U.S. SECURITIES AND EXCHANGE COMMISSION

FORM 40-F

(Check One)

o Registration statement pursuant to Section 12 of the Securities Exchange Act of 1934

or

þ Annual report pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2004

Commission file number 1-15226

ENCANA CORPORATION

1800-855 2nd Street, S.W., P.O. Box 2850, Calgary, Alberta, Canada T2P 2S5
(403) 645-2000
(Address and Telephone Number of Registrant’s Principal Executive Offices)

CT Corporation System, 111 8^th Avenue, New York, NY 10011
(212) 894-8940
(Name, Address (Including Zip Code) and Telephone Number
(Including Area Code) of Agent For Service in the United States)

Securities registered or to be registered pursuant to Section 12(b) of the Act.

Securities registered or to be registered pursuant to Section 12(g) of the Act. None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act. Debt Securities

For annual reports, indicate by check mark the information filed with this Form:

     Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report: 449,997,384

     Indicate by check mark whether the registrant by filing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934 (the “Exchange Act”). If “Yes” is marked, indicate the file number assigned to the registrant in connection with such rule.

Yes o No þ

     Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the registrant was required to file such reports); and (2) has been subject to such filing requirements for the past 90 days.

Yes þ No o

The Annual Report on Form 40-F shall be incorporated by reference into or as an exhibit to, as applicable, each of the registrant’s Registration Statements under the Securities Act of 1933: Form S-8 (File Nos. 333-13956 and 333-85598) and Form F-9 (File Nos. 333-113732 and 333-118737).

 

FORM 40-F

Principal Documents

The following documents have been filed as part of this Annual Report on Form 40-F, beginning on the following page:

40-F1

ANNUAL INFORMATION FORM

February 25, 2005

TABLE OF CONTENTS

INTRODUCTORY INFORMATION

      EnCana Corporation (“EnCana” or the “Corporation”) was formed through the business combination (the “Merger”), on April 5, 2002, of Alberta Energy Company Ltd. (“AEC”) and PanCanadian Energy Corporation (“PanCanadian”). The Merger was accomplished through an arrangement in respect of AEC under the Business Corporations Act (Alberta) and certain corporate changes for PanCanadian. Pursuant to the Merger, PanCanadian indirectly acquired all of the outstanding common shares of AEC in consideration for common shares issued by PanCanadian. PanCanadian’s name was also changed to EnCana Corporation and its board of directors and senior management were reconstituted. Following completion of the Merger, AEC remained in existence, as an indirect wholly owned subsidiary of EnCana. On January 1, 2003, AEC and another subsidiary were amalgamated with EnCana. As a result of these transactions, the former PanCanadian and the former AEC continue as one corporation known as EnCana Corporation.

      In this annual information form, unless otherwise specified or the context otherwise requires, reference to “EnCana” or to the “Corporation” includes reference to subsidiaries of and partnership interests held by EnCana Corporation and its subsidiaries. Any reference to “EnCana” or the “Corporation” for periods prior to the Merger are to EnCana’s founding companies, PanCanadian and AEC, and their subsidiaries and partnership interests.

      Unless otherwise indicated, all financial information included in this annual information form is determined using Canadian generally accepted accounting principles (“Canadian GAAP”), which differs from generally accepted accounting principles in the United States (“U.S. GAAP”). The notes to EnCana’s audited consolidated financial statements contain a discussion of the principal differences between EnCana’s financial results calculated under Canadian GAAP and under U.S. GAAP.

      In accordance with Canadian GAAP, the consolidated financial statements of EnCana include the results of PanCanadian prior to the Merger and do not include any results related to AEC’s operations prior to the Merger. Accordingly, unless otherwise indicated, all financial information contained in this annual information form for the first quarter of 2002 does not reflect the results of AEC for that period. Unless otherwise indicated, other statistical information and operational results are presented on the same basis.

      Unless otherwise specified, all dollar amounts are expressed in United States dollars and all references to “dollars” or “$” are to United States dollars and all references to “C$” are to Canadian dollars.

NOTE REGARDING FORWARD-LOOKING STATEMENTS

      This annual information form contains certain forward-looking statements within the meaning of the United States Private Securities Litigation Reform Act of 1995. Forward-looking statements are typically identified by words such as “anticipate”, “believe”, “expect”, “plan”, “intend” or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking statements in this annual information form include, but are not limited to, statements with respect to: capital investment levels and the allocation thereof, drilling plans and the timing and location thereof, production capacity and levels and the timing of achieving such capacity and levels, pipeline capacity, the timing of pipeline construction, reserve estimates, the use of facilities related to the Hythe Gas Storage Facility and the timing thereof, storage capacity, the level of expenditures for compliance with environmental regulations, site restoration costs including abandonment and reclamation costs, plans for examining the Deep Panuke project, pending litigation, exploration plans, acquisition and disposition plans, including farmout plans, research and development plans, the timing and results of the environmental impact study in the Jonah area, the timing of acquisitions, the timing, completion and capacity of the Starks Storage facility, net cash flows, geographical expansion and plans for seismic acquisitions and surveys.

      Readers are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other things contemplated by the forward-looking statements will not occur. Although EnCana believes that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Some of the risks and other factors which could cause results to differ materially from those expressed in the forward-looking statements contained in this annual information form include, but are not limited to: volatility of oil and natural gas prices, fluctuations in currency and interest rates, product supply and demand, market competition, risks inherent in EnCana’s North American and foreign oil and natural gas and midstream operations, risks of war, hostilities, civil insurrection and instability affecting countries in which EnCana and its subsidiaries operate and terrorist threats, risks inherent in EnCana’s and its subsidiaries’ marketing operations, including credit risk, imprecision of reserves estimates and estimates of recoverable quantities of oil, natural gas and liquids from resource plays and other sources not currently classified as proved reserves, EnCana’s and its subsidiaries’ ability to replace and expand oil and natural gas reserves, EnCana’s ability to generate sufficient cash flow from operations to meet its current and future obligations, EnCana’s ability to access external sources of debt and equity capital, general economic and business conditions, EnCana’s ability to enter into or renew leases, the timing and costs of gas storage facility, well and pipeline construction, EnCana’s ability to make capital investments and the amounts of capital investments, imprecision in estimating the timing, costs and levels of production and drilling, the results of exploration, development and drilling, imprecision in estimates of future production capacity, EnCana’s and its subsidiaries’ ability to secure adequate product transportation, uncertainty in the amounts and timing of royalty payments, imprecision in estimates of product sales, changes in environmental and other regulations or the interpretation of such regulations, risks associated with existing and potential future lawsuits and regulatory actions against EnCana and its subsidiaries, political and economic conditions in the countries in which EnCana and its subsidiaries operate including Ecuador, difficulty in obtaining necessary regulatory approvals and such other risks and uncertainties described from time to time in EnCana’s reports and filings with the Canadian securities authorities and the United States Securities and Exchange Commission (the “SEC”). Statements relating to “reserves” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated, and can be profitably produced in the future. Readers are cautioned that the foregoing list of important factors is not exhaustive. The forward-looking statements contained in this annual information form are made as of the date hereof and EnCana undertakes no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this annual information form are expressly qualified by this cautionary statement.

NOTE REGARDING RESERVES DATA AND OTHER OIL AND GAS INFORMATION

      National Instrument 51-101 (“NI 51-101”) of the Canadian Securities Administrators imposes oil and gas disclosure standards for Canadian public companies engaged in oil and gas activities. NI 51-101 and its companion policy specifically contemplate the granting of exemptions from some of the disclosure standards prescribed by NI 51-101 to companies that are active in the United States (“U.S.”) capital markets, to permit the substitution of the standards required by the SEC in order to provide for comparability of oil and gas disclosure with that provided by U.S. and other international issuers. EnCana has obtained an exemption from Canadian securities regulatory authorities to permit it to provide disclosure in accordance with the relevant legal requirements of the SEC. Accordingly, the reserves data and other oil and gas information included or incorporated by reference in this annual information form is disclosed in accordance with U.S. disclosure requirements and practices. Such information, as well as the information that EnCana discloses in the future in reliance on the exemption, may differ from the corresponding information prepared in accordance with NI 51-101 standards.

      The primary differences between the U.S. requirements and the NI 51-101 requirements are that (i) the U.S. standards require disclosure only of proved reserves, whereas NI 51-101 requires disclosure of proved and probable reserves, and (ii) the U.S. standards require that the reserves and related future net revenue be estimated under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made, whereas NI 51-101 requires disclosure of proved reserves and the related future net revenue estimated using constant prices and costs as at the effective date of the estimation, and of proved and probable reserves and related future net revenue using forecast prices and costs. The definitions of proved reserves also differ, but according to the Canadian Oil and Gas Evaluation Handbook (the reference source for the definition of proved reserves under NI 51-101), differences in the estimated proved reserve quantities based on constant prices should not be material. EnCana concurs with this assessment. There are also differences in accepted practices for determining constant prices for purposes of evaluating bitumen reserves, as outlined under “Narrative Description of the Business — Reserves and Other Oil and Gas Information — Reserve Quantities Information” in this annual information form.

      EnCana has disclosed proved reserve quantities, using the standards contained in U.S. SEC Regulation S-X, and the standardized measure of discounted future net cash flows relating to proved oil and gas reserves determined in accordance with United States Statement of Financial Accounting Standards No. 69 “Disclosures About Oil and Gas Producing Activities” (“FAS 69”).

      Under U.S. disclosure standards, reserves and production information is disclosed on a net basis (after royalties). The reserves and production information contained in this annual information form is shown on that basis.

      In this annual information form, certain crude oil and natural gas liquids (“NGLs”) volumes have been converted to millions of cubic feet equivalent (“MMcfe”) or thousands of cubic feet equivalent (“Mcfe”) on the basis of one barrel (“bbl”) to six thousand cubic feet (“Mcf”). Also, certain natural gas volumes have been converted to barrels of oil equivalent (“BOE”) on the same basis. MMcfe, Mcfe and BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent equivalency at the well head.

CORPORATE STRUCTURE

Name and Incorporation

      As described under “Introductory Information”, EnCana Corporation was formed through the Merger involving AEC and PanCanadian. EnCana is governed by the Canada Business Corporations Act (“CBCA”).

      The executive and registered office of EnCana is located at 1800, 855 – 2nd Street S.W., Calgary, Alberta, Canada T2P 2S5.

Intercorporate Relationships

      The following table presents the name, the percentage of voting securities owned and the jurisdiction of incorporation, continuance or formation of EnCana’s principal subsidiaries and partnerships with total assets that exceed 10 percent of the total consolidated assets of EnCana or revenues that exceed 10 percent of the total consolidated revenues of EnCana as at and for the year ended December 31, 2004:

Notes:

     The above table does not include all of the subsidiaries and partnerships of EnCana. The assets and revenues of unnamed subsidiaries and partnerships in the aggregate did not exceed 20 percent of the total consolidated assets or total consolidated revenues of EnCana as at and for the year ended December 31, 2004.

GENERAL DEVELOPMENT OF THE BUSINESS

      EnCana is one of North America’s leading independent crude oil and natural gas exploration and production companies, based on landholdings and production at December 31, 2004. EnCana pursues growth from its portfolio of unconventional long-life resource plays situated in Canada and the United States. EnCana defines resource plays as large contiguous accumulations of hydrocarbons, located in thick or areally extensive deposits, that typically have low geological and commercial development risk and low average decline rates. EnCana’s disciplined pursuit of these unconventional assets enabled it to become North America’s largest natural gas producer, based on production in the second half of 2004, and a leading developer of oilsands through in-situ recovery. The Corporation is also engaged in exploration and production activities internationally and has interests in midstream operations and assets, including natural gas storage facilities, NGLs processing facilities, power plants and pipelines.

      EnCana operates under two main divisions: (i) Upstream; and (ii) Midstream & Marketing. The following describes the significant events in the last three years that have taken place in these divisions.

Upstream

      The Upstream division manages EnCana’s exploration for, and development and production of, natural gas, crude oil and NGLs and other related activities.

      Following the Merger in 2002, the majority of EnCana’s Upstream operations were located in Canada, the U.S., Ecuador and the U.K. central North Sea. From the time of the Merger through early 2004, EnCana focused on the development and expansion of its highest growth, highest return assets in these key areas. In 2004, EnCana sharpened its strategic focus to concentrate on its inventory of North American resource play assets. In focusing its portfolio of assets, EnCana completed a number of significant acquisitions and dispositions during the past three years.

2004 Acquisitions:

2004 Dispositions:

      Concurrent with the announcement of the U.K. sale, EnCana designated its Ecuador and Gulf of Mexico assets as non-core (for planned future disposition) because these assets no longer fit with EnCana’s North American resource play focus. The Ecuador assets include interests in five Oriente Basin blocks and a 36.3 percent interest in the

Oleoducto de Crudos Pesados (“OCP”) pipeline. The Ecuador Region is now treated as a discontinued operation for financial reporting purposes. The Gulf of Mexico assets include EnCana’s interests in the Tahiti, Tonga, Sturgis, Sawtooth, Jack and St. Malo discoveries. EnCana has an average 40 percent interest in 239 exploration blocks covering approximately 1.4 million gross acres in the Gulf of Mexico.

      In December 2004, EnCana announced its intention to sell additional mature western Canadian conventional oil and natural gas properties representing production of approximately 22,000 barrels of oil equivalent per day. EnCana expects these transactions to close in the second quarter of 2005.

      In February 2005, EnCana Oil and Gas (USA) Inc. announced plans to sell three natural gas gathering and processing facilities in the U.S. — Fort Lupton and Dragon Trail in Colorado, and Lisbon in Utah. The three plants have a total processing capacity of approximately 210 million cubic feet per day.

2003 Acquisitions:

2003 Dispositions:

2002 Acquisitions:

      Over the past three years, EnCana completed a number of other acquisitions and dispositions not listed above. The majority of these transactions were individually valued at less than $100 million.

Midstream & Marketing

      EnCana’s Midstream & Marketing division encompasses the Corporation’s midstream operations and market optimization activities. EnCana’s midstream activities are comprised of natural gas storage operations, NGLs processing and storage, power generation operations and pipelines. EnCana’s marketing groups are focused on enhancing the sale of Upstream’s proprietary production. Correspondingly, the marketing groups undertake market optimization activities, including third party purchases and sales of product, which provides operational flexibility for transportation commitments, product type, delivery points and customer diversification.

      In focusing its portfolio of assets, the Midstream & Marketing division completed a number of project expansions as well as asset dispositions over the past three years.

2004 Projects:

2004 Dispositions:

2003 Projects:

2003 Dispositions:

2002 Dispositions:

NARRATIVE DESCRIPTION OF THE BUSINESS

      The following map outlines EnCana’s onshore North America landholdings and key resource plays as of December 31, 2004.

UPSTREAM

      The majority of EnCana’s Upstream operations are located in Canada, the U.S. and Ecuador. International New Ventures Exploration is mainly focused on opportunities in Africa, Brazil, the Middle East and Greenland.

      As at December 31, 2004, EnCana had net proved reserves of approximately 10.5 trillion cubic feet of natural gas and 501 million barrels of crude oil and NGLs, as estimated by independent qualified reserves evaluators. Proved developed reserves comprise approximately 67 percent of total net proved reserves. See “Reserves and Other Oil and Gas Information” in this annual information form.

Canada

      EnCana has an industry-leading land position in western Canada of approximately 25 million gross acres (approximately 22 million net acres, of which approximately 14 million net acres are undeveloped). The mineral rights on approximately one third of this land is acreage owned in fee title by EnCana, which means that production is subject to a mineral tax that is generally less than the Crown royalty imposed on production from land where the government owns the mineral rights.

      EnCana’s Canadian Upstream operations are divided into two regions — Canadian Plains and Canadian Foothills & Frontier.

Canadian Plains Region

      The Canadian Plains Region encompasses EnCana’s natural gas production activities in southern Alberta and Saskatchewan as well as the Corporation’s primary crude oil thermal recovery projects at Foster Creek and Christina Lake. The three key resource plays in the Canadian Plains Region are: (i) Shallow Gas in southern Alberta (2004 production of approximately 592 million cubic feet per day and 2003 production of approximately 507 million cubic feet per day); (ii) Coalbed Methane (“CBM”) developments in southern and central Alberta (2004 production of approximately 17 million cubic feet per day and 2003 production of approximately four million cubic feet per day); and (iii) Steam-Assisted Gravity Drainage (“SAGD”) operations at Foster Creek (2004 production of approximately 28,774 barrels per day and 2003 production of approximately 21,823 barrels per day).

      EnCana’s 2005 capital investment in core programs for natural gas projects in the Canadian Plains Region is budgeted to be approximately $1,085 million, with approximately $65 million directed to exploration and approximately $1,020 million to development. EnCana anticipates drilling approximately 4,098 gross natural gas wells (3,925 net wells) in this region in 2005. Capital investment in 2005 for crude oil projects is budgeted to be approximately $423 million, primarily directed towards development projects, including approximately $290 million for SAGD projects, and the drilling of approximately 358 gross oil wells (349 net wells).

      The following table summarizes landholdings for the Canadian Plains Region as at December 31, 2004.

      The following table sets forth daily average production figures for the periods indicated.

      The following table summarizes EnCana’s interests in producing wells as at December 31, 2004. These figures exclude wells which were capable of producing, but that were not producing as of December 31, 2004.

      The following describes EnCana’s major producing areas or activities in the Canadian Plains Region.

Suffield

      EnCana holds interests in the Upper Cretaceous shallow natural gas horizons and deeper formations in the Suffield area in southeast Alberta. Suffield is one of the core areas of the Shallow Gas resource play. EnCana also produces conventional heavy oil in the area. The Suffield area is largely made up of the Suffield Block, where operations are carried out by EnCana in cooperation with the Canadian military according to guidelines established under agreements with the Government of Canada.

Brooks

      EnCana produces natural gas, crude oil and NGLs from the Cretaceous horizons in the Brooks area of southern Alberta, located east of Calgary. This area is another core area of the Shallow Gas resource play and is largely comprised of EnCana fee title lands, covering a portion of the Palliser Block.

Chinook

      The Chinook area is located immediately east of Calgary. The majority of the Corporation’s lands in the area are fee title lands on the Palliser Block for which EnCana owns the mineral rights. In addition to operations in the Upper Cretaceous shallow natural gas horizons, the Chinook area is the centre of EnCana’s CBM resource play. The 1,100 section Horseshoe Canyon CBM development is located within the Chinook area. In 2004, EnCana drilled approximately 577 CBM wells on its project area on the Palliser Block, increasing production to approximately 30 million cubic feet per day at year-end. In 2005, EnCana plans to drill approximately 1,000 CBM wells, which is expected to increase CBM production to approximately 60 million cubic feet per day by year-end.

Foster Creek

      EnCana has a 100 percent working interest in Foster Creek, one of the Corporation’s two key crude oil resource plays. EnCana holds surface access and petroleum and natural gas rights for natural gas and oilsands exploration, development and transportation from areas within the Cold Lake Air Weapons Range (Primrose Block) which were granted by the Government of Canada. EnCana has acquired, and has certain rights to acquire, oilsands leases wherever deposits of bitumen are identified within the areas for which petroleum and natural gas lease rights are held. EnCana is currently operating a 100 percent owned thermal oil recovery project in the Foster Creek area of the Primrose Block using SAGD technology.

      Pilot operations at Foster Creek commenced in 1998, and a 20,000 barrel per day commercial facility was started up in 2001. The first expansion, which increased commercial capacity to approximately 30,000 barrels per day, was completed in the third quarter of 2003. Net crude oil production in 2004 averaged approximately 28,800 barrels per day. An additional expansion has been approved and the engineering is underway. A total of 30,000 barrels per day of incremental production capacity is expected to be added in two stages with this development: 10,000 barrels per day of capacity is expected to be on stream in the fourth quarter of 2005, with an additional 20,000 barrels per day expected in the fourth quarter of 2006. EnCana anticipates reaching this expected output of 60,000 barrels per day in early 2007.

      EnCana continues to operate its 80 megawatt, natural gas-fired cogeneration facility in conjunction with its SAGD operation at Foster Creek. The facility reached its full capacity in the fourth quarter of 2003. The steam generated by the facility is being used within the SAGD operation and the excess power generated is being sold into the Alberta Power Pool grid.

Christina Lake

      EnCana has a 100 percent owned thermal crude oil recovery pilot project at Christina Lake which also uses SAGD technology. In 2004, EnCana added two well pairs and had total productive capacity of approximately 6,000 barrels per day at year-end.

Thermal Recovery Research and Development

      EnCana continues to research and develop technologies to increase recovery and decrease the costs of extracting crude oil bitumen from oilsands.

      One focus area is to reduce the reliance on steam in bitumen production. To this end, EnCana is piloting two technologies using solvents as part of the extraction process. The Solvent Aided Process (“SAP”) mixes a small amount of solvent with steam to enhance recovery. A second technology, the Vapex process, uses solvent in place of steam. After piloting SAP at Senlac, Saskatchewan in 2002, EnCana completed construction and commenced operation of a pilot operation at Christina Lake in 2004. The Vapex pilot at Foster Creek has been in operation since 2002. The first phase of the pilot is nearing completion, and there is additional research planned in the area for 2005.

      Another focus area is artificial lift where EnCana is pursuing pump designs that are expected to enable the Corporation to optimize SAGD by operating at lower pressures, thereby realizing lower steam oil ratios and decreasing facility capital costs. EnCana now has more than 10 wells on electrical submersible pumps at Foster Creek, and the Corporation expects to utilize this technology on new SAGD wells. Low pressure SAGD technology is being utilized in one well pair at Foster Creek, and EnCana plans to utilize this technology in up to 10 wells in 2005.

Weyburn

      EnCana has a 62 percent working interest (50 percent economic interest) in the Weyburn crude oil field in southwest Saskatchewan. EnCana is the operator and expects to improve ultimate recovery in the enhanced oil recovery area with a carbon dioxide (“CO₂”) miscible flood project. In 2004, EnCana continued with its infill drilling program which began in 2003. This program ensures optimal coverage of areas currently within the enhanced oil recovery area. Four additional patterns, or well groupings, were completed in the CO₂ miscible flood development in 2004. As of December 31, 2004, there were 36 patterns on stream out of a planned total of 75 patterns.

Canadian Foothills & Frontier Region

      The Canadian Foothills & Frontier Region includes EnCana’s natural gas and crude oil exploration, development and production activities in northern Alberta and British Columbia. It also includes EnCana’s exploration and development activities offshore the East Coast of Canada and in the Mackenzie Delta area of the Northwest Territories. There are three key resource plays in the Canadian Foothills & Frontier Region: (i) Greater Sierra; (ii) Cutbank Ridge; and (iii) Pelican Lake.

      EnCana’s 2005 capital investment in core programs for natural gas projects in the Canadian Foothills & Frontier Region is budgeted to be approximately $1,432 million, with approximately $150 million directed to exploration and approximately $1,282 million to development. EnCana plans to drill approximately 740 gross natural gas wells (688 net wells) and approximately 77 gross crude oil wells (77 net wells) in this region in 2005. Capital investment for crude oil projects is budgeted to be approximately $95 million, primarily directed towards development projects.

      The following table summarizes landholdings for the Canadian Foothills & Frontier Region as at December 31, 2004.

      The following table sets forth daily average production figures for the periods indicated.

      The following table summarizes EnCana’s interests in producing wells as at December 31, 2004. These figures exclude wells which were capable of producing, but that were not producing as of December 31, 2004.

      The following describes EnCana’s major producing areas or activities in the Canadian Foothills & Frontier Region.

Greater Sierra

      The Greater Sierra area of northeast British Columbia is one of EnCana’s key natural gas resource plays. Production in the area has grown from essentially zero in 1998 to an average of approximately 230 million cubic feet per day in 2004. As at December 31, 2004, EnCana held an average 98 percent interest in 13 production facilities in the area that were capable of processing approximately 450 million cubic feet per day of natural gas. In 2004, EnCana completed the construction of the Ekwan pipeline which went into operation on April 1, 2004. The Ekwan pipeline transports natural gas from northeast British Columbia to Alberta. The pipeline extends approximately 80 kilometres and has a capacity of approximately 400 million cubic feet per day. December 2004 throughput for the pipeline was approximately 95 million cubic feet per day.

Cutbank Ridge

      Cutbank Ridge is a key natural gas resource play located in the Canadian Rocky Mountain foothills, approximately 50 kilometres southwest of Dawson Creek, British Columbia. The majority of the Corporation’s lands in this area were purchased in 2003. In 2004, EnCana drilled approximately 50 net natural gas wells at Cutbank Ridge and increased production to approximately 47 million cubic feet per day of natural gas by year-end. In 2005, EnCana plans to drill approximately 100 net natural gas wells at Cutbank Ridge.

Pelican Lake

      Pelican Lake is another of EnCana’s key resource plays producing crude oil in north-central Alberta. In 2004, EnCana continued to expand the waterflood program at Pelican Lake, which has increased the recovery of crude oil in the area. EnCana also holds a 38 percent non-operated interest in a 110-kilometre, 20-inch diameter crude oil pipeline which connects the Pelican Lake area to a major pipeline that transports crude oil from northern Alberta to crude oil markets.

Sexsmith/ Hythe/Saddle Hills

      EnCana produces natural gas, crude oil and NGLs in the Sexsmith/ Hythe/Saddle Hills area in northwest Alberta. EnCana also operates and has a 62 percent interest in the 210 million cubic feet per day Sexsmith sour natural gas and liquids processing plant and an 85 percent interest in the 50 million cubic feet per day Saddle Hills sweet natural gas plant. EnCana also owns 100 percent of and operates the Hythe sour natural gas plant, which has a capacity of approximately 170 million cubic feet per day. The Hythe and Sexsmith sour natural gas plants are interconnected by pipeline to provide greater operating efficiencies. EnCana also owns and operates a 240-kilometre natural gas gathering system in the area.

Cold Lake Air Weapons Range

      EnCana produces natural gas from the Cold Lake Air Weapons Range (formerly referred to as the Primrose Block) located in northeast Alberta. The majority of EnCana’s natural gas production in the area is processed through 100 percent controlled and operated compression facilities. In 2004, production in the area was impacted by the September 2003 Alberta Energy and Utilities Board decision to shut-in natural gas production that may put at risk the recovery of bitumen resources in the area. The decision resulted in a decrease in annualized natural gas production in the area of approximately eight million cubic feet per day. In January 2005, the Government of Alberta reached an agreement with natural gas producers which partially compensates the producers for this shut-in production.

East Coast of Canada

      Offshore Nova Scotia on the East Coast of Canada, EnCana has a 100 percent working interest in the Deep Panuke natural gas discovery. EnCana is in the process of examining the potential economic viability of the Deep Panuke project, and this is expected to continue in 2005.

      In 2004, EnCana participated in the drilling of the Weymouth and Crimson deep water exploration wells offshore Nova Scotia. Both wells were unsuccessful.

      EnCana also has other interests in exploration lands located offshore Nova Scotia and Newfoundland and Labrador.

Mackenzie Delta

      EnCana drilled one exploration well in the Mackenzie Delta region of Canada’s Northwest Territories in 2004. EnCana plans to drill one additional well in the area in 2005, as well as conduct further testing of the well drilled in 2004.

United States

      EnCana’s operations in the U.S. Rockies area are focused on exploiting deep, tight, long-life, unconventional natural gas formations primarily in the Jonah sweet natural gas field located in the Green River Basin of southwest Wyoming, and in the Piceance Basin of northwest Colorado (which includes the Mamm Creek natural gas field). The acquisition of Tom Brown in May 2004 expanded EnCana’s operations within the Green River and Piceance Basins. EnCana’s U.S. operations also include interests in the East Texas and Fort Worth Basins in Texas, the Gulf of Mexico and Alaska, as well as natural gas gathering and processing assets. The majority of the production in the U.S. is from resource plays. The key resource plays are: (i) Jonah; (ii) Piceance; (iii) East Texas; and (iv) Fort Worth.

      EnCana’s 2005 capital investment in core programs for natural gas projects in the U.S. is budgeted to be approximately $1,482 million, with approximately $77 million directed to exploration and approximately $1,405 million to development, and includes the drilling of approximately 923 gross natural gas wells (789 net wells). There are no budgeted amounts for capital investment in crude oil projects.

      The following table summarizes EnCana’s landholdings in the United States as at December 31, 2004.

      The following table sets forth daily average production figures for the periods indicated.

      The following table summarizes EnCana’s interests in producing wells as at December 31, 2004. These figures exclude wells which were capable of producing, but that were not producing as of December 31, 2004.

      The following describes EnCana’s major producing areas or activities in the United States.

Jonah

      EnCana produces natural gas and associated NGLs from the Jonah field, located in southwest Wyoming. The Jonah key resource play represents EnCana’s initial entry into the U.S. Rockies region. Since arriving in 2000, EnCana has approximately tripled both reserves and production — mainly through a combination of infill drilling and advanced hydraulic fracturing techniques. This approach has enabled the Corporation to access the reserves of natural gas in the Lance formation that makes up the Jonah play. These stacked sands exist at depths between 8,000 and 11,500 feet. The U.S. Bureau of Land Management is working on an Environmental Impact Statement covering future development in the area. The study is expected to be complete by mid-2005. EnCana expects that the results of the study will be positive for the Corporation, and will allow for increased production growth at Jonah.

Piceance

      The Piceance Basin in northwest Colorado is one of EnCana’s key natural gas resource plays. This basin is characterized by thick natural gas accumulations primarily in the Williams Fork formation. EnCana entered the basin in 2001 with its acquisition of the Mamm Creek field. The May 2004 acquisition of Tom Brown included properties and natural gas production in the basin. As of December 31, 2004, EnCana had accumulated over one million net acres in the basin and had production of approximately 285 million cubic feet per day.

East Texas

      EnCana produces natural gas in the East Texas Basin. The East Texas properties were acquired as part of the Tom Brown acquisition in 2004, and the basin is one of EnCana’s newest key resource plays. This tight gas, multi-zone play targets the Bossier and Cotton Valley zones. During 2004, EnCana drilled approximately 50 net wells in the basin.

Fort Worth

      EnCana produces natural gas and associated NGLs in the Fort Worth Basin in north Texas. Fort Worth is one of EnCana’s key resource plays, and the Corporation has assembled a significant land position in the Barnett Shale play in this basin. The Corporation entered the area in 2003 with the acquisition of Savannah Energy Inc. (“Savannah”). EnCana is applying horizontal drilling and multi-stage reservoir stimulation to improve performance in this play. The Corporation’s December 2004 purchase of natural gas assets in north Texas included properties located in the Fort Worth Basin.

Gulf of Mexico

      In the summer of 2004, an EnCana subsidiary, EnCana Gulf of Mexico LLC, participated in two exploration and appraisal activities in the Gulf of Mexico. A production test was completed on the two primary zones in the Tahiti well, in which EnCana holds a 25 percent non-operated interest. The well produced at a restricted rate of 15,000 barrels per day. Rate and pressure analysis indicate that the well may be capable of sustained flow of as much as 30,000 barrels of oil per day. In addition, EnCana participated in the deep water Jack exploration well which encountered approximately 350 feet of net pay. EnCana has a 25 percent non-operated interest in the well. In total, EnCana subsidiaries have participated in six discoveries in the Gulf of Mexico since 2002.

      In late 2004, the Gulf of Mexico assets were deemed to be non-core to EnCana. The Corporation plans to dispose of these assets in 2005.

Alaska

      In late 2004, EnCana’s assets in Alaska were deemed to be non-core by the Corporation. EnCana plans to dispose of these assets in 2005.

Gathering & Processing Facilities

      EnCana owns and operates various gas gathering and NGLs processing facilities. Near Rifle, Colorado, EnCana’s gathering facilities have a capacity of approximately 360 million cubic feet per day and include over 645 kilometres of pipelines. Near Fort Lupton, Colorado, the gathering facilities include field compression and over 1,000 kilometres of pipelines. The Fort Lupton processing plant has a capacity of approximately 90 million cubic feet per day. The Corporation’s gathering facilities in Rangely, Colorado include field compression and over 1,600 kilometres of

pipelines. The Dragon Trail processing plant near Rangely has a capacity of approximately 60 million cubic feet per day. The Lisbon plant in Moab, Utah was acquired as part of the Tom Brown acquisition. The Lisbon plant is a sophisticated cryogenic natural gas processing plant with a capacity of approximately 60 million cubic feet per day.

      In February 2005, the Corporation announced its intention to sell the Fort Lupton, Dragon Trail and Lisbon plants and the associated gas gathering facilities.

International New Ventures Exploration

      EnCana invests a small portion (approximately two percent) of its capital in high potential exploration beyond its core geographic areas, primarily in Africa, Brazil, the Middle East and Greenland.

Central and West Africa

      EnCana’s onshore exploration operations in Chad are based out of the Corporation’s office in N’Djamena. EnCana has a 50 percent working interest in Permit H comprising approximately 108 million gross acres (approximately 54 million net acres). EnCana acquired seismic data and completed the drilling of four exploration wells in 2004. In 2005, the Corporation expects to acquire seismic data and anticipates drilling three to five exploration and/or appraisal wells.

      In July 2004, EnCana assigned its entire interest in the offshore Keta Block in Ghana to its partner. The assignment has been submitted to the Government of Ghana and EnCana is awaiting final approval of its exit from Ghana.

Brazil

      In 2004, EnCana entered into a Technology Cooperation Agreement for heavy oil activities with Petrobras, the Brazilian national oil company. This agreement is part of a larger cooperation including joint participation with Petrobras in Agência Nacional do Petróleo (“ANP”) Bid Round 6, in which EnCana acquired an average working interest ranging from 30 to 40 percent in seven Petrobras-operated blocks. This acquisition increased the Corporation’s landholdings by approximately 1.1 million gross acres (approximately 402,000 net acres). In 2005, activity on these offshore blocks is expected to be limited to seismic acquisition.

      In ANP Bid Round 6, EnCana also acquired a 25 percent non-operated interest in offshore Block 101, increasing its land position by approximately 177,000 gross acres (approximately 44,000 net acres). In addition to these newly acquired blocks, EnCana has a 67 percent working interest in Block BM-C-7 comprising approximately 161,000 gross acres (approximately 108,000 net acres) offshore Brazil. In 2004, the Corporation drilled one exploration well and one appraisal well on this block. Evaluation of the results is expected to continue in 2005.

Middle East

      In October 2004, EnCana reached an agreement with the Government of Qatar to enter the second phase of its exploration production sharing agreement on Block 2. This block encompasses most of the onshore lands in the State of Qatar. EnCana’s 100 percent working interest in the landholdings on the block total approximately 2.2 million acres. Plans for 2005 include expected seismic activity and pursuing the planned farmout of a portion of EnCana’s working interest.

      In 2004, the Corporation farmed out a portion of its working interest in Block 47 in the Republic of Yemen. The Corporation has a 36.75 percent working interest in Block 47 (approximately 1.9 million gross acres and approximately 691,000 net acres). EnCana drilled one unsuccessful exploration well on the block in 2004.

      EnCana has a 100 percent working interest in onshore Blocks 3 and 4 in the Sultanate of Oman, which cover approximately 9.6 million acres. EnCana conducted seismic surveys in 2004 and expects to drill one well in 2005. In 2005, EnCana also plans to pursue the farmout of a portion of its interest in Oman.

      EnCana has a 50 percent non-operated working interest in Block 5 in the Kingdom of Bahrain. Block 5 is comprised of approximately 97,000 gross acres (approximately 48,000 net acres). During 2004, seismic data was acquired and one exploration well was drilled and abandoned. EnCana exited the block in early 2005.

Greenland

      EnCana acquired one exploration licence (Lady Franklin) in the 2004 Offshore West Greenland Bid Round. This licence was signed in January 2005. EnCana also has an 87.5 percent working interest in the Atammik block, offshore west Greenland, consisting of approximately 985,000 gross acres (approximately 862,000 net acres). EnCana conducted seismic activities in 2004. In 2005, EnCana expects to conduct additional seismic activity and pursue the farmout of a portion of its working interest in Greenland.

Ecuador

      In late 2004, the Ecuador Region was deemed to be non-core to EnCana. The Corporation plans to dispose of its Ecuadorian operations in 2005. As a result, the Ecuador Region is now treated as a discontinued operation for financial reporting purposes.

      An indirect, wholly owned subsidiary of EnCana owns a concession in the Oriente Basin, known as the Tarapoa Block. The Corporation has a 100 percent working interest in this concession, which is operated under a participation contract which has a primary term through to August 1, 2015. EnCana also has a 40 percent non-operated economic interest in Block 15 in the Oriente Basin. This concession is operated under a participation contract which has primary terms through to July 2012 for base area production and July 2019 for production resulting from additional exploration. In addition, EnCana has a majority operating interest in Blocks 14, 17 and Shiripuno, also in the Oriente Basin. The production contracts for Blocks 14 and 17 expire in July 2012 and December 2018, respectively.

      At December 31, 2004, EnCana held an average 64 percent working and economic interest in approximately 1.4 million gross acres (approximately 894,000 net acres, of which approximately 795,000 net acres are undeveloped) in Ecuador. At December 31, 2004, 211 gross crude oil wells (151 net wells) were producing. EnCana’s contractual entitlement to net crude oil production in 2004 was 76,872 barrels per day (51,089 barrels per day in 2003).

      EnCana’s interests in Ecuador also include an indirect 36.3 percent equity interest in the OCP pipeline. OCP is a 500-kilometre pipeline with a capacity of approximately 450,000 barrels per day that runs from the crude oil producing area of Ecuador to the Pacific Coast. In 2004, shipments on OCP totalled approximately 170,599 barrels per day. Pursuant to the terms of the agreement with the Government of Ecuador, OCP will be transferred to the Government of Ecuador, without cost, after a 20-year operating period. EnCana has a 15-year shipping commitment on OCP of approximately 108,000 barrels per day. EnCana’s shipments on OCP in 2004 averaged approximately 72,636 barrels per day.

MIDSTREAM & MARKETING

Midstream

      EnCana’s midstream activities are primarily comprised of natural gas storage operations, NGLs processing and storage, power generation operations and pipelines. EnCana’s 2005 capital investment in core programs in its midstream operations is budgeted to be approximately $342 million.

Natural Gas Storage

      Based upon overall storage capacity, EnCana is the largest independent (non-utility) natural gas storage operator in North America with facilities in Alberta, California and Oklahoma. EnCana also leases natural gas storage capacity from other storage operators located in the U.S. Gulf Coast and mid-continent regions. At December 31, 2004, EnCana had owned and operated storage capacity of approximately 163 billion cubic feet, as well as leased storage capacity of approximately 15 billion cubic feet.

      EnCana provides a portion of its storage capacity under multi-year firm contracts to industry participants on a fee-for-service basis as well as offering short-term firm or interruptible storage services, all at market based rates. The remaining capacity is used as part of the natural gas storage optimization program (through the purchase and sale of third party gas) and is available to manage EnCana’s produced gas sales.

AECO HUB^TM

      EnCana operates and markets its Alberta natural gas storage facilities under the commercial name AECO HUB^tm. These facilities, all of which are 100 percent owned by EnCana, include the Suffield Gas Storage Facility, the Hythe Gas Storage Facility and the Countess Gas Storage Facility. The AECO HUB^tm is Canada’s largest natural gas storage and trading hub.

          Suffield Gas Storage Facility

      Located on the Suffield Block in southeast Alberta, this facility was the first and is the most significant in the AECO HUB^tm portfolio. It has storage capacity of approximately 85 billion cubic feet, a maximum withdrawal capability of approximately 1.8 billion cubic feet per day and a maximum injection capability of approximately 1.6 billion cubic feet per day.

          Hythe Gas Storage Facility

      The Hythe Gas Storage Facility in northwest Alberta has approximately 10 billion cubic feet of working natural gas capacity, approximately 200 million cubic feet per day of withdrawal capability, and approximately 150 million cubic feet per day of injection capability. The facility is connected to both the Alberta pipeline system of TransCanada Corporation and the Alliance Pipeline system. Commencing April 1, 2004, the compression and pipeline facilities related to the Hythe Gas Storage Facility were temporarily removed from gas storage service and utilized by the Upstream division to facilitate additional production from Cutbank Ridge. This facility is expected to return to gas storage service effective April 1, 2005.

          Countess Gas Storage Facility

      In October 2002, EnCana announced plans to develop a new natural gas storage facility in southeast Alberta that is expected to store up to 40 billion cubic feet of natural gas. The Countess Gas Storage Facility consists of two depleted underground reservoirs located about 85 kilometres east of Calgary. The first 10 billion cubic feet of new storage capacity came online in 2003, with free-flow injection through the summer and plant facilities completion in October. The completed facilities increased 2004 storage capacity to approximately 30 billion cubic feet, maximum withdrawal capability to approximately 850 million cubic feet per day and maximum injection capability to approximately 800 million cubic feet per day. The full 40 billion cubic feet of storage capacity and additional withdrawal capability are expected to be utilized in 2005, upon approval to operate at increased pressures in the reservoir.

Wild Goose Gas Storage Facility

      The Wild Goose Gas Storage Facility, located north of Sacramento, California was California’s first independent natural gas storage facility. In July 2002, Wild Goose was granted permission by the California Public Utilities Commission to approximately double the storage size and approximately triple the withdrawal capacity of the facility. Completion of the initial phase expansion was completed in March 2004, bringing the total working gas capacity to approximately 24 billion cubic feet. The expansion also increased maximum withdrawal capability to approximately 480 million cubic feet per day and expanded maximum injection capability to approximately 450 million cubic feet per day.

Salt Plains Gas Storage Facility

      The Salt Plains Gas Storage Facility, located in northern Oklahoma, has a capacity of 15 billion cubic feet, a maximum withdrawal capability of approximately 200 million cubic feet per day and a maximum injection capability of approximately 150 million cubic feet per day.

Starks Project

      In October 2003, Starks Gas Storage L.L.C., an indirect wholly owned subsidiary of EnCana, announced plans to develop a high-deliverability storage facility in southwest Louisiana. Subject to regulatory approvals and a satisfactory second open season, the facility is expected to be in-service during the third quarter of 2006 with approximately 9 billion cubic feet of initial storage capacity, 350 million cubic feet of injection capacity and 400 million cubic feet of withdrawal capacity. Full future capacity of the Starks facility is expected to be approximately 19 billion cubic feet.

Leased Storage Capacity

      EnCana Gas Storage Inc., an indirect wholly owned subsidiary of EnCana, has entered into contracts to lease storage capacity in the U.S. Gulf Coast and mid-continent regions. Total leased capacity at December 31, 2004 was approximately 15 billion cubic feet. Contracts for approximately 7 billion cubic feet of this capacity expire at the end of March 2005, with the remaining contract terms ranging from 15 months to 12 years.

Natural Gas Liquids

      EnCana holds interests in four NGLs extraction plants that straddle two major natural gas pipelines at Empress, Alberta plus storage and fractionation assets in Saskatchewan, eastern Canada and the U.S.

      At Empress, the rights to extract NGLs from natural gas transported through transmission pipelines are acquired from the shippers of the natural gas. As at December 31, 2004, EnCana’s share of the combined processing capacity was approximately 2.1 billion cubic feet per day.

      Ethane recovered at Empress is sold as a specification product to petrochemical companies for consumption within the Province of Alberta. The remaining liquids components are transported as a mixed stream by pipeline to a plant at Sarnia, Ontario in which EnCana holds an approximate 10.4 percent interest. The mixed stream is fractionated at Sarnia into marketable products: propane, butane and pentanes plus. These are sold to distributors, refiners and petrochemical manufacturers in Canada and the U.S. under contracts, the terms of which are typically one year or less.

      Other significant NGLs midstream assets include: (i) a 50 percent interest in a pipeline that delivers NGLs from Empress to storage facilities and the Enbridge pipeline at Kerrobert, Saskatchewan; (ii) interests in a NGLs storage facility and depropanizer at Superior, Wisconsin; and (iii) a 49 percent interest in a propane and butane storage facility at Marysville, Michigan.

Power

      EnCana is a large consumer of electricity in Alberta and uses a portfolio of physical assets, short to medium term purchases and sales and spot market purchases to manage the cost of electricity for its Upstream and Midstream divisions in Alberta’s deregulated market. The physical assets include two 106 megawatt power plants in southern Alberta and the 80 megawatt Foster Creek cogeneration facility (part of EnCana’s Foster Creek SAGD operation). The Cavalier Power Station, located approximately 54 kilometres east of Calgary, is 100 percent owned and operated by EnCana. The Balzac Power Station, in which EnCana holds a 50 percent non-operated interest, is also located near Calgary. EnCana’s electricity requirements in Alberta are approximately 300 megawatts and its generation capacity is approximately 239 megawatts. The Corporation disposed of its 25 percent non-operated partnership interest in the 110 megawatt Kingston CoGen plant in December 2004.

Pipelines

      In 2004, Entrega, an affiliate of EnCana Oil & Gas (USA) Inc., announced that it is proceeding with its proposed natural gas pipeline project. Once complete, the pipeline is expected to transport natural gas out of Colorado’s Piceance Basin, through Wamsutter, Wyoming, to the Cheyenne natural gas trading hub in northeast Colorado. Upon receipt of FERC certification, the first segment of the pipeline through Wamsutter is expected to be on stream in late 2005, with an initial capacity of approximately 700 million cubic feet per day.

      EnCana holds a 36 percent equity investment in the Trasandino Pipeline system which carries crude oil from Argentina’s Neuquen Basin to refineries in Chile. The pipeline is 420 kilometres in length and has a design capacity of approximately 113,000 barrels per day. Shipments on the Trasandino system in 2004 averaged approximately 57,000 barrels per day (approximately 104,000 barrels per day in 2003). In 2004, as a result of ongoing volume reductions, EnCana reduced the carrying value of its investment in Trasandino by approximately $35 million.

Marketing

      EnCana’s marketing groups are focused on enhancing the sales of the Corporation’s proprietary production. Correspondingly, the marketing groups conduct market optimization activities that include third party purchases and sales of product to provide operational flexibility for transportation commitments, product type, delivery points and customer diversification.

Natural Gas Marketing

      In 2004, approximately 89 percent of EnCana’s produced natural gas sales were directly marketed by EnCana to local distribution companies, industrials and energy marketing companies. The remaining 11 percent of produced natural gas sales were marketed to aggregators who supply natural gas to markets throughout North America. Prices received by EnCana are based primarily upon prevailing index prices for natural gas. Prices are impacted by competing fuels in such markets and by regional supply and demand for natural gas.

      To mitigate the market risk associated with forecasted cash flows, EnCana enters into various risk management contracts relating to produced natural gas. Details of these transactions are found in Note 17 to EnCana’s audited consolidated financial statements for the year ended December 31, 2004.

      In 2004, EnCana sold approximately 51 percent of its produced natural gas (after royalties and mineral taxes) at fixed prices, approximately 4 percent at AECO Index based pricing, approximately 36 percent at NYMEX based pricing and approximately 9 percent at other prices. As of December 31, 2004, for 2005 EnCana has arranged for the sale of approximately 26 percent of its natural gas at fixed prices, approximately 26 percent of its natural gas at insured floor prices, approximately 12 percent exposed to AECO Index based prices, approximately 29 percent exposed to NYMEX based prices and approximately 7 percent at other prices.

      In addition to sales of its proprietary production, EnCana purchases and sells natural gas for the purpose of optimizing the profitability of its midstream assets and the netback price of the Corporation’s proprietary production. In 2004, EnCana’s sales of purchased natural gas amounted to approximately 895 million cubic feet per day (approximately 903 million cubic feet per day in 2003).

Crude Oil Marketing

      EnCana sells and manages the transportation of its western Canadian crude oil to markets in Canada and the U.S. (140,911 barrels per day in 2004 and 138,784 barrels per day in 2003). Crude oil sales are normally executed under spot and monthly evergreen contracts with delivery to major pipeline hubs, such as Edmonton and Hardisty, in Alberta, with EnCana arranging the intermediate transportation on the feeder pipeline systems. Sales are also made on a delivered basis using trunk pipeline systems, such as Enbridge, for sales to U.S. refinery destinations.

      EnCana provides North American marketing services to certain organizations on a fee for service basis. In 2004, EnCana acted as exclusive agent for Canadian Oil Sands Limited (“COS”) and marketed COS’ Syncrude volumes of 85,157 barrels per day (64,863 barrels per day in 2003). The COS marketing agreement terminates in the second quarter of 2006. EnCana also provides marketing services to the Alberta Government’s Department of Energy (73,852 barrels per day in 2004 and 69,264 barrels per day in 2003). This agency agreement ends in the second quarter of 2007.

      In Ecuador, EnCana’s crude oil volumes are sold FOB at the marine loading facility at Balao, Esmeraldas Province, Ecuador. A total of 77,845 barrels per day was marketed in 2004 (45,561 barrels per day in 2003). Until

September 2003, Ecuador production was transported from the Ecuador Oriente region to Balao via the SOTE Pipeline. EnCana began shipping on the OCP Pipeline in September 2003, and the pipeline was fully commissioned in November 2003. EnCana’s production in Ecuador consists of a high viscosity crude oil with characteristics well-suited to refineries on the U.S. West and Gulf Coasts.

      To mitigate the market risk associated with forecasted cash flows, EnCana enters into various risk management contracts relating to crude oil. Details of these transactions are found in Note 17 to EnCana’s audited consolidated financial statements for the year ended December 31, 2004.

NGLs Marketing

      EnCana’s production of NGLs in western Canada is marketed through Kinetic Resources (LPG), an Alberta partnership in which EnCana has an indirect 75 percent interest, and Kinetic Resources (U.S.A.), a Michigan partnership in which EnCana has an indirect 75 percent interest (collectively, “Kinetic”). In 2004, Kinetic continued to market a portion of EnCana’s western Canada NGLs primarily to eastern Canada and the U.S. Kinetic also markets NGLs on behalf of other parties. An indirect 100 percent owned affiliate of EnCana also directly markets certain U.S.-produced NGLs volumes to U.S.-based customers.

RESERVES AND OTHER OIL AND GAS INFORMATION

      EnCana retained independent qualified reserves evaluators to evaluate and prepare reports on 100 percent of EnCana’s crude oil and natural gas reserves as of December 31, 2004. EnCana’s Canadian reserves were evaluated by McDaniel & Associates Consultants Ltd. and Gilbert Laustsen Jung Associates Ltd. EnCana’s U.S. reserves were evaluated by Netherland, Sewell & Associates, Inc. and DeGolyer and MacNaughton. EnCana’s Ecuadorian reserves were evaluated by Gilbert Laustsen Jung Associates Ltd. 2004 was the third consecutive year in which all of EnCana’s reserves were independently evaluated.

      EnCana has a reserves committee of independent board members which reviews the qualifications and appointment of the independent qualified reserves evaluators. The committee also reviews the procedures for providing information to the evaluators. All booked reserves are based upon annual evaluations by the independent qualified reserves evaluators. The evaluations are conducted from the fundamental geological and engineering data.

      Any references to NGLs in this section include condensate.

      As at December 31, 2004, both the U.K. and Ecuador Regions are classified as discontinued operations for financial reporting purposes.

Reserve Quantities Information

      EnCana’s natural gas reserves increased in 2004 from exploration and development drilling and acquisitions. The Corporation’s crude oil and NGLs reserves decreased in 2004 primarily as a result of the divestiture of non-core properties and a negative revision in Canadian bitumen reserves as a result of anomalously lower year-end bitumen prices, as further discussed below. EnCana’s reserves increased in 2003 primarily from exploration and development drilling, and to a lesser extent from acquisitions and upward revisions. Reserve acquisitions were approximately equal to reserve dispositions in 2003. The Corporation’s reserves increased in 2002 predominantly from the Merger with AEC, and also partly due to extensions and discoveries. The 2002 increase was partially offset by downward revisions of reserve quantities.

      On December 31, 2004, being the effective date for the Corporation’s reserves evaluations, field prices for bitumen were much lower than the average for 2004 due to market conditions. The application of U.S. standards for the determination of constant prices as at that date resulted in the removal of the Corporation’s Foster Creek bitumen reserves from the proved category, encompassing a negative revision of approximately 363 million barrels. Canadian securities regulators, in recognition that the bitumen market is not yet mature and that there are no published reference prices for bitumen, have accepted an approach in determining the constant price for bitumen based on using the published price for WTI and historical averages for the adjustments that create the difference in price between WTI and bitumen. Under the accepted Canadian methodology, there would not have been any negative revisions of the Corporation’s proved bitumen reserves.

      The following table sets forth reserves continuity information prepared by EnCana in accordance with U.S. disclosure standards, including FAS 69. The end of year numbers for 2004 represent estimates derived from the reports of the independent qualified reserves evaluators referred to above. The end of year numbers for 2003 and 2002 represent estimates derived from the reports of the independent qualified reserves evaluators who evaluated EnCana’s reserves as of December 31, 2003 and December 31, 2002.

Net Proved Reserves (EnCana Share After Royalties)^(1,2)

Constant Pricing

Notes:

Other Disclosures About Oil and Gas Activities

      The tables in this section set forth oil and gas information prepared by EnCana in accordance with U.S. disclosure standards, including FAS 69.

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein

      In calculating the standardized measure of discounted future net cash flows, year-end constant prices and cost assumptions were applied to EnCana’s annual future production from proved reserves to determine cash inflows. Future production and development costs are based on constant price assumptions and assume the continuation of existing economic, operating and regulatory conditions. Future income taxes are calculated by applying statutory income tax rates to future pre-tax cash flows after provision for the tax cost of the oil and natural gas properties based upon existing laws and regulations. The discount was computed by application of a 10 percent discount factor to the future net cash flows. The calculation of the standardized measure of discounted future net cash flows is based upon the discounted future net cash flows prepared by EnCana’s independent qualified reserves evaluators in relation to the reserves they respectively evaluated, and adjusted by EnCana to account for management’s estimates of risk management activities, asset retirement obligations and future income taxes.

      EnCana cautions that the discounted future net cash flows relating to proved oil and gas reserves are an indication of neither the fair market value of EnCana’s oil and gas properties, nor of the future net cash flows expected to be generated from such properties. The discounted future net cash flows do not include the fair market value of exploratory properties and probable or possible oil and gas reserves, nor is consideration given to the effect of anticipated future changes in crude oil and natural gas prices, development, asset retirement and production costs and possible changes to tax and royalty regulations. The prescribed discount rate of 10 percent may not appropriately reflect future interest rates. The computation also excludes values attributable to EnCana’s Syncrude interest (disposed of in 2003) and Midstream interests.

Standardized Measure of Discounted Future Net Cash Flows

Relating to Proved Oil and Gas Reserves

Changes in Standardized Measure of Discounted Future Net Cash Flows

Relating to Proved Oil and Gas Reserves