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, Feb. 26 /CNW/ - 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.

-------------------------------------------------------------------------
-------------------------------------------------------------------------
2003 financial and operating highlights
-------------------------------------------------------------------------
U.S. dollars Canadian dollars
& protocols & protocols
Earnings per share diluted $4.92, up 184% $6.83, up 152%
Cash flow per share diluted $9.30, up 68% $13.05, up 50%
Natural gas sales 2.57 Bcf/d, up 8% 3.0 Bcf/d, up 9%
Oil and NGLs sales 222,500 bbls/d, up 13% 259,800 bbls/d,
up 12%
Total BOE sales 650,200 BOE/d, up 9% 760,700 BOE/d,
up 10%
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
-------------------------------------------------------------------------
Fourth quarter financial and operating highlights
-------------------------------------------------------------------------
U.S. dollars Canadian dollars
& protocols & protocols
Earnings per share diluted $0.91, up 57% $1.15, up 25%
Cash flow per share diluted $2.69, up 39% $3.55, up 17%
Natural gas sales 2.68 Bcf/d, up 4% 3.1 Bcf/d, up 3%
Oil and NGLs sales 266,900 bbls/d, up 32% 313,800 bbls/d,
up 33%
Total BOE sales 713,900 BOE/d, up 13% 833,800 BOE/d,
up 12%
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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.
"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 of 2002.
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.
"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.


Consolidated EnCana Highlights
------------------------------
US$ and U.S. protocols
----------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Financial Highlights
(as at and for
the period ended
December 31)
(US$ millions, Pro
except per Q4 Q4 % forma(3) %
share amounts) 2003 2002 Change 2003 2002 Change
-------------------------------------------------------------------------
Revenues, net of
royalties 2,850 2,116 + 35 10,216 6,967 + 47

Cash flow 1,254 935 + 34 4,459 2,664 + 67
Per share
- basic 2.71 1.96 + 38 9.41 5.62 + 67
Per share
- diluted 2.69 1.94 + 39 9.30 5.54 + 68

Net earnings 426 282 + 51 2,360 833 + 183
Per share
- basic(1) 0.92 0.59 + 56 4.98 1.76 + 183
Per share
- diluted 0.91 0.58 + 57 4.92 1.73 + 184

Earnings from
continuing
operations,
excluding foreign
exchange
translation of
U.S. dollar debt
issued in Canada
(after tax) and tax
rate change gain 316 239 + 32 1,375 697 + 97
Per share
- diluted 0.68 0.49 + 39 2.87 1.45 + 98

Net capital
investment 1,381 778 + 78 3,422 3,234 + 6

Total assets 24,110 19,912 + 21
Long-term debt 6,088 5,051 + 21
Shareholders'
equity 11,278 8,718 + 29

Debt-to-capitalization ratio
(adjusted for working capital) 34% 31%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Common shares (millions)
Outstanding at
December 31 460.6 478.9 - 3.8 460.6 478.9 - 3.8
Weighted average
(diluted) 465.9 482.6 - 3.5 479.7 481.1 - 0.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Operating Highlights Pro
(for the period Q4 Q4 % forma(3) %
ended Dec. 31) 2003 2002 Change 2003 2002 Change
-------------------------------------------------------------------------
(After royalties)
Natural Gas
(MMcf/d)
Production 2,682 2,467 + 9 2,536 2,358 + 8
Withdrawal
(Injection) - 117 30 22
-------------------------------------------------------------------------
Total natural gas
sales (MMcf/d) 2,682 2,584 + 4 2,566 2,380 + 8
-------------------------------------------------------------------------
Oil and NGLs
sales (bbls/d)
North America 174,471 158,358 + 10 165,895 150,484 + 10
International 92,419 43,686 + 112 56,649 47,119 + 20
-------------------------------------------------------------------------
Total liquids
sales (bbls/d) 266,890 202,044 + 32 222,544 197,603 + 13
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total sales
(BOE/d)(2) 713,890 632,711 + 13 650,211 594,270 + 9
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(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
-------------------------------------------------------

-------------------------------------------------------------------------
-------------------------------------------------------------------------
2003 Prices Pro
Q4 Q4 % forma(3) %
2003 2002 Change 2003 2002 Change
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Natural Gas (US$/Mcf)
Including hedging
Canada 4.66 3.54 + 32 4.74 2.83 + 67
U.S. 4.58 3.82 + 20 4.90 3.12 + 57
Excluding hedging
Canada 4.41 3.60 + 23 4.87 2.78 + 75
U.S. 4.71 3.48 + 35 4.88 2.86 + 71
-------------------------------------------------------------------------
Total North American
gas (US$/Mcf)
Including hedging 4.65 3.60 + 29 4.77 2.88 + 66
Excluding hedging 4.49 3.58 + 25 4.87 2.80 + 74
-------------------------------------------------------------------------
Oil and NGLs (US$/bbl)
Including hedging
North American oil
Light/medium 21.79 23.48 - 7 22.54 21.47 + 5
Heavy 14.62 16.54 - 12 15.70 16.85 - 7
International oil
Ecuador 23.57 24.02 - 2 24.21 21.24 + 14
U.K. 27.05 25.73 + 5 28.11 24.70 + 14
Natural gas liquids 25.77 23.06 + 12 25.33 19.42 + 30

Excluding hedging
North American oil
Light/medium 25.53 24.39 + 5 26.61 22.28 + 19
Heavy 18.43 17.38 + 6 19.61 17.35 + 13
International oil
Ecuador 23.57 24.02 - 2 24.21 21.24 + 14
U.K. 27.05 25.73 + 5 28.11 24.76 + 14
Natural gas liquids 25.77 23.06 + 12 25.33 19.42 + 30
-------------------------------------------------------------------------
Total oil and
NGLs (US$/bbl)
Including hedging 20.36 20.94 - 3 20.71 19.71 + 5
Excluding hedging 22.51 21.51 + 5 23.25 20.13 + 15
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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
---------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Financial Highlights
(as at and for
the period ended
December 31)
(C$ millions, Pro
except per Q4 Q4 % forma(3) %
share amounts) 2003 2002 Change 2003 2002 Change
-------------------------------------------------------------------------
Revenues, net of
royalties and
production and
mineral taxes 3,674 3,258 + 13 14,052 10,747 + 31
Cash flow
Per share
- basic 1,652 1,464 + 13 6,262 4,187 + 50
Per share
- diluted 3.57 3.06 + 17 13.21 8.84 + 49
3.55 3.03 + 17 13.05 8.70 + 50
Net earnings
Per share
- basic(4) 534 443 + 21 3,274 1,305 + 151
Per share
- diluted 1.16 0.93 + 25 6.91 2.75 + 151
1.15 0.92 + 25 6.83 2.71 + 152
Earnings from
continuing
operations,
excluding foreign
exchange
translation of
U.S. dollar debt
issued in Canada
(after tax) and
tax rate
change gain 410 372 + 10 1,934 1,086 + 78
Per share
- diluted 0.89 0.77 + 16 4.03 2.26 + 78

Net capital
investment 1,827 1,223 + 49 4,615 5,074 - 9

Total assets 31,157 31,452 - 1
Long-term debt 7,866 7,978 - 1
Shareholders' equity 14,575 13,771 + 6

Debt-to-capitalization ratio
(adjusted for working capital) 34% 31%
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Operating Highlights Pro
(for the period Q4 Q4 % forma(3) %
ended Dec. 31) 2003 2002 Change 2003 2002 Change
-------------------------------------------------------------------------
(Before royalties)
Natural Gas (MMcf/d)
Production 3,120 2,888 + 8 2,970 2,730 + 9
Withdrawal
(Injection) - 149 35 28
-------------------------------------------------------------------------
Total natural gas
sales (MMcf/d) 3,120 3,037 + 3 3,005 2,758 + 9
-------------------------------------------------------------------------

Oil and NGLs
sales (bbls/d)
North America 195,129 179,067 + 9 187,196 169,722 + 10
International 118,705 57,720 + 106 72,651 61,609 + 18
-------------------------------------------------------------------------
Total liquids
sales (bbls/d) 313,834 236,787 + 33 259,847 231,331 + 12
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total sales
(BOE/d)(5) 833,834 742,954 + 12 760,680 690,998 + 10
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(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
------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2003 Prices Pro
Q4 Q4 % forma(3) %
2003 2002 Change 2003 2002 Change
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Natural Gas (C$/Mcf)
Including hedging
Canada 5.54 5.09 + 9 6.16 4.05 + 52
U.S. 5.41 5.16 + 5 6.32 4.12 + 53
Excluding hedging
Canada 5.25 5.17 + 2 6.34 3.98 + 59
U.S. 5.54 4.74 + 17 6.28 3.79 + 66
-------------------------------------------------------------------------
Total North American
gas (C$/Mcf)
Including hedging 5.51 5.11 + 8 6.19 4.07 + 52
Excluding hedging 5.33 5.08 + 5 6.32 3.96 + 60
-------------------------------------------------------------------------
Oil and NGLs (C$/bbl)
Including hedging
North American oil
Light/medium 27.37 35.10 - 22 30.12 32.40 - 7
Heavy 17.69 24.63 - 28 20.79 25.34 - 18
International oil
Ecuador 28.16 35.38 - 20 31.13 31.30 - 1
U.K. 33.36 37.99 - 12 36.50 36.14 + 1
Natural gas liquids 33.83 36.15 - 6 35.49 30.44 + 17

Excluding hedging
North American oil
Light/medium 31.84 36.36 - 12 35.33 33.53 + 5
Heavy 22.21 25.81 - 14 25.74 26.04 - 1
International oil
Ecuador 28.16 35.38 - 20 31.13 31.30 - 1
U.K. 33.36 37.99 - 12 36.50 36.23 + 1
Natural gas liquids 33.83 36.15 - 6 35.49 30.44 + 17
-------------------------------------------------------------------------
Total oil and
NGLs (C$/bbl)
Including hedging 25.20 31.57 - 20 27.65 29.70 - 7
Excluding hedging 27.60 32.33 - 15 30.73 30.26 + 2
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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.

---------------------------------------------------------
---------------------------------------------------------
EnCana 2003 capital investment
---------------------------------------------------------
Upstream (US$ million)
Offset production declines 1,900
2003 and part of 2004 growth 1,500
Exploration and long-term development 552
Cutbank Ridge land purchase 270
--------
Upstream total 4,222
---------------------------------------------------------
Midstream, marketing and corporate 280
--------
Core capital total 4,502
---------------------------------------------------------
Other
Leased equipment purchases 262
Minor corporate acquisitions 207
Upstream asset acquisitions 351
--------
Other total 820
---------------------------------------------------------
Divestitures
Express and Cold Lake pipelines(*) (1,024)
Syncrude (946)
Upstream minor properties (301)
Minor corporate divestitures (14)
---------------------------------------------------------
Divestitures total (2,285)
---------------------------------------------------------
---------------------------------------------------------
Net capital investment 3,037
---------------------------------------------------------
---------------------------------------------------------

(*) 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.
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.

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.

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.
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 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 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.



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



EnCana Corporation



U.S. DOLLARS


Prepared in US$

Interim Report
For the period ended December 31, 2003

EnCana Corporation
CONSOLIDATED STATEMENT OF EARNINGS


December 31
-------------------------------------------
Three Months Ended Year Ended
(unaudited) (US$ millions, -------------------------------------------
except per share amounts) 2003 2002 2003 2002
-------------------------------------------------------------------------
(restated (restated
- Note 2) - Note 2)

REVENUES,
NET OF ROYALTIES (Note 4) $ 2,850 $ 2,116 $ 10,216 $ 6,276
-------------------------------------------------------------------------
EXPENSES (Note 4)
Production and
mineral taxes 58 41 189 119
Transportation
and selling 170 121 545 364
Operating 337 258 1,297 813
Purchased product 1,049 720 3,455 2,200
Depreciation,
depletion and
amortization 725 452 2,222 1,304
Administrative 52 48 173 119
Interest, net 85 119 287 290
Accretion of asset
retirement
obligation (Note 9) 4 4 19 13
Foreign exchange
(gain) loss (Note 6) (165) 3 (601) (14)
Stock-based
compensation (Note 2) 6 - 18 -
Gain on corporate
disposition - (33) - (33)
-------------------------------------------------------------------------
2,321 1,733 7,604 5,175
-------------------------------------------------------------------------
NET EARNINGS BEFORE
INCOME TAX 529 383 2,612 1,101
Income tax
expense (Note 7) 103 135 445 366
-------------------------------------------------------------------------
NET EARNINGS FROM
CONTINUING OPERATIONS 426 248 2,167 735
NET EARNINGS FROM
DISCONTINUED
OPERATIONS (Note 5) - 34 193 77
-------------------------------------------------------------------------
NET EARNINGS $ 426 $ 282 $ 2,360 $ 812
-------------------------------------------------------------------------
-------------------------------------------------------------------------

NET EARNINGS FROM
CONTINUING OPERATIONS
PER COMMON SHARE (Note 11)
Basic $ 0.92 $ 0.52 $ 4.57 $ 1.76
Diluted $ 0.91 $ 0.51 $ 4.52 $ 1.74
-------------------------------------------------------------------------
-------------------------------------------------------------------------

NET EARNINGS PER
COMMON SHARE (Note 11)
Basic $ 0.92 $ 0.59 $ 4.98 $ 1.94
Diluted $ 0.91 $ 0.58 $ 4.92 $ 1.92
-------------------------------------------------------------------------
-------------------------------------------------------------------------



CONSOLIDATED STATEMENT OF RETAINED EARNINGS

Year Ended December 31
-----------------------
(unaudited) (US$ millions) 2003 2002
-------------------------------------------------------------------------
(restated
- Note 2)
RETAINED EARNINGS, BEGINNING OF YEAR
As previously reported $ 3,457 $ 2,787
Retroactive adjustment for changes
in accounting policies (Note 2) 66 32
-------------------------------------------------------------------------
As restated 3,523 2,819
Net Earnings 2,360 812
Dividends on Common Shares (139) (108)
Charges for Normal Course Issuer Bid (Note 10) (468) -
-------------------------------------------------------------------------
RETAINED EARNINGS, END OF YEAR $ 5,276 $ 3,523
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.



EnCana Corporation
CONSOLIDATED BALANCE SHEET

As at As at
December December
(unaudited) (US$ millions) 31, 2003 31, 2002
-------------------------------------------------------------------------
(restated
- Note 2)
ASSETS
Current Assets
Cash and cash equivalents $ 148 $ 116
Accounts receivable and accrued revenues 1,367 1,258
Inventories 573 281
Assets of discontinued operations (Note 5) - 2,155
-------------------------------------------------------------------------
2,088 3,810
Property, Plant and Equipment, net (Note 4) 19,545 14,247
Investments and Other Assets 566 292
Goodwill 1,911 1,563
-------------------------------------------------------------------------
(Note 4) $ 24,110 $ 19,912
-------------------------------------------------------------------------
-------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable and
accrued liabilities $ 1,579 $ 1,445
Income tax payable 65 13
Current portion of long-term debt (Note 8) 287 134
Liabilities of discontinued
operations (Note 5) - 1,100
-------------------------------------------------------------------------
1,931 2,692
Long-Term Debt (Note 8) 6,088 5,051
Other Liabilities 21 54
Asset Retirement Obligation (Note 9) 430 309
Future Income Taxes 4,362 3,088
-------------------------------------------------------------------------
12,832 11,194
-------------------------------------------------------------------------
Shareholders' Equity
Share capital (Note 10) 5,305 5,511
Share options, net 55 84
Paid in surplus 18 51
Retained earnings 5,276 3,523
Foreign currency translation adjustment 624 (451)
-------------------------------------------------------------------------
11,278 8,718
-------------------------------------------------------------------------
$ 24,110 $ 19,912
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.



EnCana Corporation
CONSOLIDATED STATEMENT OF CASH FLOWS

December 31
-------------------------------------------
Three Months Ended Year Ended
-------------------------------------------
(unaudited) (US$ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------
(restated (restated
- Note 2) - Note 2)

OPERATING ACTIVITIES
Net earnings from
continuing operations $ 426 $ 248 $ 2,167 $ 735
Depreciation, depletion
and amortization 725 452 2,222 1,304
Future income
taxes (Note 7) 176 242 501 404
Unrealized foreign
exchange (gain) (141) (8) (545) (23)
Accretion of asset
retirement
obligation 4 4 19 13
Other 27 (64) 56 (166)
-------------------------------------------------------------------------
Cash flow from
continuing operations 1,217 874 4,420 2,267
Cash flow from
discontinued
operations 37 61 39 152
-------------------------------------------------------------------------
Cash flow 1,254 935 4,459 2,419
Net change in other
assets and liabilities (2) (1) (84) (17)
Net change in non-cash
working capital from
continuing operations (301) (346) (81) (853)
Net change in non-cash
working capital
from discontinued
operations (37) 17 17 64
-------------------------------------------------------------------------
914 605 4,311 1,613
-------------------------------------------------------------------------

INVESTING ACTIVITIES
Capital
expenditures (Note 4) (1,677) (900) (5,115) (3,021)
Proceeds on
disposal of
property, plant
and equipment 282 121 301 363
Corporate
(acquisitions)
and dispositions (Note 3) 14 60 (193) 60
Business
combination with
Alberta Energy
Company Ltd. - - - (80)
Equity investments (3) - (161) -
Net change in
investments
and other 5 32 (63) 43
Net change in
non-cash working
capital from
continuing
operations 29 293 (83) 186
Discontinued
operations (Note 5) - (59) 1,585 (146)
-------------------------------------------------------------------------
(1,350) (453) (3,729) (2,595)
-------------------------------------------------------------------------

FINANCING ACTIVITIES
Issuance of
long-term debt 526 760 1,609 1,506
Repayment of
long-term debt - (1,297) (963) (1,206)
Issuance of
common shares (Note 10) 19 27 114 88
Purchase of
common shares (Note 10) (186) - (868) -
Dividends on
common shares (36) (30) (139) (108)
Other (8) (36) (13) (53)
Net change in
non-cash working
capital from
continuing
operations 22 1 2 (7)
Discontinued
operations - 277 (282) 271
-------------------------------------------------------------------------
337 (298) (540) 491
-------------------------------------------------------------------------

DEDUCT: FOREIGN
EXCHANGE LOSS
(GAIN) ON CASH AND
CASH EQUIVALENTS
HELD IN FOREIGN
CURRENCY 1 - 10 (2)
-------------------------------------------------------------------------

(DECREASE) INCREASE IN
CASH AND CASH
EQUIVALENTS (100) (146) 32 (489)
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD 248 262 116 605
-------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS,
END OF PERIOD $ 148 $ 116 $ 148 $ 116
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.



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).

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 centres 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 centre 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


2003 2002
------------------------------------------------------
As As As As
(US$ millions) Reported Change Restated Reported Change Restated
-------------------------------------------------------------------------

Consolidated
Balance Sheet
Assets
Assets of
discontinued
operations $ - $ - $ - $ 2,166 $ (11) $ 2,155
Property, plant
and equipment,
net 19,403 142 19,545 14,153 94 14,247

Liabilities
Liabilities of
discontinued
operations $ - $ - $ - $ 1,113 $ (13) $ 1,100
Current portion
of long-term
debt 190 97 287 134 - 134
Long-term debt 5,767 321 6,088 4,682 369 5,051
Preferred
securities of
subsidiary - - - 289 (289) -
Other
liabilities &
asset retirement
obligation 473 (22) 451 357 6 363
Future
income taxes 4,318 44 4,362 3,065 23 3,088

Shareholders'
Equity
Preferred
securities $ 418 $ (418) $ - $ 80 $ (80) $ -
Paid in surplus - 18 18 51 - 51
Retained
earnings 5,192 84 5,276 3,457 66 3,523
Foreign currency
translation
adjustment 606 18 624 (452) 1 (451)

Consolidated
Statement of
Earnings
Net Earnings $ 2,336 $ 24 $ 2,360 $ 780 $ 32 $ 812

Net Earnings per
Common Share
- Diluted $ 4.88 $ 0.04 $ 4.92 $ 1.84 $ 0.08 $ 1.92
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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:


(US$ millions) Vintage Savannah
-------------------------------------------------------------------------
Working Capital $ 1 $ 1
Property, Plant and Equipment, net 126 110
Future Income Taxes (11) (20)
-------------------------------------------------------------------------
$ 116 $ 91
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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.


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

Midstream &
Upstream Marketing
-------------------------------------------
(US$ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Revenues, net of royalties $ 1,676 $ 1,264 $ 1,174 $ 845

Expenses
Production and mineral taxes 58 41 - -
Transportation and selling 159 100 11 21
Operating 254 194 83 64
Purchased product - - 1,049 720
Depreciation, depletion
and amortization 689 429 27 10
-------------------------------------------------------------------------
Segment Income $ 516 $ 500 $ 4 $ 30
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Corporate Consolidated
-------------------------------------------
2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Revenues, net of royalties $ - $ 7 $ 2,850 $ 2,116

Expenses
Production and mineral taxes - - 58 41
Transportation and selling - - 170 121
Operating - - 337 258
Purchased product - - 1,049 720
Depreciation, depletion
and amortization 9 13 725 452
-------------------------------------------------------------------------
Segment Income $ (9) $ (6) 511 524
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Administrative 52 48
Interest, net 85 119
Accretion of asset
retirement obligation 4 4
Foreign exchange (gain) loss (165) 3
Stock-based compensation 6 -
Gain on corporate disposition - (33)
-------------------------------------------------------------------------
(18) 141
-------------------------------------------------------------------------
Net Earnings Before Income Tax 529 383
Income tax expense 103 135
-------------------------------------------------------------------------
Net Earnings from Continuing Operations $ 426 $ 248
-------------------------------------------------------------------------
-------------------------------------------------------------------------



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

North America
-----------------------------------------------------
Upstream Produced Gas and NGLs
Canada United States Crude Oil
-----------------------------------------------------
(US$ millions) 2003 2002 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Revenues, net
of royalties $ 892 $ 695 $ 298 $ 204 $ 239 $ 235
Expenses
Production and
mineral taxes 19 12 27 17 4 7
Transportation
and selling 81 57 30 22 21 13
Operating 84 83 17 10 76 57
Depreciation,
depletion and
amortization 297 199 82 83 125 68
-------------------------------------------------------------------------
Segment Income $ 411 $ 344 $ 142 $ 72 $ 13 $ 90
-------------------------------------------------------------------------
-------------------------------------------------------------------------



Ecuador U.K. North Sea Other Total Upstream
---------------------------------------------------------
2003 2002 2003 2002 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Revenues,
net of
royalties $ 169 $ 79 $ 45 $ 22 $ 33 $ 29 $1,676 $1,264
Expenses
Production
and mineral
taxes 8 5 - - - - 58 41
Transportation
and selling 21 6 6 2 - - 159 100
Operating 33 18 8 4 36 22 254 194
Depreciation,
depletion and
amortization 72 24 21 11 92 44 689 429
-------------------------------------------------------------------------
Segment Income $ 35 $ 26 $ 10 $ 5 $ (95) $ (37) $ 516 $ 500
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Midstream & Marketing
Total Midstream
Midstream Marketing(*) & Marketing
-----------------------------------------------------
(US$ millions) 2003 2002 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Revenues $ 435 $ 193 $ 739 $ 652 $ 1,174 $ 845
Expenses
Transportation
and selling - - 11 21 11 21
Operating 73 59 10 5 83 64
Purchased product 339 90 710 630 1,049 720
Depreciation,
depletion and
amortization 22 3 5 7 27 10
-------------------------------------------------------------------------
Segment Income $ 1 $ 41 $ 3 $ (11) $ 4 $ 30
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) 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.



Results of Operations (For the year ended December 31)

Midstream &
Upstream Marketing
-------------------------------------------
(US$ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Revenues, net of royalties $ 6,327 $ 3,674 $ 3,887 $ 2,594

Expenses
Production and mineral taxes 189 119 - -
Transportation and selling 490 277 55 87
Operating 973 626 324 187
Purchased product - - 3,455 2,200
Depreciation, depletion
and amortization 2,133 1,233 48 36
-------------------------------------------------------------------------
Segment Income $ 2,542 $ 1,419 $ 5 $ 84
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Corporate Consolidated
-------------------------------------------
2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Revenues, net of royalties $ 2 $ 8 $ 10,216 $ 6,276

Expenses
Production and mineral taxes - - 189 119
Transportation and selling - - 545 364
Operating - - 1,297 813
Purchased product - - 3,455 2,200
Depreciation, depletion
and amortization 41 35 2,222 1,304
-------------------------------------------------------------------------
Segment Income $ (39) $ (27) 2,508 1,476
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Administrative 173 119
Interest, net 287 290
Accretion of asset
retirement obligation 19 13
Foreign exchange (gain) loss (601) (14)
Stock-based compensation 18 -
Gain on corporate disposition - (33)
-------------------------------------------------------------------------
(104) 375
-------------------------------------------------------------------------
Net Earnings Before Income Tax 2,612 1,101
Income tax expense 445 366
-------------------------------------------------------------------------
Net Earnings from
Continuing Operations $ 2,167 $ 735
-------------------------------------------------------------------------
-------------------------------------------------------------------------



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


North America
-----------------------------------------------------
Upstream Produced Gas and NGLs
Canada United States Crude Oil
-----------------------------------------------------
(US$ millions) 2003 2002 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Revenues, net of
royalties $ 3,523 $ 1,971 $ 1,143 $ 454 $ 951 $ 825
Expenses
Production and
mineral taxes 52 50 108 35 4 20
Transportation
and selling 274 151 86 59 69 35
Operating 342 255 60 35 300 201
Depreciation,
depletion and
amortization 1,075 625 293 202 436 237
-------------------------------------------------------------------------
Segment Income $ 1,780 $ 890 $ 596 $ 123 $ 142 $ 332
-------------------------------------------------------------------------
-------------------------------------------------------------------------



Ecuador U.K. North Sea Other Total Upstream
---------------------------------------------------------
2003 2002 2003 2002 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Revenues,
net of
royalties $ 412 $ 245 $ 118 $ 103 $ 180 $ 76 $6,327 $3,674
Expenses
Production
and mineral
taxes 25 14 - - - - 189 119
Transportation
and selling 45 21 16 11 - - 490 277
Operating 83 53 18 11 170 71 973 626
Depreciation,
depletion and
amortization 159 79 74 39 96 51 2,133 1,233
-------------------------------------------------------------------------
Segment Income $ 100 $ 78 $ 10 $ 42 $ (86) $ (46) $2,542 $1,419
-------------------------------------------------------------------------
-------------------------------------------------------------------------



Midstream & Marketing Total Midstream
Midstream Marketing(*) & Marketing
-----------------------------------------------------
(US$ millions) 2003 2002 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Revenues $ 1,084 $ 440 $ 2,803 $ 2,154 $ 3,887 $ 2,594
Expenses
Transportation
and selling - - 55 87 55 87
Operating 261 174 63 13 324 187
Purchased product 762 169 2,693 2,031 3,455 2,200
Depreciation,
depletion and
amortization 40 24 8 12 48 36
-------------------------------------------------------------------------
Segment Income $ 21 $ 73 $ (16) $ 11 $ 5 $ 84
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) 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.



Capital Expenditures
Three Months Ended Year Ended
December 31 December 31
-------------------------------------------
(US$ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------
Upstream
Canada $ 911 $ 490 $ 3,198 $ 1,388
United States 342 211 968 1,176
Ecuador 93 61 265 168
United Kingdom 178 17 223 82
Other Countries 15 75 78 117
-------------------------------------------------------------------------
1,539 854 4,732 2,931
Midstream & Marketing 69 22 276 47
Corporate 69 24 107 43
-------------------------------------------------------------------------
Total $ 1,677 $ 900 $ 5,115 $ 3,021
-------------------------------------------------------------------------
-------------------------------------------------------------------------



Property, Plant and Equipment and Total Assets

Property, Plant
and Equipment Total Assets
-------------------------------------------
As at December 31, As at December 31,
-------------------------------------------
(US$ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------
Upstream $ 18,532 $ 13,656 $ 21,742 $ 16,042
Midstream & Marketing 784 470 1,879 1,403
Corporate 229 121 489 312
Assets of Discontinued
Operations - 2,155
-------------------------------------------------------------------------
Total $ 19,545 $ 14,247 $ 24,110 $ 19,912
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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

For the three months ended December 31
--------------------------------------------------------
Merchant Midstream-
Syncrude Energy Pipelines Total
--------------------------------------------------------
(US$ millions) 2003 2002 2003 2002 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues, Net
of Royalties $ - $ 85 $ - $ (6)$ - $ 40 $ - $ 119
-------------------------------------------------------------------------

Expenses
Transportation
and selling - 1 - - - - - 1
Operating - 33 - - - 16 - 49
Purchased
product - - - (6) - - - (6)
Depreciation,
depletion and
amortization - 6 - (1) - 3 - 8
Administrative - - - 1 - - - 1
Interest, net - 1 - - - 5 - 6
Loss on
discontinuance - - - 4 - - - 4
-------------------------------------------------------------------------
- 41 - (2) - 24 - 63
-------------------------------------------------------------------------
Net Earnings
(Loss) Before
Income Tax - 44 - (4) - 16 - 56
Income tax
expense
(recovery) - 17 - (1) - 6 - 22
-------------------------------------------------------------------------
Net Earnings
(Loss) from
Discontinued
Operations $ - $ 27 $ - $ (3)$ - $ 10 $ - $ 34
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Consolidated
Statement of
Earnings For the year ended December 31
--------------------------------------------------------
Merchant Midstream-
Syncrude(*) Energy Pipelines(*) Total
--------------------------------------------------------
(US$ millions) 2003 2002 2003 2002 2003 2002 2003 2002
-------------------------------------------------------------------------

Revenues, Net of
Royalties $ 87 $ 232 $ - $ 922 $ - $ 135 $ 87 $1,289
-------------------------------------------------------------------------

Expenses
Transportation
and selling 2 3 - - - - 2 3
Operating 46 105 - - - 50 46 155
Purchased
product - - - 931 - - - 931
Depreciation,
depletion and
amortization 7 16 - - - 18 7 34
Administrative - - - 22 - - - 22
Interest, net - 1 - - - 19 - 20
Foreign
exchange
(gain) - - - - - (3) - (3)
(Gain) loss on
discontinuance - - 19 (220) - (220) 19
-------------------------------------------------------------------------
55 125 - 972 (220) 84 (165) 1,181
-------------------------------------------------------------------------
Net Earnings
(Loss) Before
Income Tax 32 107 - (50) 220 51 252 108
Income tax
expense
(recovery) 8 28 - (17) 51 20 59 31
-------------------------------------------------------------------------
Net Earnings
(Loss) from
Discontinued
Operations $ 24 $ 79 $ - $ (33)$ 169 $ 31 $ 193 $ 77
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) Reflects only nine months of earnings for 2002 as EnCana did not, at
that time, own the operations which have been discontinued.



Consolidated Balance Sheet

As at December 31
--------------------------------------------------------
Merchant Midstream-
Syncrude Energy Pipelines Total
--------------------------------------------------------
(US$ millions) 2003 2002 2003 2002 2003 2002 2003 2002
-------------------------------------------------------------------------

Assets
Cash and cash
equivalents $ - $ 18 $ - $ - $ - $ 43 $ - $ 61
Accounts
receivable and
accrued
revenues - 41 - - - 20 - 61
Inventories - 9 - - - 1 - 10
-------------------------------------------------------------------------
- 68 - - - 64 - 132
Property, plant
and equipment,
net - 884 - - - 517 - 1,401
Investments and
other assets - - - - - 237 - 237
Goodwill - 264 - - - 121 - 385
-------------------------------------------------------------------------
- 1,216 - - - 939 - 2,155
-------------------------------------------------------------------------
Liabilities
Accounts payable
and accrued
liabilities - 68 - 3 - 25 - 96
Income tax
payable - (4) - - - 11 - 7
Short-term
debt - 277 - - - - - 277
Current portion
of long-term
debt - - - - - 15 - 15
-------------------------------------------------------------------------
- 341 - 3 - 51 - 395
Long-term debt - - - - - 365 - 365
Future income
taxes - 236 - - - 104 - 340
-------------------------------------------------------------------------
- 577 - 3 - 520 - 1,100
-------------------------------------------------------------------------
Net Assets of
Discontinued
Operations $ - $ 639 $ - $ (3)$ - $ 419 $ - $1,055
-------------------------------------------------------------------------
-------------------------------------------------------------------------


6. FOREIGN EXCHANGE (GAIN) LOSS

Three Months Ended Year Ended
December 31 December 31
-------------------------------------------
(US$ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------
Unrealized Foreign Exchange
(Gain) on Translation of
U.S. Dollar Debt Issued
in Canada $ (141) $ (8) $ (545) $ (23)
Other Foreign Exchange
(Gain) Loss (24) 11 (56) 9
-------------------------------------------------------------------------
$ (165) $ 3 $ (601) $ (14)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


7. INCOME TAXES
Three Months Ended Year Ended
December 31 December 31
-------------------------------------------
(US$ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------

Provision for Income Taxes
Current
Canada $ (118) $ (108) $ (136) $ (26)
United States 29 - 39 (31)
Ecuador 18 8 39 17
United Kingdom (3) (8) - -
Other Countries 1 1 2 2
-------------------------------------------------------------------------
(73) (107) (56) (38)
Future 173 245 860 424
Future tax rate
reductions(*) 3 (3) (359) (20)
-------------------------------------------------------------------------
$ 103 $ 135 $ 445 $ 366
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) 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.


8. LONG-TERM DEBT
As at As at
December 31, December 31,
(US$ millions) 2003 2002
-------------------------------------------------------------------------

Canadian Dollar Denominated Debt
Revolving credit and term loan borrowings $ 1,425 $ 879
Unsecured notes and debentures 1,335 1,155
Preferred securities 252 206
-------------------------------------------------------------------------
3,012 2,240
-------------------------------------------------------------------------

U.S. Dollar Denominated Debt
Revolving credit and term loan borrowings 417 441
Unsecured notes and debentures 2,713 2,284
Preferred securities 150 150
-------------------------------------------------------------------------
3,280 2,875
-------------------------------------------------------------------------

Increase in Value of Debt Acquired(*) 83 70
Current Portion of Long-Term Debt (287) (134)
-------------------------------------------------------------------------
$ 6,088 $ 5,051
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) 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:

As at December 31,
-----------------------------
(US$ millions) 2003 2002
-------------------------------------------------------------------------
Asset Retirement Obligation,
Beginning of Year $ 309 $ 163
Liabilities Incurred 64 146
Liabilities Settled (23) (13)
Accretion Expense 19 13
Other 61 -
-------------------------------------------------------------------------
Asset Retirement Obligation, End of Year $ 430 $ 309
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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

December 31, 2003 December 31, 2002
---------------------------------------------
(millions) Number Amount Number Amount
-------------------------------------------------------------------------
Common Shares Outstanding,
Beginning of Year 478.9 $ 5,511 254.9 $ 142
Shares Issued to AEC
Shareholders - - 218.5 5,281
Shares Issued under
Option Plans 5.5 114 5.5 88
Shares Repurchased (23.8) (320) - -
-------------------------------------------------------------------------
Common Shares Outstanding,
End of Year 460.6 $ 5,305 478.9 $ 5,511
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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:

Weighted
Stock Average
Options Exercise
(millions) Price (C$)
-------------------------------------------------------------------------
Outstanding, Beginning of Year 29.6 39.74
Granted under EnCana Plans 6.4 47.97
Exercised (5.5) 29.11
Forfeited (1.7) 41.18
-------------------------------------------------------------------------
Outstanding, End of Year 28.8 43.13
-------------------------------------------------------------------------
Exercisable, End of Year 15.6 38.92
-------------------------------------------------------------------------
-------------------------------------------------------------------------



Outstanding Options Exercisable Options
-----------------------------------------------------
Weighted
Number Average Number of
of Remaining Weighted Options Weighted
Range of Options Contractual Average Out- Average
Exercise Outstanding Life Exercise standing Exercise
Price (C$) (millions) (years) Price(C$) (millions) Price(C$)
-------------------------------------------------------------------------
13.50 to 19.99 1.5 0.9 18.86 1.5 18.86
20.00 to 24.99 1.3 1.5 22.38 1.3 22.38
25.00 to 29.99 2.2 1.5 26.49 2.2 26.49
30.00 to 43.99 1.3 2.2 38.89 1.2 38.52
44.00 to 53.00 22.5 3.7 47.93 9.4 47.63
-------------------------------------------------------------------------
28.8 2.8 43.13 15.6 38.92
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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).

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:

Year Ended
December 31
-----------------------------
2003 2002
-------------------------------------------------------------------------
Weighted Average Fair Value of Options
Granted (C$) $ 12.21 $ 13.31
Risk Free Interest Rate 3.87% 4.29%
Expected Lives (years) 3.00 3.00
Expected Volatility 0.33 0.35
Annual Dividend per Share (C$) $ 0.40 $ 0.40
-------------------------------------------------------------------------
-------------------------------------------------------------------------


11. PER SHARE AMOUNTS

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

Three Months Ended Year Ended
--------------------------------------------------------------
September
March 31 June 30 30 December 31 December 31
--------------------------------------------------------------
(millions) 2003 2003 2003 2003 2002 2003 2002
-------------------------------------------------------------------------
Weighted
Average
Common
Shares
Outstanding
- Basic 479.9 480.6 473.4 462.3 477.9 474.1 417.8
Effect of
Dilutive
Securities 4.4 3.8 4.5 3.6 4.7 5.6 4.8
-------------------------------------------------------------------------
Weighted
Average
Common
Shares
Outstanding
- Diluted 484.3 484.4 477.9 465.9 482.6 479.7 422.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------


12. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

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

As at
(US$ millions) December 31, 2003
-------------------------------------------------------------------------
Commodity Price Risk
Natural gas $ 57
Crude oil (279)
Gas storage optimization (25)
Power 4
Foreign Currency Risk 7
Interest Rate Risk 44
-------------------------------------------------------------------------
$ (192)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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.



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:

Unrecognized
Notional Gain/
Volumes Physical/ (Loss)
(MMcf/d) Financial Term Price (US$ millions)
-------------------------------------------------------------------------
Fixed Price
Contracts
Sales Contracts
Fixed AECO
price 453 Financial 2004 6.20 C$/mcf $ 5
NYMEX Fixed
price 732 Financial 2004 5.13 US$/mcf (86)
Chicago Fixed
price 40 Financial 2004 5.41 US$/mcf (1)
AECO Collars 71 Financial 2004 5.34-7.52 C$/mcf 2
NYMEX Collars 50 Physical 2004 2.46-4.90 US$/mcf (16)

NYMEX Collars 50 Physical 2005 2.46-4.90 US$/mcf (13)
2006-
NYMEX Collars 46 Physical 2007 2.46-4.90 US$/mcf (20)

Basis Contracts
Sales Contracts
Fixed NYMEX
to AECO
basis 343 Financial 2004 (0.54) US$/mcf 22
Fixed NYMEX
to Rockies
basis 255 Financial 2004 (0.48) US$/mcf 18
Fixed NYMEX
to Rockies
basis 413 Physical 2004 (0.50) US$/mcf 26
Fixed NYMEX
to San Juan
basis 60 Financial 2004 (0.63) US$/mcf 1
Fixed NYMEX
to San Juan
basis 50 Physical 2004 (0.64) US$/mcf 1
Fixed Rockies
to CIG basis 38 Financial 2004 (0.10) US$/mcf -

Fixed NYMEX
to AECO
basis 877 Financial 2005 (0.66) US$/mcf 6
Fixed NYMEX
to Rockies
basis 283 Financial 2005 (0.49) US$/mcf 16
Fixed NYMEX
to Rockies
basis 393 Physical 2005 (0.47) US$/mcf 26
Fixed NYMEX
to San Juan
basis 75 Financial 2005 (0.63) US$/mcf (1)
Fixed NYMEX
to San Juan
basis 50 Physical 2005 (0.64) US$/mcf (1)
Fixed Rockies
to CIG basis 50 Financial 2005 (0.10) US$/mcf 1

Fixed NYMEX 2006-
to AECO basis 402 Financial 2008 (0.65) US$/mcf 24
Fixed NYMEX
to Rockies 2006-
basis 175 Financial 2008 (0.57) US$/mcf 13
Fixed NYMEX
to Rockies 2006-
basis 207 Physical 2007 (0.49) US$/mcf 22
Fixed NYMEX
to San Juan
basis 62 Financial 2006 (0.62) US$/mcf (1)
Fixed NYMEX
to San Juan
basis 42 Physical 2006 (0.64) US$/mcf (1)
Fixed Rockies 2006-
to CIG basis 31 Financial 2007 (0.10) US$/mcf -

Purchase
Contracts
Fixed NYMEX
to AECO basis 47 Financial 2004 (0.80) US$/mcf (3)
-------------------------------------------------------------------------
40
Gas Marketing
Financial
Positions(1) (2)
Gas Marketing
Physical
Positions(1) 19
-------------------------------------------------------------------------
$ 57
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) The gas marketing activities are part of the daily ongoing operations
of the Company's proprietary production management.


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:

Unrecognized
Notional Average Gain/
Volumes Price (Loss)
(bbl/d) Term (US$/bbl) (US$ millions)
-------------------------------------------------------------------------
Fixed WTI NYMEX Price 62,500 2004 23.13 $ (162)
Collars on WTI NYMEX 62,500 2004 20.00-25.69 (115)
3-way Put Spread 10,000 2005 20.00/25.00/28.77 (3)
-------------------------------------------------------------------------
(280)
Crude Oil Marketing
Financial
Positions(1) (2)
Crude Oil Marketing
Physical
Positions(1) 3
-------------------------------------------------------------------------
$ (279)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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:

Unrecognized
Notional Gain/
Volumes Price (Loss)
(bcf) (US$/mcf) (US$ millions)
-------------------------------------------------------------------------
Financial Instruments
Purchases 286.7 5.63 $ 109
Sales 312.4 5.69 (132)
-------------------------------------------------------------------------
(23)
Physical Contracts (2)
-------------------------------------------------------------------------
$ (25)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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.


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.


PREPARED IN C$
Interim Report
For the period ended December 31, 2003

EnCana Corporation

CONSOLIDATED STATEMENT OF EARNINGS

December 31
------------------------------------------
(unaudited) Three Months Ended Year Ended
(C$ millions, except ------------------------------------------
per share amounts) 2003 2002 2003 2002
-------------------------------------------------------------------------
(restated (restated
- Note 2) - Note 2)

REVENUES,
NET OF ROYALTIES (Note 4) $ 3,751 $ 3,322 $ 14,316 $ 9,831
-------------------------------------------------------------------------

EXPENSES (Note 4)
Production and
mineral taxes 77 64 264 185
Transportation
and selling 223 190 760 570
Operating 443 405 1,815 1,274
Purchased product 1,381 1,131 4,839 3,448
Depreciation,
depletion and
amortization 954 710 3,090 2,042
Administrative 69 76 241 187
Interest, net 112 187 401 453
Accretion of asset
retirement
obligation (Note 9) 5 7 27 21
Foreign exchange
(gain) loss (Note 6) (191) 4 (785) (23)
Stock-based
compensation (Note 2) 8 - 24 -
Gain on corporate
disposition - (51) - (51)
-------------------------------------------------------------------------
3,081 2,723 10,676 8,106
-------------------------------------------------------------------------
NET EARNINGS
BEFORE INCOME TAX 670 599 3,640 1,725
Income tax
expense (Note 7) 136 212 664 573
-------------------------------------------------------------------------
NET EARNINGS FROM
CONTINUING OPERATIONS 534 387 2,976 1,152
NET EARNINGS FROM
DISCONTINUED
OPERATIONS (Note 5) - 56 298 123
-------------------------------------------------------------------------
NET EARNINGS $ 534 $ 443 $ 3,274 $ 1,275
-------------------------------------------------------------------------
-------------------------------------------------------------------------


NET EARNINGS FROM
CONTINUING OPERATIONS
PER COMMON SHARE (Note 11)
Basic $ 1.16 $ 0.81 $ 6.28 $ 2.76
Diluted $ 1.15 $ 0.80 $ 6.20 $ 2.73
-------------------------------------------------------------------------
-------------------------------------------------------------------------

NET EARNINGS PER
COMMON SHARE (Note 11)
Basic $ 1.16 $ 0.93 $ 6.91 $ 3.05
Diluted $ 1.15 $ 0.92 $ 6.83 $ 3.02
-------------------------------------------------------------------------
-------------------------------------------------------------------------



EnCana Corporation

CONSOLIDATED STATEMENT OF RETAINED EARNINGS

Year Ended December 31
-------------------------
(unaudited) (C$ millions) 2003 2002
-------------------------------------------------------------------------
(restated
- Note 2)
RETAINED EARNINGS, BEGINNING OF YEAR
As previously reported $ 4,684 $ 3,630
Retroactive adjustment for changes in
accounting policies (Note 2) 103 49
-------------------------------------------------------------------------
As restated 4,787 3,679
Net Earnings 3,274 1,275
Dividends on Common Shares (190) (167)
Charges for Normal Course Issuer Bid (Note 10) (645) -
-------------------------------------------------------------------------
RETAINED EARNINGS, END OF YEAR $ 7,226 $ 4,787
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.



EnCana Corporation

CONSOLIDATED BALANCE SHEET

As at As at
December December
(unaudited) (C$ millions) 31, 2003 31, 2002
-------------------------------------------------------------------------
(restated
- Note 2)
ASSETS
Current Assets
Cash and cash equivalents $ 191 $ 183
Accounts receivable and
accrued revenues 1,766 1,987
Inventories 740 443
Assets of discontinued operations (Note 5) - 3,404
-------------------------------------------------------------------------
2,697 6,017
Property, Plant and Equipment, net (Note 4) 25,259 22,504
Investments and Other Assets 732 462
Goodwill 2,469 2,469
-------------------------------------------------------------------------
(Note 4) $ 31,157 $ 31,452
-------------------------------------------------------------------------
-------------------------------------------------------------------------


LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued
liabilities $ 2,040 $ 2,282
Income tax payable 84 20
Current portion of long-term debt (Note 8) 372 212
Liabilities of discontinued
operations (Note 5) - 1,738
-------------------------------------------------------------------------
2,496 4,252
Long-Term Debt (Note 8) 7,866 7,978
Other Liabilities 27 86
Asset Retirement Obligation (Note 9) 556 488
Future Income Taxes 5,637 4,877
-------------------------------------------------------------------------
16,582 17,681
-------------------------------------------------------------------------
Shareholders' Equity
Share capital (Note 10) 8,456 8,732
Share options, net 92 133
Paid in surplus 24 61
Retained earnings 7,226 4,787
Foreign currency translation
adjustment (1,223) 58
-------------------------------------------------------------------------
14,575 13,771
-------------------------------------------------------------------------
$ 31,157 $ 31,452
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.



EnCana Corporation

CONSOLIDATED STATEMENT OF CASH FLOWS

December 31
-------------------------------------------
Three Months Ended Year Ended
-------------------------------------------
(unaudited) (C$ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------
(restated (restated
- Note 2) - Note 2)

OPERATING ACTIVITIES
Net earnings from
continuing operations $ 534 $ 387 $ 2,976 $ 1,152
Depreciation, depletion
and amortization 954 710 3,090 2,042
Future income
taxes (Note 7) 232 379 735 632
Unrealized foreign
exchange (gain) (159) (13) (704) (37)
Accretion of asset
retirement obligation 5 7 27 21
Other 37 (101) 84 (250)
-------------------------------------------------------------------------
Cash flow from
continuing operations 1,603 1,369 6,208 3,560
Cash flow from
discontinued
operations 49 95 54 237
-------------------------------------------------------------------------
Cash flow 1,652 1,464 6,262 3,797
Net change in other
assets and liabilities (2) (2) (117) (27)
Net change in non-cash
working capital from
continuing operations (406) (544) (161) (1,351)
Net change in non-cash
working capital from
discontinued operations (49) 26 29 99
-------------------------------------------------------------------------
1,195 944 6,013 2,518
-------------------------------------------------------------------------

INVESTING ACTIVITIES
Capital
expenditures (Note 4) (2,220) (1,413) (7,100) (4,724)
Proceeds on
disposal of
property, plant
and equipment 375 190 402 566
Corporate
(acquisitions)
and dispositions (Note 3) 18 93 (289) 93
Business
combination with
Alberta Energy
Company Ltd. - - - (128)
Equity investments (4) - (226) -
Net change in
investments
and other 7 50 (89) 67
Net change in
non-cash working
capital from
continuing
operations 38 460 (135) 293
Discontinued
operations (Note 5) - (93) 2,372 (229)
-------------------------------------------------------------------------
(1,786) (713) (5,065) (4,062)
-------------------------------------------------------------------------

FINANCING ACTIVITIES
Issuance of
long-term debt 696 1,189 2,197 2,354
Repayment of
long-term debt - (2,026) (1,445) (1,886)
Issuance of
common shares (Note 10) 25 43 161 139
Purchase of
common shares (Note 10) (244) - (1,184) -
Dividends on
common shares (47) (47) (190) (167)
Other (9) (57) (16) (82)
Net change in
non-cash working
capital from
continuing
operations 29 1 - (12)
Discontinued
operations - 434 (438) 425
-------------------------------------------------------------------------
450 (463) (915) 771
-------------------------------------------------------------------------

DEDUCT: FOREIGN
EXCHANGE LOSS ON
CASH AND CASH
EQUIVALENTS HELD
IN FOREIGN CURRENCY 3 - 25 7
-------------------------------------------------------------------------

(DECREASE) INCREASE IN
CASH AND CASH EQUIVALENTS (144) (232) 8 (780)
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD 335 415 183 963
-------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS,
END OF PERIOD $ 191 $ 183 $ 191 $ 183
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.



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).

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 centres 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 centre 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

2003 2002
-------------------------------------------------------
As As As As
(C$ millions) Reported Change Restated Reported Change Restated
-------------------------------------------------------------------------

Consolidated
Balance Sheet
Assets
Assets of
discontinued
operations $ - $ - $ - $ 3,422 $ (18) $ 3,404
Property, plant
and equipment,
net 25,076 183 25,259 22,356 148 22,504

Liabilities
Liabilities of
discontinued
operations $ - $ - $ - $ 1,758 $ (20) $ 1,738
Current portion
of long-term
debt 246 126 372 212 - 212
Long-term debt 7,451 415 7,866 7,395 583 7,978
Preferred
securities of
subsidiary - - - 457 (457) -
Other
liabilities &
asset retirement
obligation 611 (28) 583 564 10 574
Future income
taxes 5,579 58 5,637 4,840 37 4,877

Shareholders'
Equity
Preferred
securities $ 541 $ (541) $ - $ 126 $ (126) $ -
Paid in surplus - 24 24 61 - 61
Retained
earnings 7,097 129 7,226 4,684 103 4,787

Consolidated
Statement of
Earnings
Net Earnings $ 3,239 $ 35 $ 3,274 $ 1,224 $ 51 $ 1,275

Net Earnings per
Common Share -
Diluted $ 6.78 $ 0.05 $ 6.83 $ 2.89 $ 0.13 $ 3.02
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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:


(C$ millions) Vintage Savannah
-------------------------------------------------------------------------
Working Capital $ 2 $ 1
Property, Plant and Equipment, net 194 155
Future Income Taxes (17) (28)
-------------------------------------------------------------------------
$ 179 $ 128
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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.


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

Upstream Midstream & Marketing
-------------------------------------------
(C$ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Revenues, net of royalties $ 2,206 $ 1,984 $ 1,545 $ 1,327

Expenses
Production and mineral taxes 77 64 - -
Transportation and selling 209 157 14 33
Operating 334 304 109 101
Purchased product - - 1,381 1,131
Depreciation, depletion
and amortization 906 673 36 16
-------------------------------------------------------------------------
Segment Income $ 680 $ 786 $ 5 $ 46
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Corporate Consolidated
-------------------------------------------
2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Revenues, net of royalties $ - $ 11 $ 3,751 $ 3,322

Expenses
Production and mineral taxes - - 77 64
Transportation and selling - - 223 190
Operating - - 443 405
Purchased product - - 1,381 1,131
Depreciation, depletion
and amortization 12 21 954 710
-------------------------------------------------------------------------
Segment Income $ (12) $ (10) 673 822
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Administrative 69 76
Interest, net 112 187
Accretion of asset
retirement obligation 5 7
Foreign exchange (gain) loss (191) 4
Stock-based compensation 8 -
Gain on corporate disposition - (51)
-------------------------------------------------------------------------
3 223
-------------------------------------------------------------------------
Net Earnings Before Income Tax 670 599
Income tax expense 136 212
-------------------------------------------------------------------------
Net Earnings from Continuing Operations $ 534 $ 387
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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

North America
--------------------------------------------------
Upstream Produced Gas and NGLs
Canada United States Crude Oil
--------------------------------------------------
(C$ millions) 2003 2002 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Revenues, net
of royalties $ 1,174 $ 1,091 $ 392 $ 320 $ 315 $ 370
Expenses
Production and
mineral taxes 25 19 36 27 5 10
Transportation
and selling 107 89 40 34 27 20
Operating 110 130 23 16 100 89
Depreciation,
depletion and
amortization 390 312 108 130 164 107
-------------------------------------------------------------------------
Segment Income $ 542 $ 541 $ 185 $ 113 $ 19 $ 144
-------------------------------------------------------------------------
-------------------------------------------------------------------------



Ecuador U.K. North Sea Other Total Upstream
----------------------------------------------------------
2003 2002 2003 2002 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Revenues,
net of
royalties $ 222 $ 124 $ 59 $ 34 $ 44 $ 45 $2,206 $1,984

Expenses
Production and
mineral taxes 11 8 - - - - 77 64
Transportation
and selling 27 10 8 4 - - 209 157
Operating 43 28 11 7 47 34 334 304
Depreciation,
depletion and
amortization 95 37 28 17 121 70 906 673
-------------------------------------------------------------------------
Segment Income $ 46 $ 41 $ 12 $ 6 $(124) $ (59) $ 680 $ 786
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Midstream & Marketing Total Midstream
Midstream Marketing (*) & Marketing
-----------------------------------------------------
(C$ millions) 2003 2002 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Revenues $ 573 $ 303 $ 972 $ 1,024 $ 1,545 $ 1,327

Expenses
Transportation
and selling - - 14 33 14 33
Operating 96 93 13 8 109 101
Purchased product 446 142 935 989 1,381 1,131
Depreciation,
depletion and
amortization 29 5 7 11 36 16
-------------------------------------------------------------------------
Segment Income $ 2 $ 63 $ 3 $ (17) $ 5 $ 46
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) 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.



Results of Operations (For the year ended December 31)
Midstream &
Upstream Marketing
-------------------------------------------
(C$ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Revenues, net of royalties $ 8,866 $ 5,755 $ 5,446 $ 4,062

Expenses
Production and mineral taxes 264 185 - -
Transportation and selling 683 434 77 136
Operating 1,360 980 455 294
Purchased product - - 4,839 3,448
Depreciation, depletion
and amortization 2,967 1,930 66 57
-------------------------------------------------------------------------
Segment Income $ 3,592 $ 2,226 $ 9 $ 127
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Corporate Consolidated
-------------------------------------------
2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Revenues, net of royalties $ 4 $ 14 $ 14,316 $ 9,831

Expenses
Production and mineral taxes - - 264 185
Transportation and selling - - 760 570
Operating - - 1,815 1,274
Purchased product - - 4,839 3,448
Depreciation, depletion
and amortization 57 55 3,090 2,042
-------------------------------------------------------------------------
Segment Income $ (53) $ (41) 3,548 2,312
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Administrative 241 187
Interest, net 401 453
Accretion of asset
retirement obligation 27 21
Foreign exchange (gain) loss (785) (23)
Stock-based compensation 24 -
Gain on corporate disposition - (51)
-------------------------------------------------------------------------
(92) 587
-------------------------------------------------------------------------
Net Earnings Before Income Tax 3,640 1,725
Income tax expense 664 573
-------------------------------------------------------------------------
Net Earnings from Continuing Operations $ 2,976 $ 1,152
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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

North America
-----------------------------------------------
Upstream Produced Gas and NGLs
Canada United States Crude Oil
-----------------------------------------------
(C$ millions) 2003 2002 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Revenues, net of
royalties $4,945 $3,089 $1,604 $ 711 $1,331 $1,294
Expenses
Production and mineral
taxes 70 78 151 55 7 31
Transportation and
selling 384 235 119 91 96 55
Operating 480 398 85 54 420 315
Depreciation, depletion
and amortization 1,501 977 409 315 608 372
-------------------------------------------------------------------------
Segment Income $2,510 $1,401 $ 840 $ 196 $ 200 $ 521
-------------------------------------------------------------------------
-------------------------------------------------------------------------

U.K. Total
Ecuador North Sea Other Upstream
--------------------------------------------------------
2003 2002 2003 2002 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Revenues,
net of
royalties $ 570 $ 382 $ 164 $ 160 $ 252 $ 119 $8,866 $5,755
Expenses
Production and
mineral taxes 36 21 - - - - 264 185
Transportation
and selling 60 34 24 19 - - 683 434
Operating 113 83 24 18 238 112 1,360 980
Depreciation,
depletion and
amortization 218 123 103 63 128 80 2,967 1,930
-------------------------------------------------------------------------
Segment Income $ 143 $ 121 $ 13 $ 60 $ (114)$ (73)$3,592 $2,226
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Total
Midstream & Marketing Midstream
Midstream Marketing (*) & Marketing
-----------------------------------------------
(C$ millions) 2003 2002 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Revenues $1,513 $ 689 $3,933 $3,373 $5,446 $4,062
Expenses
Transportation and
selling - - 77 136 77 136
Operating 368 274 87 20 455 294
Purchased product 1,059 265 3,780 3,183 4,839 3,448
Depreciation, depletion
and amortization 56 38 10 19 66 57
-------------------------------------------------------------------------
Segment Income $ 30 $ 112 $ (21) $ 15 $ 9 $ 127
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) 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.


Capital Expenditures
Three Months Ended Year Ended
December 31 December 31
-------------------------------------------
(C$ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------
Upstream
Canada $ 1,199 $ 769 $ 4,449 $ 2,175
United States 454 331 1,339 1,831
Ecuador 123 97 370 265
United Kingdom 238 27 302 130
Other Countries 20 118 109 184
-------------------------------------------------------------------------
2,034 1,342 6,569 4,585
Midstream & Marketing 91 34 381 73
Corporate 95 37 150 66
-------------------------------------------------------------------------
Total $ 2,220 $ 1,413 $ 7,100 $ 4,724
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Property, Plant and Equipment
and Total Assets
Property, Plant
and Equipment Total Assets
-------------------------------------------
As at As at
-------------------------------------------
December December December December
(C$ millions) 31, 2003 31, 2002 31, 2003 31, 2002
-------------------------------------------------------------------------
Upstream $ 23,950 $ 21,570 $ 28,097 $ 25,340
Midstream & Marketing 1,014 742 2,428 2,216
Corporate 295 192 632 492
Assets of Discontinued
Operations - 3,404
-------------------------------------------------------------------------
Total $ 25,259 $ 22,504 $ 31,157 $ 31,452
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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 For the three months ended December 31
--------------------------------------------------------
Merchant Midstream-
Syncrude Energy Pipelines Total
--------------------------------------------------------
(C$ millions) 2003 2002 2003 2002 2003 2002 2003 2002
-------------------------------------------------------------------------

Revenues, Net of
Royalties $ - $ 134 $ - $ (9)$ - $ 63 $ - $ 188
-------------------------------------------------------------------------

Expenses
Transportation
and selling - 1 - - - - - 1
Operating - 52 - - - 25 - 77
Purchased
product - - - (10) - - - (10)
Depreciation,
depletion and
amortization - 9 - (1) - 4 - 12
Administrative - - - 1 - - - 1
Interest, net - 2 - - - 8 - 10
Loss on
discontinuance - - - 6 - - - 6
-------------------------------------------------------------------------
- 64 - (4) - 37 - 97
-------------------------------------------------------------------------
Net Earnings
(Loss) Before
Income Tax - 70 - (5) - 26 - 91
Income tax
expense
(recovery) - 27 - (2) - 10 - 35
-------------------------------------------------------------------------
Net Earnings
(Loss) from
Discontinued
Operations $ - $ 43 $ - $ (3)$ - $ 16 $ - $ 56
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Consolidated
Statement of
Earnings For the year ended December 31
--------------------------------------------------------
Merchant Midstream-
Syncrude(*) Energy Pipelines(*) Total
--------------------------------------------------------
(C$ millions) 2003 2002 2003 2002 2003 2002 2003 2002
-------------------------------------------------------------------------

Revenues, Net
of Royalties $ 129 $ 365 $ - $1,454 $ - $ 212 $ 129 $2,031
-------------------------------------------------------------------------

Expenses
Transportation
and selling 2 4 - - - - 2 4
Operating 69 164 - - - 78 69 242
Purchased
product - - - 1,465 - - - 1,465
Depreciation,
depletion and
amortization 10 26 - - - 27 10 53
Administrative - - - 35 - - - 35
Interest, net - 2 - - - 30 - 32
Foreign exchange
(gain) - - - - - (3) - (3)
(Gain) loss on
discontinuance - - - 30 (343) - (343) 30
-------------------------------------------------------------------------
81 196 - 1,530 (343) 132 (262) 1,858
-------------------------------------------------------------------------
Net Earnings
(Loss) Before
Income Tax 48 169 - (76) 343 80 391 173
Income tax
expense
(recovery) 13 45 - (27) 80 32 93 50
-------------------------------------------------------------------------
Net Earnings
(Loss) from
Discontinued
Operations $ 35 $ 124 $ - $ (49)$ 263 $ 48 $ 298 $ 123
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) Reflects only nine months of earnings for 2002 as EnCana did not, at
that time, own the operations which have been discontinued.



Consolidated
Balance Sheet As at December 31
--------------------------------------------------------
Merchant Midstream-
Syncrude Energy Pipelines Total
--------------------------------------------------------
(C$ millions) 2003 2002 2003 2002 2003 2002 2003 2002
-------------------------------------------------------------------------
Assets
Cash and cash
equivalents $ - $ 29 $ - $ - $ - $ 68 $ - $ 97
Accounts
receivable and
accrued
revenues - 65 - - - 31 - 96
Inventories - 15 - - - 1 - 16
-------------------------------------------------------------------------
- 109 - - - 100 - 209
Property, plant
and equipment,
net - 1,396 - - - 817 - 2,213
Investments and
other assets - - - - - 374 - 374
Goodwill - 417 - - - 191 - 608
-------------------------------------------------------------------------
- 1,922 - - - 1,482 - 3,404
-------------------------------------------------------------------------
Liabilities
Accounts payable
and accrued
liabilities - 108 - 5 - 40 - 153
Income tax
payable - (6) - - - 17 - 11
Short-term
debt - 438 - - - - - 438
Current portion
of long-term
debt - - - - - 23 - 23
-------------------------------------------------------------------------
- 540 - 5 - 80 - 625
Long-term debt - - - - - 576 - 576
Future income
taxes - 373 - - - 164 - 537
-------------------------------------------------------------------------
- 913 - 5 - 820 - 1,738
-------------------------------------------------------------------------
Net Assets of
Discontinued
Operations $ - $1,009 $ - $ (5)$ - $ 662 $ - $1,666
-------------------------------------------------------------------------
-------------------------------------------------------------------------


6. FOREIGN EXCHANGE (GAIN) LOSS

Three Months Ended Year Ended
December 31 December 31
-------------------------------------------
(C$ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------
Unrealized Foreign Exchange
(Gain) on Translation of
U.S. Dollar Debt Issued
in Canada $ (159) $ (13) $ (704) $ (37)
Other Foreign Exchange
(Gain) Loss (32) 17 (81) 14
-------------------------------------------------------------------------
$ (191) $ 4 $ (785) $ (23)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


7. INCOME TAXES
Three Months Ended Year Ended
December 31 December 31
-------------------------------------------
(C$ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------

Provision for Income Taxes
Current
Canada $ (155) $ (169) $ (180) $ (40)
United States 38 - 52 (49)
Ecuador 24 13 54 27
United Kingdom (4) (12) 1 -
Other Countries 1 1 2 3
-------------------------------------------------------------------------
(96) (167) (71) (59)
Future 228 384 1,217 665
Future tax rate
reductions (*) 4 (5) (482) (33)
-------------------------------------------------------------------------
$ 136 $ 212 $ 664 $ 573
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) 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.


8. LONG-TERM DEBT
As at As at
December 31, December 31,
(C$ millions) 2003 2002
-------------------------------------------------------------------------

Canadian Dollar Denominated Debt
Revolving credit and term loan borrowings $ 1,842 $ 1,388
Unsecured notes and debentures 1,725 1,825
Preferred securities 326 326
-------------------------------------------------------------------------
3,893 3,539
-------------------------------------------------------------------------

U.S. Dollar Denominated Debt
Revolving credit and term loan borrowings 539 696
Unsecured notes and debentures 3,505 3,608
Preferred securities 194 237
-------------------------------------------------------------------------
4,238 4,541
-------------------------------------------------------------------------

Increase in Value of Debt Acquired (*) 107 110
Current Portion of Long-Term Debt (372) (212)
-------------------------------------------------------------------------
$ 7,866 $ 7,978
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) 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:

As at December 31,
-----------------------------
(C$ millions) 2003 2002
-------------------------------------------------------------------------
Asset Retirement Obligation,
Beginning of Year $ 488 $ 259
Liabilities Incurred 89 229
Liabilities Settled (32) (21)
Accretion Expense 27 21
Other (16) -
-------------------------------------------------------------------------
Asset Retirement Obligation, End of Year $ 556 $ 488
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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

December 31, 2003 December 31, 2002
-------------------------------------------
(millions) Number Amount Number Amount
-------------------------------------------------------------------------
Common Shares Outstanding,
Beginning of Year 478.9 $ 8,732 254.9 $ 196
Shares Issued to AEC
Shareholders - - 218.5 8,397
Shares Issued under Option
Plans 5.5 161 5.5 139
Shares Repurchased (23.8) (437) - -
-------------------------------------------------------------------------
Common Shares Outstanding,
End of Year 460.6 $ 8,456 478.9 $ 8,732
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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:

Weighted
Stock Average
Options Exercise
(millions) Price ($)
-------------------------------------------------------------------------
Outstanding, Beginning of Year 29.6 39.74
Granted under EnCana Plans 6.4 47.97
Exercised (5.5) 29.11
Forfeited (1.7) 41.18
-------------------------------------------------------------------------
Outstanding, End of Year 28.8 43.13
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Exercisable, End of Year 15.6 38.92
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Outstanding Options Exercisable Options
-----------------------------------------------------
Weighted
Number Average Number of
of Remaining Weighted Options Weighted
Range of Options Contractual Average Out- Average
Exercise Outstanding Life Exercise standing Exercise
Price (C$) (millions) (years) Price ($) (millions) Price ($)
-------------------------------------------------------------------------
13.50 to 19.99 1.5 0.9 18.86 1.5 18.86
20.00 to 24.99 1.3 1.5 22.38 1.3 22.38
25.00 to 29.99 2.2 1.5 26.49 2.2 26.49
30.00 to 43.99 1.3 2.2 38.89 1.2 38.52
44.00 to 53.00 22.5 3.7 47.93 9.4 47.63
-------------------------------------------------------------------------
28.8 2.8 43.13 15.6 38.92
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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).

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:

Year Ended
December 31
-----------------------------
2003 2002
-------------------------------------------------------------------------
Weighted Average Fair Value of Options
Granted $ 12.21 $ 13.31
Risk Free Interest Rate 3.87% 4.29%
Expected Lives (years) 3.00 3.00
Expected Volatility 0.33 0.35
Annual Dividend per Share $ 0.40 $ 0.40
-------------------------------------------------------------------------
-------------------------------------------------------------------------


11. PER SHARE AMOUNTS

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

Three Months Ended Year Ended
--------------------------------------------------------------
September
March 31 June 30 30 December 31 December 31
--------------------------------------------------------------
(millions) 2003 2003 2003 2003 2002 2003 2002
-------------------------------------------------------------------------
Weighted
Average
Common
Shares
Outstanding
- Basic 479.9 480.6 473.4 462.3 477.9 474.1 417.8
Effect of
Dilutive
Securities 4.4 3.8 4.5 3.6 4.7 5.6 4.8
-------------------------------------------------------------------------
Weighted
Average
Common
Shares
Outstanding
- Diluted 484.3 484.4 477.9 465.9 482.6 479.7 422.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------


12. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Unrecognized gains (losses) on risk management activities were as
follows:
As at
(C$ millions) December 31, 2003
-------------------------------------------------------------------------
Commodity Price Risk
Natural gas $ 76
Crude oil (361)
Gas storage optimization (32)
Power 5
Foreign Currency Risk 9
Interest Rate Risk 57
-------------------------------------------------------------------------
$ (246)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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.


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:

Unrecognized
Notional Gain/
Volumes Physical/ (Loss)
(MMcf/d) Financial Term Price (C$ millions)
-------------------------------------------------------------------------
Fixed Price
Contracts
Sales Contracts
Fixed AECO
price 453 Financial 2004 6.20 C$/mcf $ 7
NYMEX Fixed
price 732 Financial 2004 5.13 US$/mcf (111)
Chicago Fixed
price 40 Financial 2004 5.41 US$/mcf (1)
AECO Collars 71 Financial 2004 5.34-7.52 C$/mcf 2
NYMEX Collars 50 Physical 2004 2.46-4.90 US$/mcf (21)

NYMEX Collars 50 Physical 2005 2.46-4.90 US$/mcf (17)

2006-
NYMEX Collars 46 Physical 2007 2.46-4.90 US$/mcf (26)

Basis Contracts
Sales Contracts
Fixed NYMEX
to AECO basis 343 Financial 2004 (0.54) US$/mcf 28
Fixed NYMEX
to Rockies
basis 255 Financial 2004 (0.48) US$/mcf 23
Fixed NYMEX
to Rockies
basis 413 Physical 2004 (0.50) US$/mcf 34
Fixed NYMEX
to San Juan
basis 60 Financial 2004 (0.63) US$/mcf 1
Fixed NYMEX
to San Juan
basis 50 Physical 2004 (0.64) US$/mcf 1
Fixed Rockies
to CIG basis 38 Financial 2004 (0.10) US$/mcf -

Fixed NYMEX
to AECO
basis 877 Financial 2005 (0.66) US$/mcf 8
Fixed NYMEX
to Rockies
basis 283 Financial 2005 (0.49) US$/mcf 21
Fixed NYMEX
to Rockies
basis 393 Physical 2005 (0.47) US$/mcf 34
Fixed NYMEX
to San Juan
basis 75 Financial 2005 (0.63) US$/mcf (1)
Fixed NYMEX
to San Juan
basis 50 Physical 2005 (0.64) US$/mcf (1)
Fixed Rockies
to CIG basis 50 Financial 2005 (0.10) US$/mcf 1

Fixed NYMEX 2006-
to AECO basis 402 Financial 2008 (0.65) US$/mcf 31
Fixed NYMEX
to Rockies 2006-
basis 175 Financial 2008 (0.57) US$/mcf 17
Fixed NYMEX
to Rockies 2006-
basis 207 Physical 2007 (0.49) US$/mcf 29
Fixed NYMEX
to San Juan
basis 62 Financial 2006 (0.62) US$/mcf (1)
Fixed NYMEX
to San Juan
basis 42 Physical 2006 (0.64) US$/mcf (1)
Fixed Rockies 2006-
to CIG basis 31 Financial 2007 (0.10) US$/mcf -

Purchase
Contracts
Fixed NYMEX
to AECO basis 47 Financial 2004 (0.80) US$/mcf (4)
-------------------------------------------------------------------------
53
Gas Marketing
Financial
Positions(1) (2)
Gas Marketing
Physical
Positions(1) 25
-------------------------------------------------------------------------
$ 76
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) The gas marketing activities are part of the daily ongoing operations
of the Company's proprietary production management.


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:

Unrecognized
Notional Average Gain/
Volumes Price (Loss)
(bbl/d) Term (US$/bbl) (C$ millions)
-------------------------------------------------------------------------
Fixed WTI NYMEX Price 62,500 2004 23.13 $ (209)
Collars on WTI NYMEX 62,500 2004 20.00-25.69 (148)
3-way Put Spread 10,000 2005 20.00/25.00/28.77 (4)
-------------------------------------------------------------------------
(361)
Crude Oil Marketing
Financial Positions(1) (3)
Crude Oil Marketing
Physical Positions(1) 3
-------------------------------------------------------------------------
$ (361)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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:


Unrecognized
Notional Gain/
Volumes Price (Loss)
(bcf) (US$/mcf) (C$ millions)
-------------------------------------------------------------------------
Financial Instruments
Purchases 286.7 5.63 $ 141
Sales 312.4 5.69 (170)
-------------------------------------------------------------------------
(29)
Physical Contracts (3)
-------------------------------------------------------------------------
$ (32)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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.

For further information: on EnCana Corporation is available on the company's Web site, www.encana.com,
or Investor contact:
EnCana Corporate Development, Sheila McIntosh, Vice-President, Investor Relations, (403) 645-2194; Greg Kist,
Manager, Investor Relations, (403) 645-4737; Tracy Weeks, Manager, Investor Relations, (403) 645-2007;

Media contact: Alan Boras, Manager, Media Relations, (403) 645-4747

ECA stock price

TSX $14.27 Can 0

NYSE $11.11 USD 0

As of 2017-12-15 16:03. Minimum 15 minute delay