate from quarter to quarter based on our capital program, it is our intent to exit 2007 at levels similar to year-end 2006.

Our net debt at June 30, 2007 and 2006 is reconciled as follows:

	Six Months Ended June 30
($000s)	2007		2006
Bank debt		1,342,738		893,792
Working capital deficiency		29,108		86,047
Net debt		1,371,846		979,839

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CONVERTIBLE DEBENTURES

At June 30, 2007, we had convertible debentures outstanding of $260.3 million.  The debentures consist of 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 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% Debenturesis 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 isconvertible into approximately 64.27 Canetic trust units;

•           Acclaim 11% Debentures (CNE.DB.D) - $11.24. Each $1,000 principal amount of 11% Debentures isconvertible 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 summarize the dollar value of issuances and conversions of the convertible debentures:

($000s)		9.4%		6.5%		8%			11%			6.5%
	(CNE.DB.A)		(CNE.DB.B)		(CNE.DB.C)			(CNE.DB.D)			(CNE.DB.E)			Total
Balance, December 31, 2006		5,622		17,821		8,046			1,697			227,470			260,656
Converted to units		-		-		(17	)		(388	)		-			(405	)
Deferred transaction costs		-		-		(268	)		(42	)		(8,082	)		(8,392	)
Balance, June 30, 2007		5,622		17,821		7,761			1,267			219,388			251,859

(000s)		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
Balance, December 31, 2006		351		940		517			152			8,663		10,623
Converted to units		-		-		(1	)		(35	)		-		(36	)
Balance, June 30, 2007		351		940		516			117			8,663		10,587

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 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.

16

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 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 June 30, 2007, Canetic had issued capital of 227.8 million trust units and as at August 9, 2007, we had issued capital of 228.1 million trust units.  If all outstanding convertible debentures were converted into trust units, a total of 238.3 million trust units would have been outstanding as at June 30, 2007 and 238.7 million trust units as at August 9, 2007.

	Six Months Ended June 30, 2007				Year ended December 31, 2006
Trust Units	Units (000s)		Amount ($000s)		Units (000s)		Amount($000s)
Balance, beginning of period		225,796		4,224,470		91,583		1,087,459
Issued:
Bought deal financing, net of costs		-		-		20,769		437,001
Employee Unit Savings Plan		232		3,623		274		6,184
Distribution reinvestment plan		1,469		21,379		2,470		44,825
Issued pursuant to Arrangement		-		-		106,242		2,562,563
Properties contributed to TriStar		-		-		-		(5,000	)
Conversion of debentures		36		405		2,042		36,302
Conversion of debentures - equity portion		-		-		-		4,636
Conversion of exchangeable shares		-		-		358		3,804
Unit award incentive plan		217		3,263		2,058		46,696
Balance, end of period		227,750		4,253,140		225,796		4,224,470

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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.

	Three Months Ended June 30						Six Months Ended June 30
Funds Flow($000s)	2007			2006			2007			2006
Net earnings (loss)		(301,798	)		82,875			(308,668	)		142,070
Adjustments for:
Unit-based compensation expense		4,594			11,697			4,441			18,670
Depletion, depreciation and amortization		175,784			149,972			352,224			300,490
Accretion of asset retirement obligation		3,876			2,457			7,739			4,908
Accretion of deferred transaction costs		163			-			603			-
Unrealized loss on financial derivatives		(46,898	)		(2,372	)		(1,482	)		(7,306	)
Future income taxes		356,323			(59,576	)		327,555			(79,038	)
Funds flow from operations		192,044			185,053			382,412			379,794
Unitholders’ equity		2,968,103			3,247,548			2,960,103			3,247,548

For the six months ended June 30, 2007, funds flow from operations totalled $382.4 million or $1.69 per diluted unit, representing a slight increase from $379.8 million, or $1.84 per diluted unit during the same period in 2006.

We believe that funds generated from our operations, together with anticipated financings, borrowings under our credit facility, and proceeds from property dispositions, will be sufficient to finance our operations and planned capital expenditure program.  During the six months ended June 30, 2007, funds flow from operations in excess of distributions funded 76 percent of our capital expenditure program reflecting the high weighting of our capital investment to the first six months of 2007.  Our dividend reinvestment program plus additional bank borrowings funded the remaining 58 percent.  We establish our capital expenditure program based on an annual budget review process, including budgeted funds flow from operating activities, and we closely monitor changes throughout the year.

CASH DISTRIBUTIONS

During the second quarter 2007, Canetic declared cash distributions (before the Dividend Reinvestment Plan) of $129.6 million ($0.57/unit), representing 67 percent of funds flow from operations compared to cash distributions of $139.5 million ($0.69/unit), representing 75 percent of funds flow from operations in the second quarter 2006.  The remaining 33 percent of funds flow was utilized to fund 65 percent of Canetic’s second quarter 2007 capital program.

	Three Months Ended June 30						Six Months Ended June 30
($000s, except where indicated)	2007			2006			2007			2006
Funds flow from operations		192,044			185,053			382,412			379,794
Total distributions declared		129,626			139,236			258,814			272,115
Distributions per unit ($)		0.57			0.69			1.14			1.38
Payout ratio (%)		67	%		75	%		68	%		72	%

For the six months ended June 30, 2007 our cash distributions of $238.8 million and net capital expenditure program of $202.2 million totalled approximately $441.0 million or approximately 115 percent of our funds flow of $382.4 million.  We fund our distributions and capital expenditure programs with funds 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 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.

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Our 2007 distributions to date are summarized as follows:

	Total		Distributions		Value of Units		Number of		DRIP Unit
($000s, except where indicated)	Distributions		Paid		Issued under DRIP		Units Issued		Price ($/unit)
Distributions declared:
June 2007		43,230		40,275		2,955		179,849		16.43
May 2007		43,223		39,818		3,405		209,490		16.25
April 2007		43,173		39,818		3,355		228,069		14.71
March 2007		43,118		39,802		3,316		231,858		14.30
February 2007		43,064		39,728		3,336		241,481		13.81
January 2007		43,006		39,358		3,648		261,555		13.95
Total		258,814		238,799		20,015

Canetic announced on January 15, 2007 that we would reduce the monthly distribution in order to increase the level of funds 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 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 three months ended June 30, 2007 we declared distributions of $129.6 million ($0.57 per unit) which represented 67 percent of funds flow from operations as compared to distributions of $139.5 million ($0.69 per unit) representing a 75 percent payout ratio in 2006.

For the six months ended June 30, 2007 our payout ratio was 68 percent as we generated $382.4 million of funds flow from operations and distributed $258.8 million.

CONTRACTUAL OBLIGATIONS

In addition to financial derivative commitments, the Trust has the following contractual obligations as at June 30, 2007:

(000s)	Total		2007		2008		2009		2010		2011		Thereafter
Bank debt		1,342,738		-		-		1,342,738		-		-		-
Convertible debentures(1)		260,251		1,309		5,622		8,029		17,821		227,470		-
Office lease		105,154		3,286		6,398		6,398		8,912		9,919		70,241
Pipeline contract		9,080		270		776		992		1,127		1,472		4,443
Total		1,717,223		4,865		12,796		1,358,157		27,860		238,861		74,684

⁽¹⁾ Gross of deferred transaction costs.

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 RRSPs, RRIFs, RESPs and DPSPs.  Each year, the Trust is required to file an income tax return and any taxable income of the Trust is allocated to unitholders.

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Unitholders are required to include in 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 unitholder’s ACB is reduced below zero, such amount will be deemed to be a capital gain to the unitholder and the unitholder’s 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 were taxable as other income.

For 2007, Canetic estimates that 100 percent of cash distributions will be taxable and no portion of the distributions will be a tax-deferred return of capital.  Actual taxable amounts will vary depending upon production volumes, commodity prices and other factors.

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.  For U.S. tax purposes, 100 percent of these distributions were taxable as “Qualified Dividends”.

For 2007, Canetic estimates that 100 percent of cash distributions paid during the year will be taxable as “Qualified Dividends” and no portion of the distributions will be a tax-deferred return of capital.  Actual taxable amounts may vary and is dependant upon the Trust’s current and accumulated earnings and profits as determined under U.S. tax laws.

BUSINESS RISKS

The operations of Canetic are subject to underlying risks associated with the business and structure of the Trust.  Certain of these risks are summarized in the “Forward-Looking Statements” section of the MD&A.  For a detailed discussion of business risks, please refer to “Risk Factors” in the Trust’s most recently filed Annual Information Form.

CHANGES IN ACCOUNTING POLICIES

Effective January 1, 2007, the Trust adopted the Canadian Institute of Chartered Accountants (“CICA”) Handbook Section 1530 “Comprehensive Income”, Section 3251 “Equity”, Section 3855 “Financial Instruments - Recognition and Measurement”, Section 3861 “Financial Instruments - Disclosure and Presentation”, and Section 3865 “Hedges”.  As required by the new standards prior periods have not been restated.  The adoption of these standards has had no material impact on the Trust’s net earnings or cash flows from operating activities.  The effects of the implementation of the new standards are discussed below.

Comprehensive Income

The Trust does not have any items to be accounted as components of other comprehensive income (“OCI”) and as a result comprehensive income equals net (loss) earnings.

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Financial Instruments

The financial instruments standard establishes the recognition and measurement criteria for financial assets, financial liabilities and derivatives.  All financial instruments are required to be measured at fair value on initial recognition of the instrument, except for certain related party transactions.  Measurement in subsequent periods depends on whether the financial instrument has been classified as “held-for-trading”, “available-for-sale”, “held-to-maturity”, “loans and receivables”, or “other financial liabilities” as defined by the standard.

Financial assets and financial liabilities “held-for-trading” are measured at fair value with changes in those fair values recognized in net earnings.  Financial assets “available-for-sale” are measured at fair value, with changes in those fair values recognized in OCI.  Financial assets “held-to-maturity”, “loans and receivables”, and “other financial liabilities” are measured at amortized cost using the effective interest method of amortization.  All derivative instruments, including embedded derivatives, are recorded in the balance sheet at fair value unless they qualify for the expected purchase, sale, or usage exemption.  All changes in fair value are recorded in earnings unless hedge accounting is applied, in which case changes in fair value related to the effective portion of cash flow hedges is recognized in OCI.

As a result of the adoption of these new standards, the Trust has classified its accounts receivable as “loans-and-receivables”.  Deposits have been classified as “held-to-maturity”.  Accounts payable and accrued liabilities, distributions payable, bank debt, and convertible debentures have been classified as “other financial liabilities”.  Changes in fair values of derivatives and embedded derivatives are recognized in earnings as the Trust has maintained its policy not to use hedge accounting.

Transaction costs are netted against the carrying value of the asset or liability to which it relates and then amortized over the expected life of the instrument using the effective interest method.  On adoption of Section 3855 “Financial Instruments - Recognition and Measurement”, the Trust netted its remaining deferred financing charges against convertible debentures.

The Trust also adopted Section 1506 “Accounting Changes”, the only impact of which is to provide disclosure of when an entity has not applied a new source of GAAP that has been issued but is not yet effective.  This is the case with Section 3862 “Financial Instruments Disclosures”, Section 3863 “Financial Instruments Presentations”, and section 1535 “Capital Disclosures” which are required to be adopted for fiscal years beginning on or after October 1, 2007.  The Trust will adopt these standards on January 1, 2008 and it is expected the only effect on the Trust for adopting Sections 3862 and 3863 will be incremental disclosures regarding the significance of financial instruments for the entity's financial position and performance; and the nature, extent and management of risks arising from financial instruments to which the entity is exposed.  The effect on the Trust for adopting Section 1535 will be increased disclosure surrounding our objectives, policies and processes for managing capital.

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 that 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 the controls and procedures to 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.

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INTERNAL CONTROLS OVER FINANCIAL REPORTING

Management is responsible for establishing and maintaining internal control over financial reporting to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. There have been no changes in internal control over financial reporting during the quarter ended June 30, 2007 that have materially affected, or are reasonably likely to materially effect, the Trust’s internal control over financial reporting.

OUTLOOK

As we look forward to the second half of 2007, Canetic will continue to focus on the exploitation and development of our significant asset base.  Drilling activity has resumed during the third quarter 2007 and we plan for the drilling of approximately 30 - 40 operated wells over the remainder of the year, depending on well type and depth.  The diversity of our asset base will allow us to focus our operated program on crude oil related opportunities and defer certain natural gas projects while we await a recovery in natural gas prices.  Production efficiencies associated with our capital program remain strong relative to industry averages in the Western Canadian Sedimentary Basin and additional drilling and optimization opportunities have been identified.

Our robust inventory of opportunities has led us to further increase planned capital expenditures to an estimated $400 million by year end.  This is a further $25 million dollar increase above the increase announced following the end of the first quarter resulting in a total increase year-to-date of $50 million over our original budget of $350 million announced in December of 2006. Despite the additional capital expenditures, we expect our total well count to be lower in 2007 than 2006, reflecting the deeper and more prolific wells that we have been drilling as of late.

Although Canetic continues to experience increasing operating costs on a unit-of-production basis, we maintain our commitment to managing operational efficiencies and optimizing field netbacks in all areas where we do business.  Due to continued cost pressures, particularly in the areas of labour, fuel, power, processing fees and property taxes, we are increasing our previous estimate for full year operating costs to $10.00 - $11.00 per boe.  As we experience higher field costs throughout our asset base, considerable effort is being made to optimize operational efficiencies and minimize operating costs on a unit-of-production basis, including the divestiture of assets that have a higher cost base.

Despite the temporary decline in production volumes experienced during the second quarter of 2007 and the disposition of approximately 1,000 boe per day of production associated with the Northeast Alberta Asset Sale, which was not accounted for in our previous production guidance, we believe the strength of our development program will enable us to maintain our previous production guidance of 76,500 to 80,000 boe per day for the full year 2007.  Given expected commodity prices, this production target is anticipated to result in a payout ratio of 65 to 70 percent of funds flow from operations at current distribution levels of $0.19 per unit per month.  The balance of funds flow from operations will be utilized to fund a majority of our 2007 capital expenditure program.

We remain excited about the future prospects of Canetic. Our continuing strategy has always been to build a significant asset base and a team of people that could generate long-term value for our unitholders. We believe that we have created an entity that is well positioned for the long-term, with significant asset depth and diversity, extensive development opportunities and a quality team of people to exploit those opportunities.  Our current focus is to exploit our assets and extract the inherent value for our unitholders, and find new and innovative ways to bring incremental value and opportunity to our portfolio and position the Trust to excel in today’s continually changing environment.

In addition, given the implementation of the new SIFT Rules, we will continue to review alternative business strategies and structures to ensure we are well positioned for 2011.  This includes the evaluation of unconventional oil and natural gas opportunities, U.S. and international acquisition opportunities, and further consolidation opportunities in the oil and gas trust sector, which we expect to materialize over the next couple of years.

We look forward to reporting our progress.

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CORPORATE INFORMATION

OFFICERS AND SENIOR MANAGEMENT   J. Paul Charron, CA President and Chief Executive Officer   David J. Broshko, B.Comm., CA Vice President, Finance and Chief Financial Officer   Richard J. Tiede, P.Eng Chief Operating Officer   Mark P. Fitzgerald, MBA, P.Eng Vice President, Operations   Brian K. Keller, B.Sc. Vice President, Exploitation   Brian D. Evans, LLB Vice President, General Counsel and Secretary   David M. Sterna, B.A. Economics Vice President, Corporate Planning and Marketing   Donald W. Robson, Vice President, Land   Keith S. Rockley, B.A. Vice President, Human Resources & Corporate Administration   DIRECTORS   Jack C. Lee, BA, B.Comm. ICD.D Calgary, Alberta Chairman   Robert G. Brawn, P.Eng, Calgary, Alberta Chairman, Emeritus and Director   J. Paul Charron, CA, Calgary, Alberta President, Chief Executive Officer and Director   W. Peter Comber, MBA, CA, Toronto, Ontario   Murray M. Frame, Calgary, Alberta   Daryl Gilbert, P.Eng, Calgary, Alberta   Nancy M. Laird, MBA, Calgary, Alberta   R. Gregory Rich, MBA, B.SC. (Eng.), Houston, Texas   AUDITORS   Deloitte & Touche LLP Calgary, Alberta INVESTOR RELATIONS   Telephone: (403) 539-6300 Investor Toll Free: 1-877-539-6300 E-mail: info@canetictrust.com   BANKERS   Bank of Montreal The Toronto Dominion Bank Canadian Imperial Bank of Commerce The Bank of Nova Scotia Royal Bank of Canada BNP Paribas (Canada) Alberta Treasury Branches National Bank of Canada Union Bank of California, NA Deutsche Bank AG HSBC Bank Canada Société Générale (Canada) Canadian Western Bank JP Morgan Chase Bank, NA Fortis Capital (Canada) Ltd.   PETROLEUM CONSULTANTS   GLJ Petroleum Consultants Ltd., Calgary, Alberta   Sproule Associates Ltd., Calgary, Alberta   LEGAL COUNSEL   Burnet, Duckworth & Palmer LLP Calgary, Alberta   Dorsey & Whitney LLP, New York, NY; Vancouver, BC   REGISTRAR AND TRANSFER AGENT   Computershare Trust Company of Canada Calgary, Alberta   Computershare Trust Company, Inc. Golden, Colorado   STOCK EXCHANGE LISTING   Toronto Stock Exchange: CNE.UN New York Stock Exchange: CNE   Debentures: 9.4% CNE.DB.A; 6.5% CNE.DB.B; 8.0% CNE.DB.C; 11.0% CNE.DB.D; 6.5% CNE.DB.E

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