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FORM 6-K

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16 of
of the Securities Exchange Act of 1934

For February 26, 2004                                            Commission File Number: 1-15226

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ENCANA CORPORATION
(Translation of registrant’s name into English)

1800, 855 – 2nd Street SW
Calgary, Alberta, Canada T2P 2S5
(Address of principal executive office)

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Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F:

Form 20-F                   Form 40-F  ü 

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1):                          

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7):                          

Indicate by check mark whether by furnishing the information contained in this Form, the registrant is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934:

Yes                   No  ü 

If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): 82-                          

This report furnished on Form 6-K shall be incorporated by reference into each of the Registration Statements under the Securities Act of 1933 of the registrant: Form S-8 No. 333-13956, Form S-8 No. 333-85598 and Form F-9 No. 333-98087.

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SIGNATURES
Form 6-K Exhibit Index
Interim Consolidated Financial Statements
Interim Consolidated Financial Statements

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: February 26, 2004

 

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Form 6-K Exhibit Index

 

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EnCana earns US$2.4 billion in 2003,
cash flow exceeds US$4.4 billion

Annual sales increase by more than 9 percent to 650,200 barrels of oil equivalent per day
Quarterly dividend increased 33 percent to 10 cents US per share

Calgary, Alberta (February 26, 2004) – EnCana Corporation (TSX & NYSE: ECA) earned US$2.36 billion in 2003, up 183 percent from pro forma 2002. Earnings per common share diluted were $4.92. Earnings from continuing operations, excluding gains due to foreign exchange translation of U.S. dollar debt issued in Canada (after tax) and tax rate changes, increased 97 percent in 2003 from pro forma 2002 to $1.38 billion, or $2.87 per common share diluted. The company’s 2003 cash flow increased 67 percent from pro forma 2002 to $4.46 billion, or $9.30 per common share diluted. Strong sales growth and robust commodity prices were significant factors contributing to the strong earnings and cash flow increases. Daily oil, natural gas and natural gas liquids (NGLs) sales volumes were up 9 percent from pro forma 2002, averaging 650,200 barrels of oil equivalent (BOE) per day. Daily sales were comprised of about 2.57 billion cubic feet of natural gas, up 8 percent from pro forma sales in 2002, and approximately 222,500 barrels per day of oil and NGLs, a 13 percent increase. Revenues, net of royalties, in 2003 were $10.2 billion. The EnCana board of directors has approved a 33 percent increase in the company’s quarterly dividend to US$0.10 per common share. The previous quarterly dividend was C$0.10 per common share.

IMPORTANT NOTE: EnCana’s 2003 year-end financial and operating results are reported in U.S. dollars and follow U.S. protocols, which report sales and reserves on an after-royalties basis, unless otherwise stated. Canadian protocols report sales and reserves on a before-royalties basis. See Note 1 herein. All operating results exclude EnCana’s former interest in Syncrude which was sold in 2003 and is treated as a discontinued operation.

All dollar figures are U.S. dollars unless otherwise noted.

All references to 2002 production, sales and financial information in this news release text and tables for EnCana are presented on a pro forma basis as if the merger of PanCanadian Energy Corporation (“PanCanadian” or “PCE”) and Alberta Energy Company Ltd. (“AEC”) had occurred at the beginning of 2002.

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“EnCana delivered outstanding financial and operating results in 2003 and built an even stronger asset base from which to deliver top performance over the long haul. We have increased the intrinsic value of each EnCana share by growing oil and gas sales by an average of 9 percent and increasing proved reserves by 12 percent. The sale of higher cost non-operated assets, combined with the addition of high-quality, long-term growth assets such as Cutbank Ridge, is evidence of our focus on reducing unit costs, growing sales and improving returns,” said Gwyn Morgan, EnCana’s President & Chief Executive Officer.

“With our 203 percent production replacement coming almost entirely through the drill bit, EnCana added 533 million BOE of proved reserves at a finding, development and acquisition cost of $8.75 per BOE. Our operating and administrative costs of $4.11 per BOE are below our 2003 guidance range and one of the lowest among our large capitalization independent peers,” Morgan said.

Solid fourth quarter earnings and cash flow; oil and NGLs sales up 32 percent
In the fourth quarter of 2003, EnCana’s earnings increased 51 percent from the same period in 2002 to $426 million, or $0.91 per common share diluted. Earnings from continuing operations, excluding gains due to foreign exchange translation of U.S. dollar debt issued in Canada (after tax) and tax rate changes, increased 32 percent in the fourth quarter of 2003 compared to the same 2002 period to $316 million, or $0.68 per common share diluted. Fourth quarter cash flow increased 34 percent from the fourth quarter of 2002 to $1.25 billion, or $2.69 per common share diluted. Fourth quarter oil, natural gas and NGLs sales averaged 713,900 BOE per day, up 13 percent from 632,700 BOE per day in the same period in 2002. Natural gas sales averaged 2.68 billion cubic feet per day. Gas production was up 9 percent after adjusting for higher levels of withdrawal from storage in the fourth quarter of 2002. Oil and NGLs sales in the fourth quarter of 2003 averaged 266,900 barrels per day, up 32 percent from the same 2002 period. Revenues, net of royalties were $2.85 billion, up 35 percent from the fourth quarter last year. EnCana drilled 1,517 net wells in the fourth quarter of 2003, comprised of 1,306 development wells and 211 exploration wells.

EnCana confirms 10 percent 2004 organic sales growth target
In 2004, EnCana is forecasting daily sales of between 690,000 and 735,000 BOE, comprised of sales between 2.7 billion and 2.85 billion cubic feet of gas per day and 240,000 and 260,000 barrels of oil and NGLs per day. Achieving the middle of these ranges would result in 10 percent sales growth. The company recently increased its oil sales guidance due to strong field performance and the recent acquisition of additional interests in the Scott and Telford oil fields in the U.K. central North Sea. Natural gas sales guidance remains the same and accounts for modest well freeze-offs in January, sales of non-core properties and expected shut-ins due to regulatory rulings in the gas over bitumen issue in northeast Alberta.

“The end of 2003 was marked by an early freeze up that enabled us to advance our drilling programs, taking 2003 drilling to more than 5,600 net wells and giving us a jump on our 2004 program. Natural gas sales exited the year at about 2.7 billion cubic feet per day, near the low end of our 2004 guidance. We have about 1,200 wells, approximately double our normal inventory, drilled across western North America that are awaiting tie in. Most of these wells are in southern Alberta. The tie-in work is planned to occur following spring break-up when additional rigs and crews from northern regions are expected to become available. These well tie-ins, plus substantial field activity elsewhere in North America, are expected to continue to increase gas sales growth as we move through the year,” said Randy Eresman, EnCana’s Chief Operating Officer.

EnCana’s proved reserves grow 12 percent in 2003; production replacement is 203 percent
On February 10, 2004, EnCana announced that proved reserves increased to 2.36 billion BOE, up 12 percent from year-end 2002. This resulted in a 203 percent production replacement, of which essentially all was organically generated through a successful drilling program and positive revisions. The company added 478 million BOE of proved reserves internally, 55 million BOE by acquisition and divested of 51 million BOE for total additions of 482 million BOE before production. By commodity, EnCana added 1.7 trillion cubic feet of natural gas reserves and 204 million barrels of crude oil and NGLs reserves. EnCana’s proved reserves at year-end were 8.4 trillion cubic feet of natural gas and 957 million barrels of crude oil and NGLs. The company’s proved reserve life index remained at 10 years. All of EnCana’s proved reserves are based on reports prepared by independent qualified reserves evaluators using the fundamental geological and engineering data. The process is supervised by a committee of independent directors. EnCana believes this is the most stringent standard of reserves governance available to the industry, and that it goes well beyond external reviews or audits of reserves.

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“Our reserve additions, two barrels of oil equivalent for every barrel produced, clearly demonstrate the continuous, reliable drill bit growth available through relatively low risk, repeatable development drilling on our huge resource play dominated asset base. We added 1.7 trillion cubic feet of North American gas at a time when overall industry gas reserves and production growth is faltering. We have clearly identifiable captured resource potential on our existing land base which should allow similar organic reserves and production growth for years to come,” Morgan said.

Finding, development and acquisition capital
EnCana invested about $4,650 million of finding, development and acquisition capital, which added 533 million BOE of proved reserves. This resulted in a finding, development and acquisition cost of $8.75 per BOE. During 2003, the average exchange rate was $0.716 to one Canadian dollar, which is a 12 percent increase from the average 2002 rate of $0.637 to one Canadian dollar. As a result of the conversion from Canadian to U.S. dollars, approximately $350 million was added to EnCana’s U.S. dollar finding, development and acquisition capital compared to the previous year. Excluding this estimated appreciation in the Canadian dollar, EnCana’s 2003 finding, development and acquisition costs would be lower by about $0.65 per BOE and result in a marginal increase from the 2002 cost of about $7.95 per BOE.

North American natural gas prices rise in 2003
Natural gas prices across North America rebounded over weaker 2002 prices. The average benchmark NYMEX index price in 2003 was $5.39 per thousand cubic feet, up 67 percent from the average price in 2002, driven by lower levels of natural gas in storage and continued concerns about North American supply. EnCana’s average realized natural gas price, excluding hedging, was $4.87 per thousand cubic feet; including hedging it was $4.77 per thousand cubic feet. This represents an increase of 66 percent over the average pro forma 2002 price including hedging. In the fourth quarter the average benchmark NYMEX index price was $4.58 per thousand cubic feet, an increase of 15 percent from the fourth quarter of 2002. The company’s fourth quarter average realized natural gas price, including hedging, was $4.65 per thousand cubic feet, up 29 percent compared to the fourth quarter of 2002.

World oil prices strong in 2003; Canadian heavy oil price differentials widen
World oil prices improved during 2003 as strong Asian demand, supply disruptions in Venezuela and Nigeria, the slow return of Iraqi oil production and OPEC’s production management, kept crude oil inventories low. During the year, the average benchmark West Texas Intermediate (WTI) crude oil price was $30.99 per barrel, up 19 percent over 2002. Canadian and Ecuadorian heavy oil price differentials widened during the year primarily in response to the higher WTI price. In September 2003, the OCP Pipeline began operations and the shippers created a new Ecuadorian crude oil stream called NAPO blend. The NAPO blend is a heavier crude oil than the Oriente blend. It received a WTI differential that averaged $8.06 per barrel in 2003, compared to the average Oriente differential of $5.59 per barrel. In 2003, EnCana’s average realized oil and NGLs price, excluding hedging, was $23.25 per barrel; including hedging it was $20.71 per barrel. In the fourth quarter, the company’s average realized oil and NGLs price, excluding hedging, was $22.51 per barrel; including hedging it was $20.36 per barrel.

Risk management programs help reduce cash flow risk
EnCana’s risk management program is designed to partially mitigate the volatility associated with commodity prices, exchange rates and interest rates. From time to time, EnCana will fix prices on future oil and gas sales to reduce the market risk associated with forecasted cash flows. EnCana has about 45 percent of projected 2004 gas sales, after royalties, hedged at an average effective NYMEX price of about $5.24 per thousand cubic feet, based upon an exchange rate of $0.758 to one Canadian dollar and a $0.73 per thousand cubic feet AECO basis for Canadian conversions. About half of EnCana’s projected 2004 oil sales are hedged with swaps or subject to costless collars between $20 and $26 WTI. The detailed risk management positions at December 31, 2003 are presented in Note 12 to the unaudited fourth quarter Consolidated Financial Statements. EnCana’s financial commodity price and currency risk management measures resulted in revenue being lower in the fourth quarter by approximately $15 million, comprised of $53 million of lower revenue on oil sales and $38 million of higher revenue on gas sales. For the full year, EnCana’s financial commodity and currency risk management measures resulted in revenue being lower by approximately $297 million, comprised of $206 million on oil sales and $91 million on gas sales.

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Consolidated EnCana Highlights
US$ and U.S. protocols

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1		Impact of including share options in earnings calculations The company has early adopted the Canadian accounting standard for stock-based compensation as outlined in the Canadian Institute of Chartered Accountants Handbook section 3870. Following this standard, the policy has been adopted prospectively, meaning prior years have not been restated. As a result, EnCana recorded compensation expense of $18 million in relation to outstanding share options issued in 2003. 2003 net earnings per common share – basic would have been $5.02 per common share, $0.04 per common share higher, had the company not adopted this standard.
2		Excludes EnCana’s share of Syncrude volumes, which were nil in the fourth quarter of 2003, compared to 33,918 barrels per day in the fourth quarter of 2002. For the year ended 2003, Syncrude volumes averaged 7,629 barrels per day, compared to 31,267 barrels per day in 2002.
3		Important Notice: Readers are cautioned that comparisons to 2002 full year results are based on 2002 pro forma calculations and these pro forma results may not reflect all adjustments and reconciliations that may be required under Canadian generally accepted accounting principles. These pro forma results may not be indicative of the results that actually would have occurred or of the results that may be obtained in the future. Also, certain information provided for prior years has been reclassified to conform to the presentation adopted in 2003.

Natural gas, oil and NGLs prices US$ and U.S. protocols

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Canadian protocol reporting
During the transition period over year-end 2003, when EnCana changed from reporting in Canadian dollars and before-royalty reserves and production protocols to U.S. dollars and after-royalty reserves and production protocols, EnCana is providing its sales highlights table in both formats. EnCana’s 2003 annual report will be entirely in U.S. dollars and protocols.

Consolidated EnCana Highlights
Canadian $ and Canadian protocols

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4		Impact of including share options in earnings calculations The company has early adopted the Canadian accounting standard for stock-based compensation as outlined in the Canadian Institute of Chartered Accountants Handbook section 3870. Following this standard, the policy has been adopted prospectively, meaning prior years have not been restated. As a result, EnCana recorded compensation expense of C$24 million in relation to outstanding share options issued in 2003. 2003 net earnings per common share — basic would have been C$6.96 per common share, C$0.05 per common share higher, had the company not adopted this standard.
5		Excludes EnCana’s share of Syncrude volumes, which were nil in the fourth quarter of 2003, compared to 34,261 barrels per day in the fourth quarter of 2002. For the year ended 2003, Syncrude volumes averaged 7,697 barrels per day, compared to 31,556 barrels per day in 2002.

Natural gas, oil and NGLs prices Canadian $ and Canadian protocols

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Corporate developments

Quarterly dividend increased 33 percent to US$0.10 per share
EnCana’s board of directors has declared a quarterly dividend of $0.10 per share payable on March 31, 2004 to common shareholders of record as of March 15, 2004. This is a 33 percent increase in the dividend based on current exchange rates. The previous quarterly dividend was C$0.10 per common share.

Normal Course Issuer Bid purchases
In October 2003, EnCana received approval from the Toronto Stock Exchange to purchase, for cancellation, common shares under a Normal Course Issuer Bid. Under the bid, EnCana is entitled to purchase for cancellation up to 23.2 million of its common shares over a 12-month period ending October 21, 2004. In 2003, combined purchases under the current bid and a previous bid were 23.8 million shares at an average price of C$49.65 per share. These purchases more than offset the approximately 5.5 million shares issued in 2003 as a result of the exercise of share purchase options. In 2004, EnCana has purchased for cancellation 2.5 million of its shares at an average price of C$54.52 per share under its current Normal Course Issuer Bid, approximately equal to share option exercises.

Coupon Reset Subordinated Term Securities to be redeemed
On February 4, 2004, the company announced that it intends to redeem on March 23, 2004 all of its Coupon Reset Subordinated Term Securities, Series A (Term Securities), which have an aggregate principal amount of C$125,625,000. The redemption price of the Term Securities is the principal amount thereof plus accrued and unpaid interest to the redemption date.

Financial strength

EnCana maintained its strong balance sheet in 2003. At December 31, 2003, the company’s net debt-to-capitalization ratio was 34:66. EnCana’s net debt-to-EBITDA multiple, on a trailing 12-month basis, was 1.3 times.

On October 2, 2003, EnCana completed a public offering in the United States of $500 million of 4.75% Notes due October 15, 2013. The net proceeds of the offering have been used to repay existing floating-rate bank and commercial paper indebtedness. As at December 31, 2003, approximately 52 percent of EnCana’s outstanding debt was in U.S. dollars and 65 percent of total debt was long-term fixed rate. EnCana maintains strong investment grade credit ratings from three rating services: A(low) by Dominion Bond Rating Service Limited; Baa1 by Moody’s Investors Service and A- by Standard and Poor’s Ratings Services. At December 31, 2003, the company also had a $3.1 billion credit facility with a syndicate of major banks and lending institutions, of which more than $1.3 billion was unutilized.

EnCana generated 2003 cash flow of $4,459 million; of that amount approximately $1,900 million was reinvested to maintain production at previous levels, resulting in free cash flow of $2,559 million available for dividends, share purchases and reinvestment in growth opportunities. Core capital investment was $4,502 million, $1,319 million of which was invested in the fourth quarter. Asset and corporate acquisitions in the year were $820 million and proceeds from asset and corporate dispositions were $2,285 million, including the assumption of $385 million of debt by a purchaser, resulting in net capital investment of $3,037 million.

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EnCana 2003 capital investment

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Net proceeds were $1,024 million less $385 million of debt, which was assumed by the purchaser, resulting in net cash proceeds of $639 million.

Cash taxes
During the fourth quarter of 2003, EnCana recognized a current income tax recovery of $73 million resulting in a cumulative income tax recovery of $56 million for the year. The fourth quarter recovery relates principally to a shift of approximately $90 million of previously anticipated 2003 current Canadian income tax expense to 2004.

Operational highlights

Upstream

Strong sales growth, international achievements and strategic refinement in 2003
EnCana’s 2003 upstream operations were marked by continued strong growth in daily sales and year-over-year proved reserves additions, plus some significant strategic developments. Sale of the company’s interest in Syncrude, plus the recent divestiture of its interest in Petrovera Resources, narrowed the company’s Canadian oil focus towards developing its low-cost, 100 percent owned and operated heavy oil reserves, primarily through steam-assisted gravity drainage (SAGD) projects at Foster Creek and Christina Lake, its Pelican Lake water flood project, all in northeast Alberta and its heavy oil property at Suffield in southern Alberta. In the fourth quarter SAGD production reached more than 35,000 barrels per day following the completion of the successful expansion of the Foster Creek project. Pelican Lake production averaged 16,000 barrels of oil per day in 2003 as a result of a successful water flood and Suffield production averaged 27,000 barrels per day in 2003, an 18 percent increase from 2002 levels. EnCana’s other major oil development this year was the completion and opening of the OCP Pipeline in Ecuador, a five-year project that enabled EnCana to double its production to more than 70,000 barrels of oil per day in the fourth quarter. In the U.K. central North Sea, the acquisition of interests in the Scott and Telford fields from Amerada Hess and Shell has brought current production to about 21,000 BOE per day. Development of the Buzzard oil field is progressing as planned following the receipt of regulatory approval. First oil from Buzzard is expected in late 2006.

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In natural gas, EnCana achieved strong growth from its prolific resource plays in the U.S. Rockies, acquired a new, high potential resource play at Cutbank Ridge in British Columbia and extended shallow gas development in southern Alberta to include commercial production from coalbed methane (CBM). In 2003, the company drilled 5,632 net wells, about 13 percent more than forecast, which included 5,016 development wells and 616 exploration wells. EnCana currently has about 25 rigs running in the U.S. Rockies and about 100 rigs across Western Canada.

North America

U.S.A. region grows 2003 natural gas production by 49 percent
U.S.A. production averaged 588 million cubic feet in 2003, up 49 percent from pro forma 2002. Fourth quarter production averaged 654 million cubic feet per day, up 27 percent from the same period in 2002. Current U.S.A. production is averaging 675 million cubic feet per day. In order to help mitigate pricing risk due to gas transportation constraints out of the U.S. Rockies, EnCana has fixed the price differential between NYMEX and the Rockies on an average of 645 million cubic feet per day of forecast gas sales for 2004 through 2007 at an average basis of $0.52 per thousand cubic feet.

“We’ve made strong progress during 2003 developing our two core properties, Jonah in Wyoming and Mamm Creek in Colorado, where production has increased approximately 50 percent in the past year. In 2004, we look forward to the completion of the regulatory review of our infill drilling plans at Jonah, plus advancing the development of promising new resource plays in Colorado and Texas,” said Roger Biemans, President of EnCana’s U.S.A. region.

Continued drilling success at Greater Sierra
EnCana ramped up production at the Greater Sierra resource play in 2003 by drilling 207 net wells in the area. Greater Sierra production exited 2003 at about 215 million cubic feet per day. Favourable changes in the B.C. government’s royalty regime for summer drilling and the province’s commitment to improve road infrastructure, combined with early winter drilling conditions in the fourth quarter, enabled EnCana to step up its development at Greater Sierra. Construction of EnCana’s new Ekwan Pipeline started in December. This 80 kilometre link to the Alberta gas transmission system has a planned capacity of more than 400 million cubic feet per day. With start-up planned during the second quarter of 2004, the Ekwan Pipeline is expected to facilitate continued sales growth from northeast B.C., where the company currently has about 32 rigs drilling this winter.

EnCana plans to drill 300 coalbed methane wells in 2004
In 2003, the company drilled about 270 CBM wells; about half are on production. CBM production exited the year at about 10 million cubic feet per day. EnCana is expanding CBM development on its 700,000 acres of 100 percent owned royalty-free lands in southern Alberta. EnCana expects to drill approximately 300 wells in 2004, taking production to about 30 million cubic feet per day by year-end 2004. Over the next five years, EnCana expects to increase natural gas production from coal seams to more than 200 million cubic feet per day.

Cold January weather and regulatory ruling trim gas production
Extremely cold weather across Western Canada in January 2004 caused some EnCana gas wells to freeze, resulting in the shut in, on average, of about 100 million cubic feet of daily gas production during January. In addition, the Alberta Energy and Utilities Board recently ordered some additional shut-ins of certain gas wells located in areas of northeast Alberta where bitumen is also produced from deeper geological formations. In September 2003, the regulator shut in about 10 million cubic feet of EnCana’s daily gas production. The most recent ruling could take that total to about 20 million cubic feet per day. The shut-in rulings are subject to additional AEUB hearings in the weeks ahead that will determine their finality. Also, about 15 million cubic feet per day of non-core Canadian gas production has been sold so far in 2004. These gas production reductions have been accounted for in the company’s 2004 sales forecast range.

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Sharpening heavy oil focus – sale of 53.3 percent interest in Petrovera
On February 18, 2004, EnCana sold its 53.3 percent interest in Petrovera Resources for approximately $285 million, before working capital adjustments. In 2003, EnCana’s share of Petrovera’s production represented about 20,000 BOE per day. This divestiture is consistent with EnCana’s strategy to have high working interest, operated assets where it is able to apply core competencies and manage operating costs.

New plan being developed for Deep Panuke
EnCana has initiated work on a new plan for a potential offshore development at Deep Panuke. Two successful exploration wells near the Deep Panuke natural gas field – Margaree and Marcoh, have increased the company’s confidence in the commercial potential of this discovery located about 250 kilometres southeast of Halifax, Nova Scotia. Given the numerous changes at Deep Panuke, the original development plan was no longer appropriate. Consequently, on December 3, 2003, EnCana withdrew the original Deep Panuke development applications filed with the National Energy Board and the Canada-Nova Scotia Offshore Petroleum Board in March 2002.

International

International sales up 113 percent in the fourth quarter
Sales from EnCana’s international operations averaged 95,800 BOE per day in the fourth quarter, up 113 percent from sales of about 45,000 BOE per day in the same period last year. This doubling of sales results from the opening of the OCP Pipeline in Ecuador in early September 2003 and increased ownership in the Scott and Telford fields in the U.K. central North Sea.

Ecuador production reaches full stride
EnCana has completed its first full quarter of unrestrained production from its Ecuador oil fields, selling 77,400 barrels of oil per day in the fourth quarter of 2003, up 115 percent from the same period in 2002. For the full year, Ecuador sales reached about 46,500 barrels per day, up 27 percent compared to pro forma 2002 sales. The majority of EnCana’s Ecuador production growth in 2003 was from EnCana’s 100 percent owned Tarapoa block and the company’s 40 percent non-operated interest in Block 15. In 2004, EnCana is focused on achieving operating cost efficiencies in all Ecuador operations and examining additional exploration opportunities on its expanded base of more than 800,000 acres of net undeveloped land.

Buzzard field development plan receives approval
On November 27, 2003, the U.K. Department of Trade and Industry granted regulatory approval of EnCana’s development plan for the North Sea’s Buzzard oil field. Production from the field is expected to start in late 2006, reaching a plateau of about 180,000 barrels of oil per day in 2007. The $2 billion Buzzard development will consist of three bridge-linked steel platforms supporting facilities for drilling, production, and utilities and accommodation respectively. The facilities include two subsea water injection manifolds located about two kilometres from the platform. The crude oil is expected to be transported to the mainland via a pipeline tie-in to the nearby Forties Pipeline System. The natural gas is expected to flow to market via the Frigg Pipeline System. Buzzard is located in about 100 metres of water, approximately 100 kilometres northeast of Aberdeen, Scotland and about 55 kilometres from the coast at Peterhead. EnCana is the operator of Buzzard, holding approximately 43 percent of the field, which is expected to produce about 75,000 barrels per day of light, royalty-free oil net to EnCana once the field reaches plateau level.

EnCana increased interests in Scott & Telford fields and takes over operatorship
EnCana has more than doubled its ownership of the Scott and Telford oilfields in the U.K. central North Sea. In October 2003, EnCana acquired an additional 14 percent interest in the Scott and Telford fields and subsequently took over operatorship. U.K. sales averaged 18,400 BOE per day in the fourth quarter, an increase of 102 percent over the fourth quarter of 2002. In early 2004, EnCana closed a second transaction, increasing its interests to 41 percent of Scott and 54.3 percent of Telford. EnCana is focusing its efforts on reducing the per-unit operating costs at Scott-Telford and accumulating substantial operating experience that it intends to apply in the development and daily operations of the Buzzard project.

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Midstream & Marketing

EnCana’s Midstream & Marketing division achieved $53 million of operating cash flow in 2003, which was within the company’s 2003 revised guidance range of $48 million to $55 million. Lower than expected seasonal price differentials during much of the year resulted in lower prices bid for storage capacity and reduced opportunities for storage optimization as compared to previous years.

Expansion of independent gas storage in Alberta and California
In 2003, EnCana completed construction of its Countess gas storage facility and injected 11 billion cubic feet of gas over the year. Future expansion plans at Countess are expected to take capacity to 30 billion cubic feet in the summer of 2004 and 40 billion cubic feet in 2005, when maximum withdrawal capability is expected to reach 1.2 billion cubic feet per day. Completion of a 10 billion cubic feet expansion of the Wild Goose facility in northern California is expected in April 2004, bringing the total working gas capacity to 24 billion cubic feet. The expansion is expected to more than double the facility’s withdrawal capability to 480 million cubic feet per day and expand daily injection capability from 80 million to 450 million cubic feet per day. With the company’s recently expanded storage network, plus other projects underway or in planning, EnCana expects to fortify its position as a North American leader in independent gas storage.

Expansion of U.S. Rockies gas transmission capacity planned
Entrega Gas Pipeline Inc., an affiliate of EnCana Oil & Gas (USA) Inc., plans to file a letter with the U.S. Federal Energy Regulatory Commission outlining preliminary plans to build a natural gas pipeline from northwest Colorado to the Cheyenne gas trading hub in northeast Colorado. Entrega is developing this proposed pipeline based on the industry’s growth forecast for gas production and the need to expand gas transportation capacity from the U.S. Rockies to major American markets. The Entrega Pipeline, with an expected initial capacity of 1.3 billion cubic feet per day, is planned to begin service in 2005. The project is subject to approval by the EnCana board of directors and regulatory approval by federal and state agencies. The company plans to hold an open season seeking shippers to contract for capacity on the proposed Entrega Pipeline.

FINANCIAL INFORMATION

NOTE: All financial information in this news release reflects actual results, except for the company’s 2002 pro forma twelve-month financial results, which reflect the results of PanCanadian and AEC as if they had merged at the beginning of 2002. The actual statements for the twelve months of 2002 represent PanCanadian results alone during the first quarter of 2002 as the merger did not occur until the beginning of April 2002.

This news release and EnCana’s supplemental information, including supplemental Canadian dollar and protocol information, are posted on the company’s Web site: www.encana.com

Updated guidance
EnCana has posted an updated guidance document on its Web site.

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CONFERENCE CALL TODAY

EnCana Corporation will host a conference call today, Thursday, February 26, 2004 starting at 9 a.m., Mountain Time (11 a.m. Eastern Time), to discuss EnCana’s fourth quarter and year-end 2003 financial and operating results.

To participate, please dial (719) 457-2641 approximately 10 minutes prior to the conference call. An archived recording of the call will be available from approximately 5 p.m. on February 26, 2004 until midnight March 2, 2004 by dialing (888) 203-1112 or (719) 457-0820 and entering pass code 759990.

A live audio Web cast of the conference call will also be available via EnCana’s Web site, www.encana.com, under Investor Relations. The Web cast will be archived for approximately 90 days.

NOTE 1: EnCana financial results in U.S. dollars and operating results according to U.S. protocols
Starting with year-end 2003, EnCana is reporting its financial results in U.S. dollars and its reserves and production according to U.S. protocols in order to facilitate a more direct comparison to other North American upstream oil and natural gas exploration and development companies. Reserves and production are reported on an after-royalties basis. There is no change to the physical volumes produced and sold or to the actual reserves as a result of adopting U.S. protocols. However, readers should note that the change results in a general lowering of reported numbers for EnCana’s sales volumes and impacts the percentage changes year over year. For example, under previous Canadian protocols, if EnCana produced and sold 100 barrels of oil at the wellhead, it reported sales of 100 barrels. Under the new U.S. protocol, royalties paid to the Crown, state or mineral rights owners are deducted before sales volumes are reported. For example, under U.S. protocols, if EnCana produced and sold 100 barrels and the oil was subject to a 20 percent royalty, EnCana would report sales of 80 barrels of oil.

NOTE 2: Non-GAAP measures
This press release contains references to cash flow, free cash flow, EBITDA (earnings before interest, income taxes, depreciation, depletion and amortization) and earnings from continuing operations, excluding gains from foreign exchange translation of U.S. dollar denominated debt issued in Canada (after tax) and tax rate changes, and the related basic and diluted per common share amounts as applicable, which are not measures that have any standardized meaning prescribed by Canadian GAAP and are considered non-GAAP measures. Therefore, these measures may not be comparable to similar measures presented by other issuers. These measures have been described and presented in this press release in order to provide shareholders and potential investors with additional information regarding EnCana’s liquidity and its ability to generate funds to finance its operations.

EnCana Corporation
With an enterprise value of approximately $25 billion, EnCana is one of the world’s leading independent oil and gas companies and North America’s largest independent natural gas producer and gas storage operator. Ninety percent of the company’s assets are in four key North American growth platforms. EnCana is the largest producer and landholder in Western Canada and is a key player in Canada’s emerging offshore East Coast basins. Through its U.S. subsidiaries, EnCana is one of the largest gas explorers and producers in the Rocky Mountain states and has a strong position in the deepwater Gulf of Mexico. International subsidiaries operate two key high potential international growth platforms: Ecuador, where it is the largest private sector oil producer, and the U.K. central North Sea, where it is the operator of a large oil discovery. EnCana and its subsidiaries also conduct high upside potential new ventures exploration in other parts of the world. EnCana is driven to be the industry’s high performance benchmark in production cost, per-share growth and value creation for shareholders. EnCana common shares trade on the Toronto and New York stock exchanges under the symbol ECA.

ADVISORY REGARDING RESERVES DATA AND OTHER OIL AND GAS INFORMATION – The reserves and other oil and gas information contained in this news release has been prepared in accordance with U.S. disclosure standards, in reliance on an exemption from the Canadian disclosure standards granted to EnCana by Canadian securities regulatory authorities. Such information may differ from the corresponding information

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prepared in accordance with Canadian disclosure standards under National Instrument 51-101 (NI 51-101). The reserves quantities disclosed in this news release represent net proved reserves calculated on a constant price basis using the standards contained in U.S. Securities and Exchange Commission Regulation S-X and FAS 69.

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 last day of the financial year, 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.

The finding, development and acquisition costs per BOE in this press release have been calculated by dividing total capital expended on finding, development and acquisition activities by additions to proved reserves, before divestitures, which are the sum of revisions, extensions & discoveries and acquisitions. This calculation is commonly used in the U.S. EnCana’s average finding, development and acquisition cost per BOE for its three most recent financial years was $8.35 (combining the results of PanCanadian and AEC for periods prior to the merger).

In this news release, certain natural gas volumes have been converted to BOE on the basis of six thousand cubic feet (Mcf) to one barrel (bbl). BOE may be misleading, particularly if used in isolation. A BOE conversion ratio of 6Mcf:1bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent equivalency at the well head.

ADVISORY REGARDING FORWARD-LOOKING STATEMENTS – In the interests of providing EnCana shareholders and potential investors with information regarding EnCana, including management’s assessment of EnCana’s and its subsidiaries’ future plans and operations, certain statements contained in this news release are forward-looking statements within the meaning of the “safe harbour” provisions of the United States Private Securities Litigation Reform Act of 1995. Forward-looking statements in this news release include, but are not limited to: future economic performance (including per share growth); anticipated life of proved reserves; anticipated success of resource plays; potential success of such projects as SAGD, Ecuador, Deep Panuke, Buzzard, Cutbank Ridge, Wild Goose, Countess and Entrega; anticipated capacities of the Wild Goose and Countess storage facilities; anticipated completion dates for the expansions at Wild Goose and Countess; the anticipated completion, timing and capacity of the Entrega Pipeline; the anticipated production of oil from Buzzard in 2006 and 2007; anticipated leadership in North America for independent gas storage; estimated recycle ratios; potential demand for gas; anticipated production in 2004 and beyond; anticipated development of undeveloped reserves over the next three years; anticipated drilling; potential capital expenditures and investment; anticipated completion and capacity of the Ekwan Pipeline; anticipated CBM development in 2004 and beyond; potential oil and gas sales in 2004 and beyond, anticipated costs; potential risks associated with drilling and references to potential exploration. 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 forward-looking statements will not occur, which may cause the company’s actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. These risks and uncertainties include, among other things: volatility of oil and gas prices; fluctuations in currency and interest rates; product supply and demand; market competition; risks inherent in the company’s marketing operations, including credit risks; 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 or probable reserves; the company’s ability to replace and expand oil and gas reserves; its ability to generate sufficient cash flow from operations to meet its current and future obligations; its ability to access external sources of debt and

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equity capital; the timing and the costs of well and pipeline construction; the company’s ability to secure adequate product transportation; changes in environmental and other regulations; political and economic conditions in the countries in which the company operates, including Ecuador; the risk of war, hostilities, civil insurrection and instability affecting countries in which the company operates and terrorist threats; risks associated with existing and potential future lawsuits and regulatory actions made against the company; the risk that the anticipated synergies to be realized by the merger of AEC and PCE will not be realized; costs relating to the merger of AEC and PCE being higher than anticipated and other risks and uncertainties described from time to time in the reports and filings made with securities regulatory authorities by EnCana. 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. Readers are cautioned that the foregoing list of important factors is not exhaustive.

Furthermore, the forward-looking statements contained in this news release are made as of the date of this news release, and EnCana does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this news release are expressly qualified by this cautionary statement.

Further information on EnCana Corporation is available on the company’s Web site, www.encana.com, or by contacting:

 

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Interim Consolidated Financial Statements

For the period ended December 31, 2003

EnCana Corporation

U.S. DOLLARS

 

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For the period ended December 31, 2003

EnCana Corporation

CONSOLIDATED STATEMENT OF EARNINGS

CONSOLIDATED STATEMENT OF RETAINED EARNINGS

See accompanying Notes to Consolidated Financial Statements.

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For the period ended December 31, 2003

EnCana Corporation

CONSOLIDATED BALANCE SHEET

See accompanying Notes to Consolidated Financial Statements.

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For the period ended December 31, 2003

EnCana Corporation

CONSOLIDATED STATEMENT OF CASH FLOWS

See accompanying Notes to Consolidated Financial Statements.

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For the period ended December 31, 2003

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)

1. BASIS OF PRESENTATION

The interim Consolidated Financial Statements include the accounts of EnCana Corporation and its subsidiaries (the “Company”), and are presented in accordance with Canadian generally accepted accounting principles. The Company is in the business of exploration, production and marketing of natural gas, natural gas liquids and crude oil, as well as natural gas storage operations, natural gas liquids processing and power generation operations.

The interim Consolidated Financial Statements have been prepared following the same accounting policies and methods of computation as the annual audited Consolidated Financial Statements for the year ended December 31, 2002, except as noted below. The disclosures provided below are incremental to those included with the annual audited Consolidated Financial Statements. The interim Consolidated Financial Statements should be read in conjunction with the annual audited Consolidated Financial Statements and the notes thereto for the year ended December 31, 2002.

2. CHANGE IN ACCOUNTING POLICIES AND PRACTICES

Reporting Currency

The Company has adopted the United States dollar as its reporting currency since most of its revenue is closely tied to the U.S. dollar and to facilitate a more direct comparison to other North American upstream exploration and development companies. The Company uses the current rate method for foreign currency translations. All prior periods have been restated to reflect the United States dollar as the reporting currency.

Preferred Securities

The Company has retroactively adopted the amendments made to the Canadian Institute of Chartered Accountants (“CICA”) Handbook section 3860, “Financial Instruments — Disclosure and Presentation”. As a result, the preferred securities issued by the Company are now recorded as a liability and included in long-term debt. The effect on the Company’s Consolidated Statement of Earnings was to increase net earnings by $6 million (2002 — $2 million decrease). The effect to the Company’s Consolidated Balance Sheet is to increase current portion of long-term debt by $97 million, increase long-term debt by $321 million and decrease shareholders’ equity by $418 million (2002 — $369 million increase to long-term debt; $289 million decrease to preferred securities of subsidiary; $80 million decrease to shareholders’ equity).

Asset Retirement Obligations

The Company has retroactively early adopted the Canadian accounting standard outlined in CICA Handbook section 3110, “Asset Retirement Obligations”. This new section requires liability recognition for retirement obligations associated with tangible long-lived assets, such as producing well sites, offshore production platforms and natural gas processing plants. The obligations included within the scope of this section are those for which a company faces a legal obligation for settlement or has made promissory estoppel. The initial measurement of the asset retirement obligation is at fair value, defined as “the price that an entity would have to pay a willing third party of comparable credit standing to assume the liability in a current transaction other than in a forced or liquidation sale.”

The asset retirement cost, equal to the fair value of the retirement obligation, is capitalized as part of the cost of the related long-lived asset and allocated to expense on a basis consistent with depreciation, depletion and amortization.

The Company previously estimated costs of dismantlement, removal, site reclamation, and other similar activities and recorded them into earnings on a unit-of production basis over the remaining life of the proved reserves and accumulated a liability on the Consolidated Balance Sheet. Upon adoption, all prior periods have been restated for the change in accounting policy. The change results in an increase in net earnings of $36 million for the year ended December 31, 2003 (2002 — $34 million increase). The effect of this change on the December 31, 2003 Consolidated Balance Sheet is an increase in property, plant and equipment of $142 million (2002 — $94 million increase), no change in the assets of discontinued operations (2002 — $11 million decrease), an increase in liabilities of $22 million (2002 — $16 million), an increase to retained earnings of $102 million (2002 — $66 million) and an increase in foreign currency translation adjustment of $18 million (2002 — $1 million).

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For the period ended December 31, 2003

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)

2. CHANGE IN ACCOUNTING POLICIES AND PRACTICES (continued)

Stock-based Compensation

The Company has early adopted the Canadian accounting standard as outlined in CICA Handbook section 3870, “Stock-based Compensation and Other Stock-based Payments”. As allowed by section 3870, this policy has been adopted prospectively, meaning all prior years have not been restated.

The adoption of the new accounting standard for stock-based compensation resulted in the Company recognizing an expense of $18 million in 2003.

Full Cost Accounting

The Company has early adopted CICA Accounting Guideline AcG – 16, “Oil and Gas Accounting — Full Cost”. The new guideline modifies how the ceiling test is performed and requires cost centers be tested for recoverability using undiscounted future cash flows from proved reserves which are determined by using forward indexed prices. When the carrying amount of a cost center is not recoverable, the cost center would be written down to its fair value. Fair value is estimated using accepted present value techniques which incorporate risks and other uncertainties when determining expected cash flows. There is no impact on the Company’s reported financial results as a result of applying the new Accounting Guideline AcG – 16.

Summary of Changes in Accounting Policies and Practices

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For the period ended December 31, 2003

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)

3. CORPORATE (ACQUISITIONS) AND DISPOSITIONS

On January 31, 2003, the Company acquired the Ecuadorian interests of Vintage Petroleum Inc. (“Vintage”) for net cash consideration of $116 million.

On July 18, 2003, the Company acquired the common shares of Savannah Energy Inc. (“Savannah”) for net cash consideration of $91 million. Savannah’s operations are in Texas, USA.

These purchases were accounted for using the purchase method with the results reflected in the consolidated results of EnCana from the dates of acquisition. These acquisitions were accounted for as follows:

Other dispositions of discontinued operations are disclosed in Note 5.

4. SEGMENTED INFORMATION

The Company has defined its continuing operations into the following segments:

•

Upstream includes the Company’s exploration for, and development and production of, natural gas, natural gas liquids and crude oil and other related activities. The Company’s Upstream operations are primarily located in Canada, the United States, the United Kingdom and Ecuador. International new ventures exploration is mainly focused on opportunities in Africa, South America and the Middle East.

•

Midstream & Marketing includes natural gas storage operations, natural gas liquids processing and power generation operations, as well as marketing activities. These marketing activities include the sale and delivery of produced product and the purchasing of third party product primarily for the optimization of midstream assets, as well as the optimization of transportation arrangements not fully utilized for the Company’s own production.

Midstream & Marketing purchases all of the Company’s North American production. Transactions between business segments are based on market values and eliminated on consolidation. The tables in this note present financial information on an after eliminations basis.

In 2003, the Company redefined its business segments to those described above. All prior periods have been restated to conform to the current presentation.

Operations that have been discontinued are disclosed in Note 5.

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PREPAID IN US$

Interim Report
For the period ended December 31, 2003

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)

4.   SEGMENTED INFORMATION (continued)

Results of Operations (For the three months ended December 31)

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PREPAID IN US$

Interim Report
For the period ended December 31, 2003

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)

4.   SEGMENTED INFORMATION (continued)

Geographic and Product Information (For the three months ended December 31)

Upstream

Midstream & Marketing

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*

Includes transportation cost optimization activity under which the Company purchases and takes delivery of product from others and delivers product to customers under transportation arrangements not utilized for the Company’s own production.

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PREPARED IN US$

Interim Report
For the period ended December 31, 2003

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)

4.   SEGMENTED INFORMATION (continued)

Results of Operations (For the year ended December 31)

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PREPARED IN US$

Interim Report
For the period ended December 31, 2003

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)

4.   SEGMENTED INFORMATION (continued)

Geographic and Product Information (For the year ended December 31)

Upstream

Midstream & Marketing

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*

Includes transportation cost optimization activity under which the Company purchases and takes delivery of product from others and delivers product to customers under transportation arrangements not utilized for the Company’s own production.

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PREPARED IN US$

Interim Report
For the period ended December 31, 2003

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)

4.   SEGMENTED INFORMATION (continued)

Capital Expenditures

Property, Plant and Equipment and Total Assets

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PREPARED IN US$

Interim Report
For the period ended December 31, 2003

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)

5.   DISCONTINUED OPERATIONS

On February 28, 2003, the Company completed the sale of its 10 percent working interest in the Syncrude Joint Venture (“Syncrude”) to Canadian Oil Sands Limited for net cash consideration of C$1,026 million (US$690 million). The Company also granted Canadian Oil Sands Limited an option to purchase its remaining 3.75 percent working interest in Syncrude and a gross-overriding royalty interest. On July 10, 2003, the Company completed the sale of the remaining interest in Syncrude for net cash consideration of C$427 million (US$309 million). This transaction completed the Company’s disposition of its interest in Syncrude and, as a result, these operations have been accounted for as discontinued operations. There was no gain or loss on this sale.

On July 9, 2002, the Company announced that it planned to sell its 70 percent equity investment in the Cold Lake Pipeline System and its 100 percent interest in the Express Pipeline System. Accordingly, these operations have been accounted for as discontinued operations. On January 2, 2003 and January 9, 2003, the Company completed the sale of its interest in the Cold Lake Pipeline System and Express Pipeline System for total consideration of approximately C$1.6 billion (US$1 billion), including assumption of related long-term debt by the purchaser, and recorded an after-tax gain on sale of C$263 million (US$169 million).

On April 24, 2002, the Company adopted formal plans to exit from the Houston-based merchant energy operation, which was included in the Midstream & Marketing segment. Accordingly, these operations have been accounted for as discontinued operations. The wind-down of these operations was substantially completed at December 31, 2002.

The following tables present the effect of the discontinued operations on the Consolidated Financial Statements:

Consolidated Statement of Earnings

Consolidated Statement of Earnings

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*

Reflects only nine months of earnings for 2002 as EnCana did not, at that time, own the operations which have been discontinued.

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For the period ended December 31, 2003

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)

5. DISCONTINUED OPERATIONS (continued)

Consolidated Balance Sheet

6. FOREIGN EXCHANGE (GAIN) LOSS

7. INCOME TAXES

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*

During the second quarter of 2003, both the Canadian federal and Alberta governments substantively enacted income tax rate reductions previously announced. The reduced rates were passed into law during the fourth quarter of 2003.

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For the period ended December 31, 2003

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)

8. LONG-TERM DEBT

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*

Certain of the notes and debentures of the Company were acquired in the business combination with Alberta Energy Company Ltd. on April 5, 2002 and were accounted for at their fair value at the date of acquisition. The difference between the fair value and the principal amount of the debt is being amortized over the remaining life of the outstanding debt acquired, approximately 28 years.

9. ASSET RETIREMENT OBLIGATION

The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the obligation associated with the retirement of oil and gas properties:

The total undiscounted amount of estimated cash flows required to settle the obligation is $3,223 million (2002 — $2,516 million), which has been discounted using a credit-adjusted risk free rate of 5.9 percent. Most of these obligations are not expected to be paid for several years, or decades, in the future and will be funded from general company resources at the time of removal.

10. SHARE CAPITAL

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For the period ended December 31, 2003

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)

10. SHARE CAPITAL (continued)

During the quarter, the Company purchased, for cancellation, 5,215,000 Common Shares (Year-to-date — 23,839,400 Common Shares) for total consideration of approximately C$244 million (US$186 million) (Year-to-date — C$1,184 million; US$868 million). Of the C$1,184 million (US$868 million) paid this year, C$437 million (US$320 million) was charged to share capital, C$102 million (US$80 million) was charged to paid in surplus and C$645 million (US$468 million) was charged to retained earnings.

The Company has stock-based compensation plans that allow employees and directors to purchase Common Shares of the Company. Option exercise prices approximate the market price for the Common Shares on the date the options were issued. Options granted under the plan are generally fully exercisable after three years and expire five years after the grant date. Options granted under previous successor and/or related company replacement plans expire ten years after the grant date.

The following tables summarize the information about options to purchase common shares at December 31, 2003:

As described in Note 2, the Company recorded stock-based compensation expense in the Consolidated Statement of Earnings for stock options granted in 2003 to employees and directors using the fair-value method. Compensation expense has not been recorded in the Consolidated Statement of Earnings related to stock options granted prior to 2003. If the Company had applied the fair-value method to options granted in prior years, pro forma Net Earnings and Net Earnings per Common Share in 2003 would have been $2,326 million; $4.91 per common share — basic; $4.85 per common share — diluted (2002 — $761 million; $1.82 per common share — basic; $1.80 per common share — diluted).

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For the period ended December 31, 2003

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)

10. SHARE CAPITAL (continued)

The fair value of each option granted is estimated on the date of grant using the Black-Scholes option-pricing model with weighted average assumptions for grants as follows:

11. PER SHARE AMOUNTS

The following table summarizes the common shares used in calculating net earnings per common share:

12. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

     Unrecognized gains (losses) on risk management activities were as follows:

Information with respect to power, foreign currency risk and interest rate risk contracts in place at December 31, 2002, is disclosed in Note 19 to the Company’s annual audited Consolidated Financial Statements. No significant new contracts have been entered into as at December 31, 2003.

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For the period ended December 31, 2003

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)

12. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)

Natural Gas

At December 31, 2003, the Company’s gas risk management activities had an unrecognized gain of $57 million. The contracts were as follows:

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(1)

The gas marketing activities are part of the daily ongoing operations of the Company’s proprietary production management.

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For the period ended December 31, 2003

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)

12. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)

Crude Oil

As at December 31, 2003, the Company’s oil risk management activities had an unrecognized loss of $279 million. The contracts were as follows:

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(1)

The crude oil marketing activities are part of the daily ongoing operations of the Company’s proprietary production management.

Gas Storage Optimization

As part of the Company’s gas storage optimization program, the Company has entered into financial instruments at various locations and terms over the next 9 months to manage the price volatility of the corresponding physical transactions and inventories.

As at December 31, 2003, the unrecognized loss on gas storage optimization risk management activities was $25 million, which was as follows:

At December 31, 2003, the unrecognized loss on physical contracts of $2 million was more than offset by unrealized gains on physical inventory in storage.

13. RECLASSIFICATION

Certain information provided for prior periods has been reclassified to conform to the presentation adopted in 2003.

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Interim Consolidated Financial Statements
(unaudited)
For the period ended December 31, 2003

EnCana Corporation

CANADIAN DOLLARS

Notice to Reader

These unaudited Interim Consolidated Financial Statements for the period ended December 31, 2003 have been provided for this transition period as EnCana moves to U.S. dollar reporting.

 

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PREPARED IN C$

Interim Report
For the period ended December 31, 2003

EnCana Corporation

CONSOLIDATED STATEMENT OF EARNINGS

CONSOLIDATED STATEMENT OF RETAINED EARNINGS

See accompanying Notes to Consolidated Financial Statements.

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PREPARED IN C$

Interim Report
For the period ended December 31, 2003

EnCana Corporation

CONSOLIDATED BALANCE SHEET

See accompanying Notes to Consolidated Financial Statements.

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PREPARED IN C$

Interim Report
For the period ended December 31, 2003

EnCana Corporation

CONSOLIDATED STATEMENT OF CASH FLOWS

See accompanying Notes to Consolidated Financial Statements.

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PREPARED IN C$

Interim Report
For the period ended December 31, 2003

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in C$ millions unless otherwise specified)

1.

BASIS OF PRESENTATION

The interim Consolidated Financial Statements include the accounts of EnCana Corporation and its subsidiaries (the “Company”), and are presented in accordance with Canadian generally accepted accounting principles. The Company is in the business of exploration, production and marketing of natural gas, natural gas liquids and crude oil, as well as natural gas storage operations, natural gas liquids processing and power generation operations.

The interim Consolidated Financial Statements have been prepared following the same accounting policies and methods of computation as the annual audited Consolidated Financial Statements for the year ended December 31, 2002, except as noted below. The disclosures provided below are incremental to those included with the annual audited Consolidated Financial Statements. The interim Consolidated Financial Statements should be read in conjunction with the annual audited Consolidated Financial Statements and the notes thereto for the year ended December 31, 2002.

2.

CHANGE IN ACCOUNTING POLICIES AND PRACTICES

Preferred Securities

The Company has retroactively adopted the amendments made to Canadian Institute of Chartered Accountants (“CICA”) Handbook section 3860, “Financial Instruments - Disclosure and Presentation”. As a result, all of the preferred securities issued by the Company are now recorded as a liability and included in long-term debt. The effect on the Company’s Consolidated Statement of Earnings was to increase net earnings by $9 million (2002 — $3 million decrease). The effect to the Company’s Consolidated Balance Sheet is to increase current portion of long-term debt by $126 million, increase long-term debt by $415 million and decrease shareholders’ equity by $541 million (2002 — $583 million increase to long-term debt; $457 million decrease to preferred securities of subsidiary; $126 million decrease to shareholders’ equity).

Asset Retirement Obligations

The Company has retroactively early adopted the Canadian accounting standard outlined in CICA Handbook section 3110, “Asset Retirement Obligations”. This new section requires liability recognition for retirement obligations associated with tangible long-lived assets, such as producing well sites, offshore production platforms and natural gas processing plants. The obligations included within the scope of this section are those for which a company faces a legal obligation for settlement or has made promissory estoppel. The initial measurement of the asset retirement obligation is at fair value, defined as “the price that an entity would have to pay a willing third party of comparable credit standing to assume the liability in a current transaction other than in a forced or liquidation sale.”

The asset retirement cost, equal to the fair value of the retirement obligation, is capitalized as part of the cost of the related long-lived asset and allocated to expense on a basis consistent with depreciation, depletion and amortization.

The Company previously estimated costs of dismantlement, removal, site reclamation, and other similar activities and recorded them into earnings on a unit-of production basis over the remaining life of the proved reserves and accumulated a liability on the Consolidated Balance Sheet. Upon adoption, all prior periods have been restated for the change in accounting policy. The change results in an increase in net earnings of $50 million for the year ended December 31, 2003 (2002 — $54 million increase). The effect of this change on the December 31, 2003 Consolidated Balance Sheet is an increase in property, plant and equipment of $183 million (2002 — $148 million increase), no change in the assets of discontinued operations (2002 — $18 million decrease), an increase in liabilities of $30 million (2002 — $27 million) and an increase to retained earnings of $153 million (2002 — $103 million).

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PREPARED IN C$

Interim Report
For the period ended December 31, 2003

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in C$ millions unless otherwise specified)

2.

CHANGE IN ACCOUNTING POLICIES AND PRACTICES (continued)

“Stock-based Compensation

The Company has early adopted the Canadian accounting standard as outlined in CICA Handbook section 3870, “Stock-based Compensation and Other Stock-based Payments”. As allowed by section 3870, this policy has been adopted prospectively, meaning all prior years have not been restated.

The adoption of the new accounting standard for stock-based compensation resulted in the Company recognizing an expense of $24 million in 2003.

Full Cost Accounting

The Company has early adopted CICA Accounting Guideline AcG — 16, “Oil and Gas Accounting — Full Cost”. The new guideline modifies how the ceiling test is performed and requires cost centers be tested for recoverability using undiscounted future cash flows from proved reserves which are determined by using forward indexed prices. When the carrying amount of a cost center is not recoverable, the cost center would be written down to its fair value. Fair value is estimated using accepted present value techniques which incorporate risks and other uncertainties when determining expected cash flows. There is no impact on the Company’s reported financial results as a result of applying the new Accounting Guideline AcG — 16.

Summary of Changes in Accounting Policies and Practices

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Table of Contents

PREPARED IN C$

Interim Report
For the period ended December 31, 2003

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in C$ millions unless otherwise specified)

3.

CORPORATE (ACQUISITIONS) AND DISPOSITIONS

On January 31, 2003, the Company acquired the Ecuadorian interests of Vintage Petroleum Inc. (“Vintage”) for net cash consideration of $179 million (US$116 million).

On July 18, 2003, the Company acquired the common shares of Savannah Energy Inc. (“Savannah”) for net cash consideration of $128 million (US$91 million). Savannah’s operations are in Texas, USA.

These purchases were accounted for using the purchase method with the results reflected in the consolidated results of EnCana from the dates of acquisition. These acquisitions were accounted for as follows:

Other dispositions of discontinued operations are disclosed in Note 5.

4.

SEGMENTED INFORMATION

The Company has defined its continuing operations into the following segments:

•

Upstream includes the Company’s exploration for, and development and production of, natural gas, natural gas liquids and crude oil and other related activities. The Company’s Upstream operations are primarily located in Canada, the United States, the United Kingdom and Ecuador. International new ventures exploration is mainly focused on opportunities in Africa, South America and the Middle East.

•

Midstream & Marketing includes natural gas storage operations, natural gas liquids processing and power generation operations, as well as marketing activities. These marketing activities include the sale and delivery of produced product and the purchasing of third party product primarily for the optimization of midstream assets, as well as the optimization of transportation arrangements not fully utilized for the Company’s own production.

Midstream & Marketing purchases all of the Company’s North American production. Transactions between business segments are based on market values and eliminated on consolidation. The tables in this note present financial information on an after eliminations basis.

In 2003, the Company redefined its business segments to those described above. All prior periods have been restated to conform to the current presentation.

Operations that have been discontinued are disclosed in Note 5.

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Table of Contents

PREPARED IN C$

Interim Report
For the period ended December 31, 2003

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in C$ millions unless otherwise specified)

4.

SEGMENTED INFORMATION (continued)

Results of Operations (For the three months ended December 31)

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Table of Contents

PREPARED IN C$

Interim Report
For the period ended December 31, 2003

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in C$ millions unless otherwise specified)

4.

SEGMENTED INFORMATION (continued)

Geographic and Product Information (For the three months ended December 31)

Upstream

Midstream & Marketing

*

Includes transportation cost optimization activity under which the Company purchases and takes delivery of product from others and delivers product to customers under transportation arrangements not utilized for the Company’s own production.

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Table of Contents

PREPARED IN C$

Interim Report
For the period ended December 31, 2003

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in C$ millions unless otherwise specified)

4.

SEGMENTED INFORMATION (continued)

Results of Operations (For the year ended December 31)

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Table of Contents

PREPARED IN C$

Interim Report
For the period ended December 31, 2003

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in C$ millions unless otherwise specified)

4.

SEGMENTED INFORMATION (continued)

Geographic and Product Information (For the year ended December 31)

Upstream

Midstream & Marketing Total Midstream

*

Includes transportation cost optimization activity under which the Company purchases and takes delivery of product from others and delivers product to customers under transportation arrangements not utilized for the Company’s own production.

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Table of Contents

Interim Report
For the period ended December 31, 2003

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in C$ millions unless otherwise specified)

4.

SEGMENTED INFORMATION (continued)

Capital Expenditures

Property, Plant and Equipment and Total Assets

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Table of Contents

PREPARED IN C$

Interim Report
For the period ended December 31, 2003

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in C$ millions unless otherwise specified)

5.

DISCONTINUED OPERATIONS

On February 28, 2003, the Company completed the sale of its 10 percent working interest in the Syncrude Joint Venture (“Syncrude”) to Canadian Oil Sands Limited for net cash consideration of $1,026 million. The Company also granted Canadian Oil Sands Limited an option to purchase its remaining 3.75 percent working interest in Syncrude and a gross-overriding royalty interest. On July 10, 2003, the Company completed the sale of the remaining interest in Syncrude for net cash consideration of $427 million. This transaction completed the Company’s disposition of its interest in Syncrude and, as a result, these operations have been accounted for as discontinued operations. There was no gain or loss on this sale.

On July 9, 2002, the Company announced that it planned to sell its 70 percent equity investment in the Cold Lake Pipeline System and its 100 percent interest in the Express Pipeline System. Accordingly, these operations have been accounted for as discontinued operations. On January 2, 2003 and January 9, 2003, the Company completed the sale of its interest in the Cold Lake Pipeline System and Express Pipeline System for total consideration of approximately $1.6 billion, including assumption of related long-term debt by the purchaser, and recorded an after-tax gain on sale of $263 million.

On April 24, 2002, the Company adopted formal plans to exit from the Houston-based merchant energy operation, which was included in the Midstream & Marketing segment. Accordingly, these operations have been accounted for as discontinued operations. The wind-down of these operations was substantially completed at December 31, 2002.

The following tables present the effect of the discontinued operations on the Consolidated Financial Statements:

Consolidated Statement of Earnings

Consolidated Statement of Earnings

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*

Reflects only nine months of earnings for 2002 as EnCana did not, at that time, own the operations which have been discontinued.

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Table of Contents

PREPARED IN C$

Interim Report
For the period ended December 31, 2003

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in C$ millions unless otherwise specified)

5. DISCONTINUED OPERATIONS (continued)

Consolidated Balance Sheet

6. FOREIGN EXCHANGE (GAIN) LOSS

7. INCOME TAXES

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*

During the second quarter of 2003, both the Canadian federal and Alberta governments substantively enacted income tax rate reductions previously announced. The reduced rates were passed into law during the fourth quarter of 2003.

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Table of Contents

PREPARED IN C$

Interim Report
For the period ended December 31, 2003

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in C$ millions unless otherwise specified)

8. LONG-TERM DEBT

* Certain of the notes and debentures of the Company were acquired in the business combination with Alberta Energy Company Ltd. on April 5, 2002 and were accounted for at their fair value at the date of acquisition. The difference between the fair value and the principal amount of the debt is being amortized over the remaining life of the outstanding debt acquired, approximately 28 years.

9. ASSET RETIREMENT OBLIGATION

The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the obligation associated with the retirement of oil and gas properties:

The total undiscounted amount of estimated cash flows required to settle the obligation is $4,165 million (2002 — $3,975 million), which has been discounted using a credit-adjusted risk free rate of 5.9 percent. Most of these obligations are not expected to be paid for several years, or decades, in the future and will be funded from general company resources at the time of removal.

10. SHARE CAPITAL

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PREPARED IN C$

Interim Report
For the period ended December 31, 2003

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in C$ millions unless otherwise specified)

10. SHARE CAPITAL (continued)

During the quarter, the Company purchased, for cancellation, 5,215,000 Common Shares (Year-to-date — 23,839,400 Common Shares) for total consideration of approximately $244 million (Year-to-date — $1,184 million). Of the $1,184 million paid this year, $437 million was charged to share capital, $102 million was charged to paid in surplus and $645 million was charged to retained earnings.

The Company has stock-based compensation plans that allow employees and directors to purchase Common Shares of the Company. Option exercise prices approximate the market price for the Common Shares on the date the options were issued. Options granted under the plan are generally fully exercisable after three years and expire five years after the grant date. Options granted under previous successor and/or related company replacement plans expire ten years after the grant date.

The following tables summarize the information about options to purchase common shares at December 31, 2003:

As described in Note 2, the Company recorded stock-based compensation expense in the Consolidated Statement of Earnings for stock options granted in 2003 to employees and directors using the fair-value method. Compensation expense has not been recorded in the Consolidated Statement of Earnings related to stock options granted prior to 2003. If the Company had applied the fair-value method to options granted in prior years, pro forma Net Earnings and Net Earnings per Common Share in 2003 would have been $3,226 million; $6.80 per common share — basic and $6.73 per common share — diluted (2002 — $1,195 million; $2.86 per common share — basic; $2.83 per common share — diluted).

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Table of Contents

PREPARED IN C$

Interim Report
For the period ended December 31, 2003

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in C$ millions unless otherwise specified)

10. SHARE CAPITAL (continued)

The fair value of each option granted is estimated on the date of grant using the Black-Scholes option-pricing model with weighted average assumptions for grants as follows:

11. PER SHARE AMOUNTS

The following table summarizes the common shares used in calculating net earnings per common share:

12. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Unrecognized gains (losses) on risk management activities were as follows:

Information with respect to power, foreign currency risk and interest rate risk contracts in place at December 31, 2002, is disclosed in Note 19 to the Company’s annual audited Consolidated Financial Statements. No significant new contracts have been entered into as at December 31, 2003.

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PREPARED IN C$

Interim Report
For the period ended December 31, 2003

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in C$ millions unless otherwise specified)

12. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)

Natural Gas

At December 31, 2003, the Company’s gas risk management activities had an unrecognized gain of $76 million. The contracts were as follows:

(1)

The gas marketing activities are part of the daily ongoing operations of the Company’s proprietary production management.

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PREPARED IN C$

Interim Report
For the period ended December 31, 2003

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in C$ millions unless otherwise specified)

12. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)

Crude Oil

As at December 31, 2003, the Company’s oil risk management activities had an unrecognized loss of $361 million. The contracts were as follows:

(1)

The crude oil marketing activities are part of the daily ongoing operations of the Company’s proprietary production management.

Gas Storage Optimization

As part of the Company’s gas storage optimization program, the Company has entered into financial instruments at various locations and terms over the next 9 months to manage the price volatility of the corresponding physical transactions and inventories.

As at December 31, 2003, the unrecognized loss on gas storage optimization risk management activities was $32 million, which was as follows:

At December 31, 2003, the unrecognized loss on physical contracts of $3 million was more than offset by unrealized gains on physical inventory in storage.

13. RECLASSIFICATION

Certain information provided for prior periods has been reclassified to conform to the presentation adopted in 2003.

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