ex991.htm

MATERIAL CHANGE REPORT

1.	Name and Address of Reporting Issuer:

Penn West Energy Trust ("Penn West")

Suite 2200, 425-1st Street S.W.

Calgary, Alberta T2P 3L8

2.	Date of Material Change:

January 11, 2008

3.	News Release:

A press release was issued by Penn West on January 11, 2008 and disseminated through the facilities of Canada Newswire and would have been received by the securities commissions where Penn West is a reporting issuer in the normal course of its dissemination.

4. Summary of Material Change:

On January 11, 2008 Penn West and Canetic Resources Trust ("Canetic") completed a plan of arrangement (the "Arrangement") resulting in Penn West's acquisition of Canetic. At a special meeting of holders of trust units of Canetic ("Canetic Unitholders") held in Calgary, Alberta on January 9, 2008, 92.1 percent of the votes cast were in favour of the Arrangement.

5.	Full Description of Material Change:

5.1 Full Description of Material Change:

The Arrangement

On January 11, 2008 Penn West and Canetic completed the Arrangement resulting in Penn West's acquisition of Canetic. At a special meeting of Canetic Unitholders held in Calgary, Alberta on January 9, 2008, 92.1 percent of the votes cast were in favour of the Arrangement.

Under the Arrangement, Canetic Unitholders received 0.515 of a Penn West trust unit for each Canetic trust unit exchanged. The first distribution that former Canetic Unitholders will be eligible to receive from Penn West will be the distribution payable on or about February 15, 2008 to Penn West unitholders of record on January 31, 2008. Canetic Unitholders of record at the close of business on January 10, 2008 also received a special one-time distribution of CDN $0.09 per Canetic trust unit. The special distribution, together with the distributions payable on the Penn West trust units (assuming no changes to the distribution policies of Penn West in effect on January 11, 2008), will effectively maintain the equivalent of Canetic's pre-Arrangement monthly cash distributions to Canetic Unitholders for six months following completion of the Arrangement, taking into account the trust unit exchange ratio and the pre-Arrangement monthly distribution levels of Penn West and Canetic. The special distribution was paid on or about January 17, 2008.

As a result of the Arrangement, the Canetic trust units were de-listed from the Toronto Stock Exchange ("TSX") and the New York Stock Exchange ("NYSE"). Trust units of Penn West continue to trade on the TSX under the symbol "PWT.UN" and on the NYSE under the symbol "PWE".

Furthermore, under the Arrangement Penn West assumed all of the covenants and obligations of Canetic in respect of the four separate classes of outstanding Canetic convertible debentures ("Canetic Debentures"). Holders of Canetic Debentures are entitled to receive 0.515 of a Penn West trust unit in lieu of each Canetic trust unit that the holder was previously entitled to receive on conversion. The revised conversion prices for the Canetic Debentures are as follows: (i) Canetic 6.5 percent debentures issued May 26, 2005 - $36.8155 per Penn West trust unit (27.1625 Penn West trust units per $1,000 principal amount); (ii) Canetic 6.5 percent debentures issued August 24, 2006 - $51.5534 per Penn West trust unit (19.3974 Penn West trust units per $1,000 principal amount); (iii) Canetic 8.0 percent debentures issued June 15, 2004 - $30.2136 per Penn West trust unit (33.0977 Penn West trust units per $1,000 principal amount); and (iv) Canetic 9.4 percent debentures issued July 3, 2003 - $31.1068 per Penn West trust unit (32.1473 Penn West trust units per $1,000 principal amount). The Canetic Debentures have been de-listed from the TSX and now trade as Penn West debentures on the TSX as PWT.DB.A in respect of the 9.4 percent July 2003 series, PWT.DB.B in respect of the 8.0 percent June 2004 series, PWT.DB.D in respect of the 6.5 percent May 2005 series and PWT.DB.F in respect of the 6.5 percent August 2006 series.

Board of Directors

Concurrent with the closing of the Arrangement, the Penn West board of directors was constituted with twelve directors, comprised of eight members of the existing Penn West board of directors (being John A. Brussa as Chair, William E. Andrew, James E. Allard, George H. Brookman, Shirley A. McClellan, Thomas E. Phillips, Frank Potter and James C. Smith) and four members of the Canetic board of directors (being Robert G. Brawn, Daryl Gilbert, Jack C. Lee as Vice-Chair, and R. Gregory Rich).

Senior Officers

Concurrent with the closing of the Arrangement, Penn West also reconstituted its management team. Penn West continues to be led by William E. Andrew as Chief Executive Officer, with J. Paul Charron (the former President and Chief Executive Officer of Canetic) as President and David W. Middleton (the former Executive Vice-President and Chief Operating Officer of Penn West) as Chief Operating Officer. The other senior officers of Penn West now include the following: Richard J. Tiede, Senior Vice-President, Business Development (the former Chief Operating Officer of Canetic); Thane A.E. Jensen, Senior Vice-President, Exploration and Development (who held this title prior to the Arrangement); Todd H. Takeyasu, Senior Vice-President, Finance - Treasury (the former senior Vice-President and Chief Financial Officer of Penn West); David J. Broshko, Senior Vice-President, Finance - Financial Reporting (the former Vice-President, Finance and Chief Financial Officer of Canetic); Mark P. Fitzgerald, Senior Vice-President, Engineering (the former Vice-President, Operations of Canetic); Eric J. Obreiter, Senior Vice-President, Production (the former Vice-President, Production of Penn West); Brian D. Evans, Senior Vice-President, General Counsel and Corporate Secretary (the former Vice-President, General Counsel and Secretary of Canetic); and Keith Luft, Senior Vice-President, Stakeholder Relations (the former Vice-President, Land and Legal of Penn West).

Description of Canetic's Oil and Gas Assets

A description of Canetic's principal properties and certain selected reserve data and other oil and gas information with respect to Canetic is contained in Schedule "A" to this Material Change Report. This information has been reproduced from pages 11 to 29 of Canetic's Annual Information Form dated March 23, 2007 (the "Canetic AIF"). Selected definitions, conventions, abbreviations and conversions relating to the information contained in Schedule "A" has been included in Schedule "B" attached hereto and has been reproduced from pages 68 to 76 of the Canetic AIF. Note that unless otherwise stated, information contained in Schedule "A" is as at December 31, 2006.

Capitalization

Immediately following the completion of the Arrangement, Penn West's capitalization consisted of the following: 372,578,576 trust units; $17,778,500 principal amount of 6.5% convertible debentures (due July 31, 2010); $229,649,000 principal amount of 6.5% convertible debentures (due December 31, 2011); $8,002,000 principal amount of 8.0% convertible debentures (due August 31, 2009); $5,578,000 principal amount of 9.4% convertible debentures (due July 31, 2008); $50 million principal amount of 7.2% convertible debentures (due May 31, 2011); $48,671,000 principal amount of 8.0% convertible debentures (due June 30, 2010); and $473 million principal amount of senior unsecured notes issued by Penn West Petroleum Ltd. In addition, concurrent with the closing of the Arrangement, Penn West secured a $4 billion credit facility with a three year term with a syndicate of 18 Canadian and international banks. The new credit facility was initially used to retire Penn West's indebtedness under its existing credit facilities and to retire all indebtedness assumed by Penn West in connection with the acquisition of Titan Exploration Ltd., Vault Energy Trust and Canetic.

The Combined Trust

The combination of Penn West and Canetic has created the largest conventional oil and gas energy trust in North America with an enterprise value of approximately $14 billion, a significant portfolio of unconventional opportunities and a dominant position in light oil in Canada. In addition, Penn West has a diversified portfolio of conventional oil and natural gas assets plus significant resource-play potential in the Peace River oil sands of Northern Alberta, CO2 enhanced oil recovery in the Pembina, Swan Hills, Midale and Weyburn light oil pools and coalbed methane producing assets. Penn West believes that it is well positioned to create long-term value for Penn West unitholders through its high-quality, long-life asset base, a strong balance sheet, and an extensive drilling inventory, together with improved access to equity and debt markets resulting from Penn West's increased size and strength.

5.2 Disclosure for Restructuring Transactions:

Not applicable.

6.	Reliance on subsection 7.1(2) or (3) of National Instrument 51-102:

Not Applicable.

7.	Omitted Information:

Not Applicable.

8.	Executive Officer:

Brian D. Evans, Senior Vice President, General Counsel and Corporate Secretary of Penn West Petroleum Ltd., the administrator of Penn West

Telephone: (403) 539-5908

Facsimile: (403) 539-5980

9.	Date of Report

January 21, 2008

Forward-looking Statements

Certain information regarding Penn West, including the attributes of Penn West following the closing of the Arrangement, the nature of the combined trust's assets and management's assessment of available development opportunities and its ability to create long-term value for unitholders therefrom may constitute forward-looking statements under applicable securities law and necessarily involve risks, including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition, failure to realize the anticipated benefits of the combination, ability to access sufficient capital from internal and external sources, failure to obtain required regulatory approvals, changes in legislation, including but not limited to tax laws and environmental regulations. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect Penn West's operations or financial results are included in reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), the SEC's website (www.sec.gov) or at Penn West's website (www.pennwest.com).

The forward-looking statements contained in this document speak only as of the date of this document. Except as expressly required by applicable securities laws, Penn West does not undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this document are expressly qualified by this cautionary statement.

SCHEDULE "A"

Oil and Gas Properties

The following is a description of Canetic's principal oil and natural gas properties. Unless otherwise specified, production estimates, gross and net acres and well count information are as at December 31, 2006. Reserve amounts are stated, before deduction of royalties as at December 31, 2006, based on escalating cost and price assumptions as evaluated in the Canetic Trust Engineering Report. The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties due to the effects of aggregation.

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

Williston Basin District

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

Greater Queensdale, Saskatchewan

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

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

Greater Midale, Saskatchewan

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

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

Heward/Handsworth, Saskatchewan

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

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

North Dakota and Montana, USA

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

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

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

Wyoming, USA - Powder River Basin Coalbed Methane ("CBM")

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

Southern District

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

Countess, Alberta

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

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

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

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

Alderson, Alberta

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

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

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

Sibbald/Acadia, Alberta

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

Border Plains District

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

Provost, Alberta

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

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

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

Furness, Saskatchewan

The greater Furness area is located in western Saskatchewan in Townships 48 and 49, Ranges 26 through 28 W3M. Furness was acquired late in 2003 pursuant to the acquisition of Exodus Energy Ltd. and is primarily a heavy oil field. The primary producing zone of interest is the Sparky Sand, with additional production provided from the McLaren and General Petroleum Formations.

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

South Central District

The South Central district includes properties located in central Alberta. In total 33 (19.4 net) wells were drilled on these properties during 2006, including 14 (8.2 net) oil, 16 (8.7 net) gas and 3 (2.5 net) dry and abandoned.

Acheson, Alberta

The Acheson area is west of Edmonton and includes interests in the Acheson D-3a Unit, the Acheson Lower Cretaceous Unit No. 1, the Acheson North D-2 Pool Unit and non-unit production. Canetic's overall working interest in the area is 99.7%.

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

Acheson is a multi-zone area with production coming from the Leduc, Nisku, Detrital, Basal Quartz and Viking zones. The Leduc Formation is characterized by the development of numerous isolated reef complexes and a broad carbonate shelf, all of which developed on the Cooking Lake platform and is responsible for the majority of Acheson’s current production. The D-3a Pool started blow down in June 2003 by the controlled production of reservoir and injected hydrocarbons following the termination of an enhanced recovery scheme to increase the recovery of original oil reserves.

Golden Spike, Alberta

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

Corbett Creek, Alberta

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

North Central District

The North Central district includes properties located in central Alberta. In total 2 (0.2 net) gas wells were drilled on these properties during 2006.

Mitsue, Alberta

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

The oil from the Mitsue Gilwood Sand Units Nos. 1 and 2 is collected at one of 37 satellites where the fluids are commingled and moved via three-phase group lines to one of three main batteries. The main batteries consist of separation, compression, treating, fresh water injection, water disposal and storage facilities. The treated oil is shipped to Edmonton for sale through the Rainbow Pipeline. The solution gas is collected at the main batteries, compressed and sent to the unit Mitsue Gas Plant located at 16-30-072-04W5M. The current average throughput of the plant is 7.0 MMcf/day of gas. The plant consists of sweetening, turbo expansion and refrigeration.

Rocky District

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

Willesden Green, Alberta

The Willesden Green area is located approximately 125 kilometers southwest of Edmonton. The properties include unit and non-unit interests, with the majority of the production operated and with high working interests. The unit interests consist of four producing oil units, with two large operated units and one wholly owned project area producing light oil (41° API) from the Cardium formation. Two other units (one operated) produce long life light crude oil and natural gas from the Viking formation. The properties have opportunities for infill drilling on 160 acres, opportunities to enhance water flood performance, and several stimulation candidates. The non-unit interests produce light gravity crude oil from the Cardium formation and Mannville groups, and natural gas from the Scollard, Belly River, Cardium, Ellerslie, Ostracod, Rock Creek and Nordegg formations. This is a multi-target area with shallow to moderate drill depths and a large concentrated land position with the majority of the lands operated. There are also deeper Mannville drilling targets defined by seismic data, as well as many prospects in the shallower Belly River, Edmonton, Paskapoo and Scollard formations. Canetic owns the facilities associated with the production, as well as a 21.7% interest in the Imperial Oil Ltd. Willesden Green natural gas plant. Canetic also owns a 20 MMcf/d gas processing facility, with pipeline infrastructure that allows Canetic to process the majority of our production in this area in our owned gas plant. This plant was constructed in late 2006 and early 2007, and was commissioned in February 2007.

Gilby/Medicine River, Alberta

The Gilby area is situated approximately 30 kilometers southeast of the Willesden Green properties, and produces light crude oil and sweet natural gas from a number of zones in this multi-target area. The property was acquired pursuant to the Gilby/Willesden Green Acquisition and consists of six units (three operated) and non-unit holdings producing from early Cretaceous and Jurassic sands. Opportunities exist for infill drilling and production optimization. The property includes a 24.8% working interest in the Gilby West natural gas plant, of which Canetic was elected operator, and working interests in a number of operated facilities.

Hoadley/Ferrybank, Alberta

The Hoadley - Ferrybank area is located 90 kilometers southwest of Edmonton. This property was purchased by Canetic in 2006 in the Samson Acquisition. Production is entirely natural gas and associated liquids primarily from the Hoadley Barrier Bar complex in the Glauconite formation at a depth ranging from 1550 to 1850 mTVD. Other producing horizons include the Edmonton Sand, the Ellerslie, and Colony. This property includes 204,000 net developed and undeveloped acreage with an average working interest of roughly 67%. 90% of the production is operated by Canetic. Canetic operates 37 compressors in the area and has ownership in 9 others. Gas is processed

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

Innisfail, Alberta

The Innisfail properties are located in central Alberta, south of Red Deer. Drilling activity at Innisfail targets shallow Edmonton and Belly River gas, deeper Pekisko gas, and Leduc oil. Natural gas is transported via Canetic's owned central gathering system 30 kms south to the Garrington Sour Gas Plant operated by Esprit Exploration Ltd. Leduc oil is gathered via pipeline to a central battery then shipped by pipeline to a third party facility for processing.

Drayton Valley District

The Drayton Valley district includes properties located in western Alberta. In total 26 (6.3 net) wells were drilled on these properties during 2006, including 12 (2.1 net) oil, 11 (4.0 net) gas, and 3 (0.2 net) service.

Brazeau/Bigoray, Alberta

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

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

Kaybob, Alberta

The Kaybob district covers a very large geographic area approximately 250 kilometers northwest of Edmonton.

Kaybob Gas - Kaybob South Beaverhill Lake Unit Nos. 2 and 3

The Kaybob natural gas production comes from the Kaybob South Beaverhill Lake Unit Nos. 2 and 3. The units are located south of the town of Fox Creek. BP Canada operates Unit No. 2 and Trilogy Energy operates Unit No. 3. AEI purchased, an 11% working interest in Unit No. 2 and a 25.6% working interest in Unit No. 3 in June of 2004 as part of the ChevronTexaco acquisition. Production is from the Swan Hills formation of the Middle Devonian Beaverhill Lake Group. The reservoir was a retrograde gas condensate reservoir, and as a result, all three units were initially produced on a gas recycle scheme to maintain the reservoir pressure above the hydrocarbon dew point. All three units are now on blow down.

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

Kaybob South Triassic Unit No. 2

Canetic owns a 23.3% working interest in the Kaybob South Triassic Unit No. 2, which is operated by Prime West Energy Inc. The Kaybob South Triassic Unit No. 2 produces 42° API oil and associated natural gas from the Triassic Montney Formation. The oil from Kaybob Triassic Unit No. 2 is processed at a central unit battery located at 03-24-062-20W5 operated by Prime West Energy Inc. The battery is equipped with solution gas recovery and compression. The solution gas is compressed and shipped to the Central Alberta Midstream operated Kaybob Amalgamated Gas Plant at 12-01-062-20W5 for processing.

Simonette, Alberta

The Simonette Beaverhill Lake A and B Pools are located approximately 150 kilometers southeast of Grande Prairie. Canetic owns a 35.5% working interest in the A Pool and a 26.3% working interest in B Pool. These pools produce from the Beaverhill Lake Group.

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

Peace River Arch District

The Peace River Arch district includes properties located in northwest Alberta and northeast British Columbia. In total 18 (8.7 net) wells were drilled on these properties during 2006, including 7 (1.5 net) oil and 11 (7.2 net) gas.

Pouce Coupe, Alberta

The Pouce Coupe properties are located approximately 80 kilometers northwest of Grande Prairie. Canetic operates the Pouce Coupe South Boundary 'B' Unit No. 2 with a 62.8% working interest. This high netback, light oil unit includes an oil battery and water injection facility, as well as amine, refrigeration and gas compression facilities. Production within the unit is obtained from the Boundary Lake member of the Charlie Lake formation. Canetic also holds a 20.793% working interest in the Pouce Coupe South Boundary B Unit operated by Enerplus Resources Corporation. Non-unit production consists of wells with interests ranging from a gross overriding royalty to a 78.75% working interest. Producing formations primarily include the Doig, Bluesky, Gething, Baldonnel, Halfway and Boundary Lake.

Red Rock, Alberta

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

Fort St. John, British Columbia

The Fort St. John properties are primarily located in the Fort St. John area in northeast British Columbia. The principal properties are within a 20 kilometer radius of Fort St. John. Canetic has an average working interest of 55%. Canetic also has 50% and 65% working interests, respectively, in two operated compressor stations and 38.44% and 27% working interests, respectively, in a further two non-operated compressor stations. In September of 2006, Canetic obtained additional production in this area through the Samson Acquisition. Working interests average 57% in this new acreage and Canetic operates 79% of its production. Major fields include Stoddart, Monias, Airport, and Wilder. Producing horizons include Halfway, Doig, and Belloy. Canetic obtained operatorship in 10 compressors through this transaction and has additional ownership in 7 more. All gas is processed through Duke Midstream.

Fireweed/Buick Creek, British Columbia

The Fireweed/Buick Creek properties are located approximately 75 kilometers north and northwest of Fort St. John in northeast British Columbia. Canetic obtained a large land position through the Samson Acquisition in September of 2006. Canetic has an average working interest of 57% in the new properties and operates 91% of its production. The majority of production comes from the Dunlevy Sand with minor production from the Doig, Halfway, Bluesky, and Baldonnel horizons. Canetic operates 9 compressors in the area and has additional ownership in 5 others. All gas is processed through Duke Midstream.

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

The effective date of the statement of reserves data and other oil and gas information set forth below (the "Statement") is December 31, 2006 and the preparation date of the Statement is February 28, 2007.

In this section "Canetic" means Canetic or one or more of the other Operating Entities.

Disclosure of Reserves Data

The reserves data of Canetic set forth below (the "ReservesData") is based upon evaluations by GLJ and Sproule with effective dates of December 31, 2006 contained in the Canetic Trust Engineering Report. The Reserves Data summarizes the crude oil, liquids and natural gas reserves of Canetic and the net present values of future net revenue for these reserves using constant prices and costs and forecast prices and costs. The Reserves Data conforms to the requirements of National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). Additional information not required by NI 51-101 has been presented to provide continuity and additional information that Canetic believes is important to the readers of this information.

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

It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the constant or forecast prices and costs or other assumptions will be attained and variances could be material.

Reserves Data (Forecast Prices and Costs)

The reserves information presented does not report the U.S. reserves separately. The U.S. properties have proved plus probable gross reserves of approximately 6,811 MBoe or 2.5% of total reserves with a before tax net present value discounted at 10% of approximately $43,419,000 or 1.0% of total value.

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

Summary of Oil and Gas Reserves and Net Present Values of Future Net Revenue as of December 31, 2006

Forecast Prices and Costs

	Reserves
	Light and Medium Oil				Heavy Oil				Natural Gas				Natural Gas Liquids				Boe
	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
Reserves Category	(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(MMcf)		(MMcf)		(Mbbls)		(Mbbls)		(MBoe)		(MBoe)

Proved
Developed Producing		68,038		61,180		15,331		14,171		369,117		296,374		11,101		8,027		155,990		132,773
Developed Non-Producing		2,932		2,573		1,542		1,363		29,289		23,619		936		676		10,292		8,548
Undeveloped		11,657		10,605		1,527		1,389		63,610		51,205		917		643		24,703		21,171
Total Proved		82,627		74,357		18,400		16,923		462,016		371,197		12,955		9,346		190,985		162,492
Probable		34,244		30,728		5,765		5,268		226,787		185,922		5,219		3,830		83,026		70,812

Total Proved Plus Probable		116,872		105,085		24,165		22,190		688,803		557,120		18,174		13,176		274,011		233,304

Royalty interest reserves for Proved Developed Producing, Total Proved, and Total Proved Plus Probable are 1,078 MBoe, 1,194 MBoe, and 1,631 MBoe respectively, which equate to Company Interest Reserves of 157,068 MBoe, 192,179 MBoe, and 275,642 MBoe respectively.

	Net Present Values of Future Net Revenue
	Before Income Taxes Discounted at (%/year)						After Income Taxes Discounted at (%/year)
Reserves Category		0 (M$)	5 (M$)	10 (M$)	15 (M$)	20 (M$)		0 (M$)	5 (M$)	10 (M$)	15 (M$)	20 (M$)

Proved
Developed Producing		4,662,073	3,515,069	2,892,706	2,493,224	2,210,722		4,662,073	3,515,069	2,892,706	2,493,224	2,210,722
Developed Non-Producing		285,053	212,000	170,885	143,402	123,449		285,053	212,000	170,885	143,402	123,449
Undeveloped		475,959	329,570	237,133	174,204	129,143		475,959	329,570	237,133	174,204	129,143
Total Proved		5,423,084	4,056,639	3,300,724	2,810,830	2,463,314		5,423,084	4,056,639	3,300,724	2,810,830	2,463,314
Probable		2,494,025	1,411,019	949,810	701,204	546,933		2,494,025	1,411,019	949,810	701,204	546,933

Total Proved Plus Probable		7,917,110	5,467,658	4,250,534	3,512,034	3,010,247		7,917,110	5,467,658	4,250,534	3,512,034	3,010,247

Total Future Net Revenue (Undiscounted) as of December 31, 2006

Forecast Prices and Costs

Reserves Category	Revenue (M$)		Royalties (M$)		Operating Costs (M$)		Development Costs (M$)		Well Abandonment Costs (M$)		Future Net Revenue Before Income Taxes (M$)		Income Taxes (M$)		Future Net Revenue After Income Taxes (M$)

Proved Reserves		10,946,040		1,734,382		3,172,124		411,314		205,135		5,423,085		0		5,423,085

Proved Plus Probable Reserves		16,081,467		2,548,000		4,753,706		620,716		241,937		7,917,108		0		7,917,108

Future Net Revenue by Production Group as of December 31, 2006

Forecast Prices and Costs

Reserves Category	Production Group	Future Net Revenue Before Income Taxes (discounted at 10%/year)
		(M$)
Proved Reserves	Light and Medium Crude Oil (including solution gas and other by-products)	1,876,792
	Heavy Oil (including solution gas and other by-products)	258,056
	Natural Gas (including CBM and by-products but excluding solution gas from oil wells)	1,163,698
	Other Company Revenue/Costs	2,178
	Total	3,300,724

Proved Plus Probable Reserves	Light and Medium Crude Oil (including solution gas and other by-products)	2,373,058
	Heavy Oil (including solution gas and other by-products)	315,299
	Natural Gas (including CBM and by-products but excluding solution gas from oil wells)	1,559,999
	Other Company Revenue/Costs	2,178
	Total	4,250,534

Reserves Data (Constant Prices and Costs)

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

Summary of Oil and Gas Reserves and Net Present Values of Future Net Revenue as of December 31, 2006

Constant Prices and Costs

	Reserves
	Light and Medium Oil				Heavy Oil				Natural Gas				Natural Gas Liquids				Boe
	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
Reserves Category	(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(MMcf)		(MMcf)		(Mbbls)		(Mbbls)		(MBoe)		(MBoe)

Proved
Developed Producing		69,497		62,552		15,503		14,333		364,835		293,202		11,149		8,055		156,955		133,807
Developed Non-Producing		2,836		2,481		1,575		1,397		28,791		23,213		921		663		10,131		8,410
Undeveloped		11,822		10,754		1,550		1,412		63,301		51,200		925		648		24,847		21,347
Total Proved		84,154		75,787		18,628		17,143		456,927		367,614		12,996		9,365		191,933		163,564
Probable		34,881		31,324		5,891		5,391		222,885		182,974		5,211		3,819		83,130		71,030

Total Proved Plus Probable		119,036		107,111		24,519		22,534		679,812		550,588		18,206		13,184		275,063		234,594

Royalty interest reserves for Proved Developed Producing, Total Proved, and Total Proved Plus Probable are 1,078 MBoe, 1,192 MBoe, and 1,634 MBoe respectively, which equate to Company Interest Reserves of 158,033 MBoe, 193,126 MBoe, and 276,697 MBoe respectively.

	Net Present Values of Future Net Revenue
	Before Income Taxes Discounted at (%/year)						After Income Taxes Discounted at (%/year)
Reserves Category		0 (M$)	5 (M$)	10 (M$)	15 (M$)	20 (M$)		0 (M$)	5 (M$)	10 (M$)	15 (M$)	20 (M$)

Proved
Developed Producing		4,244,546	3,226,467	2,653,161	2,279,373	2,013,531		4,244,546	3,226,467	2,653,161	2,279,373	2,013,531
Developed Non-Producing		250,679	190,227	153,731	128,771	110,518		250,679	190,227	153,731	128,771	110,518
Undeveloped		425,003	288,516	202,373	143,887	102,162		425,003	288,516	202,373	143,887	102,162
Total Proved		4,920,229	3,705,209	3,009,265	2,552,031	2,226,211		4,920,229	3,705,209	3,009,265	2,552,031	2,226,211
Probable		2,051,904	1,210,674	828,942	615,367	480,060		2,051,904	1,210,674	828,942	615,367	480,060

Total Proved Plus Probable		6,972,133	4,915,884	3,838,207	3,167,398	2,706,271		6,972,133	4,915,884	3,838,207	3,167,398	2,706,271

Total Future Net Revenue (Undiscounted) as of December 31, 2006

Constant Prices and Costs

Reserves Category	Revenue (M$)		Royalties (M$)		Operating Costs (M$)		Development Costs (M$)		Well Abandonment Costs (M$)		Future Net Revenue Before Income Taxes (M$)		Income Taxes (M$)		Future Net Revenue After Income Taxes (M$)

Proved Reserves		9,581,387		1,476,979		2,637,703		398,264		148,214		4,920,227		0		4,920,227

Proved Plus Probable Reserves		13,559,853		2,106,517		3,724,891		598,657		157,655		6,972,133		0		6,972,133

Future Net Revenue by Production Group as of December 31, 2006

Constant Prices and Costs

Reserves Category	Production Group	Future Net Revenue Before Income Taxes (discounted at 10%/year) (M$)

Proved Reserves	Light and Medium Crude Oil (including solution gas and other by-products)	1,880,108
	Heavy Oil (including solution gas and other by-products)	254,111
	Natural Gas (including CBM and by-products but excluding solution gas from oil wells)	872,838
	Other Company Revenue/Costs	2,210
	Total	3,009,267

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

Pricing Assumptions

The following tables set forth the pricing assumptions used in preparing the Reserves data, which was an average of the GLJ and Sproule December 31, 2006 reference prices and, in the case of forecast prices and costs, the inflation rate assumptions.

Summary of Pricing Assumptions as of December 31, 2006

Constant Prices and Costs

	December 31, 2006
Inflation Rate Percent		00.00

Crude Oil $Cdn/Bbl
Light Sweet Crude @ Edmonton		67.59
Heavy @ Hardisty		39.35
Medium @ Cromer		60.96

WTI @ Cushing, Oklahoma ($US/Bbl)		60.95

NGLs $Cdn/Bbl at Edmonton
Propane		42.66
Butane		54.03
Condensate		71.53

Natural Gas $Cdn/MMBTU
AECO Spot		6.10
Alberta Spot Plant-gate		5.59
Alberta Government Reference Plant-gate		5.57
Alberta Aggregator Plant-gate		5.33
Saskatchewan Spot Plant-gate		5.97
B.C. Spot Plant-gate		6.05
B.C. Westcoast Stn2.		6.24

Exchange Rate $US/$Cdn		0.858

Summary of Pricing and Inflation Rate Assumptions as of December 31, 2006

Forecast Prices and Costs

	Oil
Year	WTI Cushing Oklahoma		Edmonton Par Price 40° API		Hardisty Heavy 12° API		Cromer Medium 29° API		Natural Gas AECO Gas Price		Edmonton Propane		Edmonton Butane		Edmonton Pentanes		Inflation Rates		Exchange Rate
	($US/Bbl)		($Cdn/Bbl)		($Cdn/Bbl)		($Cdn/Bbl)		($Cdn/mmbtu)		($Cdn/Bbl)		($Cdn/Bbl)		($Cdn/Bbl)		%/Year		($US/$Cdn)

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

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

Reconciliations of Changes in Reserves and Future Net Revenue

The following table sets forth the reconciliation of Canetic's net reserves for the year ended December 31, 2006 using an average of the GLJ and Sproule forecast price and cost estimates, reconciled to Canetic's net reserves at December 31, 2005.

Reconciliation of Company Net Reserves by Principal product Type

Forecast Prices and Costs

	Light and Medium Oil									Heavy Oil
Factors	Net Proved (MBbl)			Net Probable (MBbl)			Net Proved Plus Probable (MBbl)			Net Proved (MBbl)			Net Probable (MBbl)			Net Proved Plus Probable (MBbl)

December 31, 2005		73,486			29,754			103,240			18,059			5,931			23,990

Acquisitions		891			475			1,365			-			-			-
Dispositions		-			-			-			-			-			-
Discoveries		311			63			374			-			-			-
Extensions		1,347			299			1,646			308			332			640
Infill Drilling		2,362			782			3,144			704			(232	)		472
Improved Recovery		-			1,676			1,676			2,318			(1,450	)		869
Economic Factors		110			45			155			27			9			36
Technical Revisions		5,863			(2,366	)		3,496			(2,189	)		679			(1,512	)
Production		(10,012	)		-			(10,012	)		(2,305	)		-			(2,305	)

December 31, 2006		74,357			30,728			105,085			16,923			5,268			22,190

	Gas									NGL									Total
Factors	Net Proved (MMcf)			Net Probable (MMcf)			Net Proved Plus Probable (MMcf)			Net Proved (MBbl)			Net Probable (MBbl)			Net Proved Plus Probable (MBbl)			Net Proved (MBoe)			Net Probable (MBoe)			Net Proved Plus Probable (MBoe)

December 31, 2005		279,004			108,717			387,721			7,418			2,684			10,102			145,464			56,489			201,952

Acquisitions		107,287			68,735			176,022			1,897			1,144			3,041			20,669			13,075			33,743
Dispositions		(851	)		(160	)		(1,011	)		(93	)		(17	)		(110	)		(235	)		(44	)		(279	)
Discoveries		871			149			1,020			53			8			61			510			95			605
Extensions		17,799			9,105			26,904			799			222			1,021			5,420			2,371			7,791
Infill Drilling		5,350			1,378			6,728			50			44			94			4,008			824			4,832
Improved Recovery		5,466			918			6,384			185			37			221			3,414			416			3,830
Economic Factors		419			163			582			11			4			15			218			85			303
Technical Revisions		9,886			(3,083	)		6,805			561			(295	)		266			5,883			(2,498	)		3,385
Production		(54,034	)		-			(54,034	)		(1,536	)		-			(1,536	)		(22,859	)		-			(22,859	)

December 31, 2005		371,197			185,922			557,120			9,346			3,830			13,176			162,492			70,812			233,304

The following table sets forth the reconciliation of Canetic's net present value of future net revenue for the year ended December 31, 2006 using an average of the GLJ and Sproule constant price and cost estimates.

Reconciliation of Changes in Net Present Values of Future Net Revenue

Discounted at 10% Per Year

Proved Reserves

Constant Prices and Costs

Period and Factor	(M$)

Estimated Future Net Revenue at Beginning of Year (December 31, 2005)	3,391,031

Sales and Transfers of Oil and Gas Produced, Net of Production Costs and Royalties	(923,545	)
Net Change in Prices, Production Costs and Royalties Related to Future Production	(442,994	)
Changes in Previously Estimated Development Costs Incurred During the Period	-
Changes in Estimated Future Development Costs	(20,535	)
Extensions, Infill Drilling and Improved Recovery	236,271
Discoveries	9,380
Acquisitions of Reserves	325,475
Dispositions of Reserves	(17,167	)
Net Change Resulting from Revisions in Quantity Estimates	112,246
Accretion of Discount	339,103
Net Change in Income Taxes	-

Estimated Future Net Revenue at End of Year	3,009,265

Additional Information Relating to Reserves Data

Undeveloped Reserves

The following tables set forth the gross Proved Undeveloped Reserves and the Probable Undeveloped Reserves, each by-product type, attributed to the Canetic Assets for the periods indicated, based on forecast prices.

	Gross Proved Undeveloped								Gross Probable Undeveloped
Year	Light / Medium Crude Oil (Mbbls)		Heavy Oil (Mbbls)		Natural Gas (MMcf)		NGL (MBbls)		Light / Medium Crude Oil (Mbbls)		Heavy Oil (Mbbls)		Natural Gas (MMcf)		NGL (Mbbls)

2006		11,675		1,527		63,610		917		11,362		1,434		82,191		1,376

Canetic invests capital into development work, which moves it’s Proved Undeveloped Reserves and Probable Reserves into the Proved Developed Producing category of Reserves. In 2006, $351 million was spent on capital development and approximately $350 million has been budgeted for development capital in 2007 with respect to the Canetic Assets. A portion of the development capital is intended to be used to convert Proved Undeveloped Reserves and Probable Reserves into Proved Developed Producing Reserves. Allocating capital to properties and timing of development is based on economics and performance of the respective properties. Canetic's focus for 2007 development will be in the areas of Pouce Coupe in the Northern district and Willesden Green in the Western district, as well the Southern District, the Williston Basin and Central Alberta.

Canetic plans to continue pursuing development opportunities such as drilling, completions, and facilities upgrades in order to move Proved Undeveloped and Probable Reserves into Proved Developed Producing Reserves. In instances where land rights are expected to expire within one year, Canetic may engage in farm out arrangements which would eliminate the potential expiry and possibly result in some Proved Undeveloped and Probable Reserves becoming Proved Developed Producing Reserves.

Future Development Costs

The following table sets forth development costs deducted in the estimation of Canetic's future net revenue attributable to the reserve categories noted below.

	Forecast Prices and Costs (M$)						Constant Prices and Costs (M$)
Year	Proved Reserves			Proved Plus Probable Reserves			Proved Reserves
		0%	10%		0%	10%		0%	10%

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

The future development costs are capital expenditures required in the future for Canetic to convert Developed Non Producing Reserves and Undeveloped Reserves into Proved Developed Producing Reserves. Canetic anticipates using a combination of internally generated funds flow, debt and equity financing to fund these future development costs. Based on the commodity price and cost assumptions adopted for both the constant prices and costs case and the forecast prices and costs case, all the expenditures included in the future development costs are economic as they enhance the net present values of the Proved Developed Producing Reserves.

Other Oil and Gas Information

Oil and Gas Wells

The following table sets forth the number and status of wells in which Canetic had a working interest as at December 31, 2006.

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

Alberta		3,102		1,035		112		51		3,806		1,266		112		69
British Columbia		55		15		1		1		297		133		20		11
Saskatchewan		2,691		1,236		114		79		307		45		3		2
Manitoba		467		146		0		0		0		0		0		0
United States		21		9		0		0		156		48		29		21
Total		6,336		2,441		227		131		4,566		1,492		164		103

Notes:

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

(2)	Gross wells include unit wells.

Properties with no Attributed Reserves

The following table sets out the total land holding of Proved and Unproved properties held by Canetic as at December 31, 2006.

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

Alberta		1,666,860		762,821		1,050,353		584,843		2,717,213		1,347,665
British Columbia		233,024		101,675		262,088		148,144		495,112		249,819
Saskatchewan		263,398		149,210		273,895		145,798		537,293		295,008
Manitoba		36,510		13,143		7,943		2,627		44,453		15,770
Wyoming		9,652		3,821		26,785		14,962		36,436		18,783
Montana		1,520		937		2,275		811		3,796		1,748
North Dakota		7,506		3,731		31,148		24,851		38,654		28,582
Total		2,218,470		1,035,338		1,654,487		922,036		3,872,957		1,957,375

Management expects that rights to explore, develop and exploit 204,146 net acres of Canetic's undeveloped land holdings will expire within one year.

Forward Contracts

Canetic has an active price risk management program that undertakes to reduce risk exposure to budgeted annual funds flow projections resulting from uncertainty or changes in commodity prices. The reduction of price risk is designed to result in an enhanced degree of stability and certainty of distribution payments to Unitholders. Core to Canetic's risk management strategy is the choice of the appropriate type of financial product at the time of execution which will give the optimal level of protection against downward price movements while maintaining as much exposure as possible to potential price increases. The objective of Canetic's risk management team is to hedge up to 50% of Canetic's budgeted production for the current and following year in accordance with the guidelines established by the Board of Directors.

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

Additional Information Concerning Abandonment and Reclamation Costs

The following table sets forth well abandonment costs deducted in the estimation of Canetic's future net revenue attributable to the reserve categories noted below.

	Forecast Prices and Costs (M$)						Constant Prices and Costs (M$)
Year	Proved Reserves			Proved Plus Probable Reserves			Proved Reserves
		0%	10%		0%	10%		0%	10%

2007		3,826	3,648		2,663	2,539		5,356	5,107
2008		6,095	5,283		4,812	4,171		4,755	4,122
2009		8,355	6,584		5,770	4,547		6,278	4,947
2010		7,900	5,659		5,288	3,788		5,879	4,211
2011		7,373	4,802		4,675	3,044		7,358	4,792
Thereafter		171,578	41,189		218,730	39,018		118,584	32,426
Total		205,127	67,164		241,938	57,107		148,210	55,604

Facility abandonment and reclamation costs of $158.8 million ($51.1 million discounted at 10%) are not included in the estimate of future net revenue.

Tax Horizon

As a result of the structure of the Trust and the Operating Entities, substantially all of the taxable income that would otherwise arise in Canetic or any other affiliated entities will accrue in the Trust and will be allocated by the Trust to Unitholders. This is primarily accomplished through the payment and deduction of interest on debt or the payment of the Canetic NPI's to the Trust. Therefore, no significant amount of income tax is anticipated to be incurred or paid by Canetic. If the proposed changes to the taxation of income trusts are enacted, taxes could be exigible in the Trust as certain distributions would no longer be a deduction in the calculation of its taxable income. For more information on these proposals, see also "Risk Factors - October 31 Proposals".

Costs Incurred

The following table summarizes expenditures (net of incentives and net of certain proceeds and including capitalized general and administrative expenses) related to Canetic's activities with respect to the year ended December 31, 2006:

Capital Expenditures ($000s)	2006

Land		14,868
Geological and Geophysical		2,783
Drilling and Completion		215,593
Production Equipment and Facilities		118,044

Net Development Expenditures		351,288
Major Acquisitions
StarPoint		2,511,746
Samson		924,635
Producing Properties		23,869
Minor Property Acquisitions		32,416
Minor Property Dispositions		(17,167	)
Net capital expenditures		3,826,787

Exploration and Development Activities

The following table sets forth the gross and net exploratory and development wells in which Canetic participated during the year ended December 31, 2006:

	Exploratory Wells				Development Wells
	Gross		Net		Gross		Net

Oil		11		8.6		150		73.2
Natural Gas		23		9.8		182		75.9
Service		0		0.0		5		2.2
Dry		2		0.8		5		4.3
Total		36		19.2		342		155.2

Production Estimates

The following table sets out the volume of the Trust's company interest forecast pricing production estimated for 2007, which is reflected in the estimate of future net revenue disclosed in the tables contained under "Disclosure of Reserves Data".

	Light and Medium Oil		Heavy Oil		Natural Gas		Natural Gas Liquids		Boe
2007	(Bbls/d)		(Bbls/d)		(Mcf/d)		(Bbls/d)		(Boe/d)

Proved Producing		26,079		5,848		188,992		5,732		69,158
Total Proved		29,144		6,327		202,851		6,187		75,467
Proved plus probable		31,129		6,769		216,968		6,655		80,714

Production History

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

	Quarter Ended
	2006
	Dec 31		Sept 30		June 30		Mar 31
Average Daily Production
Light and Medium Crude Oil (Bbls/d)		31,874		32,759		31,969		32,028
Heavy Oil (Bbls/d)		4,839		5,555		5,379		5,597
Natural Gas (Mmcf/d)		221		181		166		176
NGL (Bbls/d)		6,689		5,925		5,043		5,763
Combined (Boe/d)		80,276		74,475		70,061		72,738

Average Price Received (before hedging)
Light and Medium Crude Oil ($/Bbl)		55.08		70.17		70.07		58.01
Heavy Oil ($/Bbl)		39.76		50.54		50.36		33.26
Natural Gas ($/Mcf)		6.90		6.21		5.97		8.94
NGL ($/Bbl)		45.44		50.60		48.90		46.86
Combined ($/Boe)		47.08		53.78		53.52		53.52

Royalties
Light and Medium Crude Oil ($/Bbl)		9.22		11.10		12.36		9.61
Heavy Oil ($/Bbl)		5.42		9.38		7.77		3.47
Natural Gas ($/Mcf)		1.43		0.94		1.29		2.03
NGL ($/Bbl)		8.52		15.60		12.92		10.58
Combined ($/Boe)		8.63		9.11		10.21		10.25

	Quarter Ended
	2006
	Dec 31		Sept 30		June 30		Mar 31

Operating Expenses
Light and Medium Crude Oil ($/Bbl)		12.46		11.12		9.82		9.74
Heavy Oil ($/Bbl)		13.60		15.97		12.23		10.09
Natural Gas ($/Mcf)		1.41		1.49		1.42		1.41
NGL ($/Bbl)		-		-		-		-
Combined ($/Boe)		9.67		9.72		8.80		8.49

Transportation
Light and Medium Crude Oil ($/Bbl)		0.27		0.24		0.22		0.21
Heavy Oil ($/Bbl)		0.29		0.23		0.21		0.19
Natural Gas ($/Mcf)		0.21		0.24		0.22		0.22
NGL ($/Bbl)		0.24		0.25		0.26		0.23
Combined ($/Boe)		0.71		0.73		0.67		0.66

Netback Received ($/Boe)
Light and Medium Crude Oil		33.13		47.71		47.67		38.45
Heavy Oil		20.46		24.95		30.16		19.51
Natural Gas		3.86		3.54		3.04		5.27
NGL		36.68		34.75		35.72		36.06
Combined		28.07		34.23		33.85		34.11

The following table indicates Canetic's average daily production from its important fields for the year ended December 31, 2006:

	Light and Medium Crude Oil		Heavy Oil		Gas		NGL		BOE
	(Bbl/d)		(Bbl/d)		(MMcf/d)		(Bbl/d)		(BOE/d)
Alberta
Acheson		870		0		13.1		1,195		4,252
Alderson / Alderson East		1,991		0		0.7		1		2,101
Bigoray		1,129		0		6.9		442		2,719
Brazeau		547		0		6.3		325		1,916
Countess		0		0		8.0		3		1,332
Duchess / Rosemary		1,208		0		2.3		10		1,600
Ferrybank		16		0		3.8		119		761
Gilby / Medicine River		356		0		8.8		273		2,096
Golden Spike		210		0		4.3		354		1,288
Homeglen / Rimbey		948		0		9.4		349		2,867
Innisfail / Innisfail East		495		0		4.5		222		1,466
Kaybob South		249		0		3.5		306		1,141
Leckie		2		0		4.9		0		822
Mitsue		1,249		0		1.5		187		1,684
Pouce Coupe		455		0		5.0		112		1,404
Provost		1,391		0		0.6		19		1,507
Red Rock		10		0		3.4		155		739
Simonette		732		0		1.2		112		1,043
Tatagwa		753		0		0.0		0		753
Willesden Green		1,393		0		8.2		354		3,109
Other Properties		4,364		763		58.1		1,027		15,835
Total Alberta		18,368		763		154.5		5,565		50,435

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

Saskatchewan
Cantal		2,566		0		3.1		0		3,077
Furness		0		2,336		0.6		0		2,444
Ingoldsby		867		0		0.2		0		895
Queensdale		1,815		0		1.0		0		1,976
Unwin		0		766		0.0		0		766
Other Properties		6,825		1,476		2.4		0		8,710
Total Saskatchewan		12,073		4,578		7.3		0		17,868

British Columbia
Buick/West Buick		48		0		4.4		84		858
Fireweed		11		0		1.5		14		271
Fort St John		86		0		9.2		52		1,673
Stoddart		64		0		1.9		24		409
Other Properties		0		0		4.7		119		908
Total British Columbia		209		0		21.7		293		4,119

Manitoba
Virden		665		0		0.4		0		738
Other Properties		537		0		0.0		0		531
Total Manitoba		1,202		0		0.4		0		1,269

United States
USA Prospect		306		0		2.4		0		713
Total United States		306		0		2.4		0		713

Total Canetic		32,158		5,341		186.3		5,858		74,404

Note:

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

SCHEDULE "B"

GLOSSARY OF TERMS

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

"000s" means thousands.

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

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

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

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

"Board" or "Board of Directors" means the board of directors of Canetic.

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

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

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

"Canetic Trust Engineering Report" means, collectively, the GLJ Report and the Sproule Report, with respect to the oil, natural gas liquids and natural gas interests held by the Trust and prepared by GLJ and Sproule effective December 31, 2006.

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

"Chevron Texaco Acquisition" means the acquisition of the Chevron Texaco Properties by AEI as more particularly described under the heading "Business and Properties - Acclaim Significant Transactions".

"Chevron Texaco Properties" means the interests in oil and natural gas reserves and associated facilities located in Alberta, British Columbia, Saskatchewan and Manitoba acquired by AEI pursuant to the Chevron Texaco Acquisition as more particularly described under the heading "Business and Properties - Acclaim Significant Transactions".

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

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

(a)

Canetic's prices and costs as at the effective date of the estimation, held constant throughout the estimated lives of the properties to which the estimate applies; and

(b)

if, and only to the extent that, there are fixed or presently determinable future prices or costs to which Canetic is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in paragraph (a).

"Development costs" means costs incurred to obtain access to reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas from reserves. More specifically, development costs, including applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(a)

gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines and power lines, pumping equipment and wellhead assemblies;

(b)

drill and equip development wells, development type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment and wellhead assemblies;

(c)

acquire, construct and install production facilities such as flow lines, separators, treaters, heaters, manifolds, measuring devices and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and

(d)

provide improved recovery systems.

"Developed Non-Producing Reserves" are those Reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of Production is unknown.

"Developed Producing Reserves" are those Reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of Production must be known with reasonable certainly.

"Developed Reserves" are those Reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the Reserves on Production.

"Development well" means a well drilled inside the established limits of an oil and gas reservoir, or in close proximity to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive.

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

"Exodus" means Exodus Energy Ltd., a predecessor corporation of Canetic, incorporated under the ABCA and acquired by Canetic on December 19, 2003 pursuant to the Exodus Acquisition.

"Exploration costs" means costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects that may contain oil and gas reserves, including costs of drilling exploratory wells and exploratory type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property and after acquiring the property. Exploration costs, which include applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(a)

costs of topographical, geochemical, geological and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews and others conducting those studies;

(b)

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

(c)

dry hole contributions and bottom hole contributions;

(d)

costs of drilling and equipping exploratory wells; and

(e)

costs of drilling exploratory type stratigraphic test wells.

"Exploratorywell" means a well that is not a Development well, a Service well or a Stratigraphic Test Well.

"Forecast Prices and Costs" means future prices and costs that are:

(a)

generally acceptable as being a reasonable outlook of the future; and

(b)

if and only to the extent that, there are fixed or presently determinable future prices or costs to which Canetic is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in paragraph (a).

"Gilby/Willesden Green Acquisition" means the acquisition of the Gilby/Willesden Green Properties by Canetic as more particularly described under the heading "Business and Properties - Acclaim Significant Transactions".

"Gilby/Willesden Green Properties" means the interests in oil and natural gas reserves and associated facilities located in the Gilby West and Willesden Green areas of west central Alberta acquired by Canetic pursuant to the Gilby/Willesden Green Acquisition as more particularly described under the heading "Business and Properties - Acclaim Significant Transactions".

"GLJ" means GLJ Petroleum Consultants Ltd.

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

"Gross" means:

(a)

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

(b)

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

(c)

in relation to properties, the total area of properties in which Canetic has an interest.

"Hoadley and B.C. Properties" means the interests in oil and natural gas reserves and associated facilities located in Alberta and British Columbia acquired by Canetic pursuant to the Samson Acquisition as more particularly described under the heading "Business and Properties - Canetic Significant Transactions".

"net" means:

(a)

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

(b)

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

(c)

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

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

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

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

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

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

"Proved Reserves" are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated Proved Reserves. It is believed that there is at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated Proven Reserves.

"Reserves" are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on:

(a)

analysis of drilling, geological, geophysical and engineering data;

(b)

the use of established technology; and

(c)

specified economic conditions which are generally accepted as being reasonable and shall be disclosed.

"Samson Acquisition" means the acquisition of the Hoadley and B.C. Properties by Canetic as more particularly described under the heading "Business and Properties - Canetic Significant Transactions".

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

"Service well" means a well drilled or completed for the purpose of supporting production in an existing field. Wells in this class are drilled for the following specific purposes: gas injection (natural gas, propane, butane or flue gas), water injection, steam injection, air injection, salt water disposal, water supply for injection, observation or injection for combustion.

"Sproule" means Sproule Associates Limited.

"Sproule Report" means the reports of Sproule dated February 22, 2007 and February 23, 2007 and effective December 31, 2006, evaluating the crude oil and natural gas reserves and future net production revenues attributable to certain properties of Canetic.

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

"Stratigraphic Test Well" means a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Ordinarily, such wells are drilled without the intention of being completed for hydrocarbon production. They include wells for the purpose of core tests and all types of expendable holes related to hydrocarbon exploration.

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

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

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

"Undeveloped Reserves" are those Reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of Production. They must fully meet the requirements of the reserves classification (Proved, Probable or Possible) to which they are assigned.

"Unit" means a trust unit of the Trust.

"Unitholder" means a holder of Units.

CONVENTIONS

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

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

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

ABBREVIATIONS

Oil and Natural Gas Liquids		Natural Gas

Bbl	barrel	Mcf	thousand cubic feet
Bbls	barrels	MMcf	million cubic feet
MBbls	thousand barrels	Mcf/d	thousand cubic feet per day
MMBbls	million barrels	MMcf/d	million cubic feet per day
Bbls/d	barrels per day	mmbtu	million British thermal units
BOPD	barrels of oil per day	Bcf	billion cubic feet
NGL	natural gas liquids	GJ	gigajoule

Other

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

API	American Petroleum Institute

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

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

Boe/d

barrel of oil equivalent per day

C$	Canadian dollars

m3	cubic metres

M$	thousands of dollars

MBoe	thousand barrels of oil equivalent

mTVD	metres true vertical depth

MMBoe

million barrels of oil equivalent

million

US$	United States dollars

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

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

CONVERSIONS

To Convert From	To	Multiply By
Mcf	Cubic metres	28.174
Cubic metres	Cubic feet	35.494
Bbls	Cubic metres	0.159
Cubic metres	Bbls oil	6.290
Feet	Metres	0.305
Metres	Feet	3.281
Miles	Kilometres	1.609
Kilometres	Miles	0.621
Acres	Hectares	0.405
Hectares	Acres	2.471
gigajoule	MMBTU	0.948213
MMBTU	gigajoule	1.054615