EnCana's Third Quarter cash flow up 32% to $1.4 billion, earning nearly double to $400 million

CALGARY, October 28, 2003 - EnCana Corporation's (TSX & NYSE: ECA) continued
growth in oil and gas sales combined with strong commodity prices generated
cash flow of $1.4 billion, or $2.81 per common share diluted, during the third
quarter of 2003, up 32 percent from $1.02 billion during the third quarter of
2002. Earnings were $400 million, or 82 cents per common share diluted, up
96 percent from earnings of $204 million in the third quarter of 2002.
Revenues, net of royalties and production taxes, in the third quarter of 2003
were $3.1 billion. Capital investment, excluding acquisitions and
dispositions, was $1.85 billion.

Growth from existing assets on track in third quarter of 2003
Third quarter oil, natural gas liquids (NGLs) and natural gas sales,
excluding Syncrude, averaged 745,000 barrels of oil equivalent (BOE) per day,
up more than 9 percent compared to sales of 682,000 barrels of oil equivalent
per day during the third quarter of 2002. Daily natural gas sales increased
more than 10 percent to average 2.96 billion cubic feet compared to
2.69 billion cubic feet during the third quarter of 2002. Oil and NGLs sales,
excluding Syncrude, increased more than 7 percent, averaging 252,000 barrels
per day, compared to 234,000 barrels per day in the third quarter of 2002.
EnCana drilled 1,830 net wells in the third quarter of 2003.

Investment focused on growth and returns
"EnCana's investment strategy is focused on achieving both strong growth
and strong returns, a combination aimed at continuously increasing the
intrinsic value of every share. Through 2003, we have divested of assets that
have not met our stringent financial return thresholds, such as our Syncrude
interest, which represented 32,000 barrels per day, or about 4 percent of
EnCana's production. We have redeployed a portion of those sale proceeds into
buying about 20 million of our shares for cancellation, representing about
4.25 percent of the shares outstanding in October 2002. We believe this to be
a value creating strategy for EnCana's shareholders, given the confidence we
have in the ability of our asset base to produce low-risk, high-return
growth," said Gwyn Morgan, EnCana's President & Chief Executive Officer.

Organic growth from underlying assets on track at 10 percent in 2003
EnCana is on track to achieve about 10 percent organic production growth
from continuing operations in 2003. Excluding Syncrude, total pro forma
production in 2002 was 687,000 barrels of oil equivalent per day. Strong
production increases are underway in the fourth quarter, putting the company
on pace to achieve sales this year approaching the midpoint of its guidance,
which is between 740,000 and 797,000 barrels of oil equivalent per day.
On an all in basis, including discontinued Syncrude operations, EnCana's
pro forma sales for 2002 were 722,500 barrels of oil equivalent per day.
Comparing this to total forecast sales in 2003, and forecast reduction in
shares outstanding from year-end 2002 to year-end 2003, puts EnCana on track
to achieve an all in production per share growth rate in 2003 in excess of
10 percent.

Fourth quarter production rising in several regions
"In Ecuador, the recent completion of the new export pipeline has nearly
doubled production to more than 96,000 barrels of oil per day. In the U.K.
central North Sea, we have taken over operatorship of the Scott Telford
production platform and increased our ownership in the project by 14 percent,
resulting in an increase in our sales to about 17,000 barrels of oil
equivalent per day," Morgan said.
"In North America, our U.S. Rockies, British Columbia and southern
Alberta resource plays are fuelling profitable gas growth. We drilled more
than 1,800 net wells across the continent during the third quarter, most of
which are yet to come on stream. An estimated 1,400 completed gas wells are
expected to be tied into gathering systems during the fourth quarter, adding
about 200 million cubic feet of gas production per day," Morgan said.
The company is on target to achieve its 2003 sales forecast of between
740,000 and 797,000 barrels of oil equivalent per day. To date in October,
sales are averaging more than 810,000 barrels of oil equivalent per day,
comprised of 3.1 billion cubic feet of gas and 300,000 barrels of oil and
NGLs. EnCana expects to exit the year producing between 820,000 and 840,000
barrels of oil equivalent per day from continuing assets - up more than
12 percent from the 2002 exit rate and well within the company's forecast 2004
sales range of between 805,000 and 885,000 barrels of oil equivalent per day.

Major new resource play at Cutbank Ridge
In September, EnCana announced the capture of a major new resource play
at Cutbank Ridge covering about 500,000 net acres near the foothills of
British Columbia and Alberta and containing an estimated 4 trillion cubic feet
of recoverable gas. Similar to the company's resource plays at Greater Sierra
in northeast B.C., Jonah in Wyoming, Mamm Creek in Colorado and Palliser and
Suffield in southern Alberta, Cutbank Ridge is expected to deliver steady,
profitable, long-life production growth for many years to come. The productive
Cadomin geological formation underlying Cutbank Ridge lands is an expansive
gas-charged reservoir where EnCana believes it can apply its proven assembly-
line, resource play management system to generate several hundred million
cubic feet of daily gas production in the years ahead. With Cutbank Ridge
added to its portfolio, EnCana is now estimating that, beyond its proved and
risked probable booked reserves, the company's existing lands contain unbooked
resource potential of approximately 11 trillion cubic feet of gas and
650 million barrels of oil. Over the coming years, EnCana expects to convert
these resources to reserves.

All references to production, sales and financial information for the
first nine months of 2002 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. All dollar figures are Canadian unless
otherwise stated.

Nine months cash flow hits $4.6 billion, net earnings $2.7 billion
During the first nine months of 2003, EnCana's net earnings increased
229 percent from the first nine months of 2002 to $2.7 billion, or $5.60 per
common share diluted. Net earnings include gains totalling $406 million after
tax, or 83 cents per common share diluted, as a result of foreign exchange
translation on U.S. dollar denominated debt. While the stronger Canadian
dollar results in gains on the U.S. dollar denominated debt, it adversely
impacts the average net Canadian dollar price realized by the company on its
sales of oil, NGLs and natural gas, which are either directly denominated in
U.S. dollars or denominated in Canadian dollars but closely tied to U.S.
currency. Cash flow for the first nine months of 2003 was up 69 percent over
the same period of 2002 to $4.6 billion, or $9.55 per common share diluted.
Revenues, net of royalties and production taxes, in the first nine months were
$10.4 billion. Capital investment in the first nine months, excluding
acquisitions and dispositions, was $4.9 billion.

North American natural gas industry prices remain strong
Natural gas prices across North America remained strong due to marginally
lower supplies in the U.S. and Canada and the need to replenish the low
storage levels at the end of last winter. In the third quarter, the average
benchmark NYMEX index price was US$4.97 per thousand cubic feet, up 56 percent
from the third quarter of 2002. North American storage injections increased
during the summer months taking gas storage levels close to long-term
averages. In the third quarter, the company's average realized field gate
natural gas price, excluding hedging, was C$5.88 per thousand cubic feet;
including hedging it was C$5.81 per thousand cubic feet.

World oil prices remain strong in the wake of continued supply
uncertainty
During the third quarter, the average benchmark West Texas Intermediate
crude oil price was US$30.21 per barrel, up 7 percent over the same period
last year. The Organization of Petroleum Exporting Countries' decision to cut
oil supplies by 900,000 barrels per day effective November 1, 2003 and
uncertainty regarding Iraqi production continue to support world oil prices at
relatively high levels. EnCana's third quarter average realized oil and NGLs
price, excluding hedging, was C$28.24 per barrel; including hedging it was
C$25.63 per barrel.

Risk management programs help mitigate volatility
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
in order to lock in financial returns and reduce cash flow at risk. EnCana has
about 40 percent of projected 2004 gas sales, after royalties, hedged at an
average effective NYMEX price of about US$5.23, based upon a 1.32 C$/US
exchange rate and a US$0.73 per thousand cubic feet AECO basis for Canadian
conversions. About half of EnCana's projected 2004 oil sales, after royalties,
are hedged or subject to costless collars between US$20 and US$26 WTI. The
detailed risk management positions at September 30, 2003 are presented in
Note 10 to the third quarter Consolidated Financial Statements. With strong
oil and gas prices and changes to exchange rates in the third quarter,
EnCana's financial commodity price and currency risk management measures
resulted in revenue being lower by approximately $81 million, comprised of
$61 million on oil sales and $20 million on gas sales.

<<

Consolidated Highlights
-----------------------

-------------------------------------------------------------------------
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Financial Highlights
(unaudited)
(as at and for the
periods ended 9 Months
September 30) Q3 Q3 9 Months 2002
($ millions, except 2003 2002 2003 Pro
per share amounts) Actuals Actuals Actuals forma(2)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Revenues, net of royalties and
production taxes 3,116 2,741 10,378 7,489
-------------------------------------------------------------------------
Cash Flow 1,352 1,022 4,642 2,739
Per common share - diluted 2.81 2.12 9.55 5.66
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Net earnings 400 204 2,712 825
Per common share - basic(1) 0.83 0.43 5.69 1.74
Per common share - diluted 0.82 0.42 5.60 1.70

Less:
Foreign exchange gain (loss)
on translation of US$ debt
(after-tax) 14 (145) 406 17
Per common share - basic 0.03 (0.30) 0.85 0.04
Per common share - diluted 0.03 (0.30) 0.83 0.04

Less:
Tax rate change gain - - 486 42
Per common share - basic - - 1.02 0.09
Per common share - diluted - - 1.00 0.09
-------------------------------------------------------------------------
Net earnings, excluding above
gains (losses) 386 349 1,820 766
Per common share - basic 0.80 0.73 3.82 1.61
Per common share - diluted 0.79 0.72 3.77 1.57
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Capital investment 1,849 1,440 4,880 4,084
-------------------------------------------------------------------------
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at
Dec. 31/02

Total assets 30,212 31,322
Long-term debt 7,103 7,395
Preferred securities 549 583
Shareholders' equity 14,953 13,794

Debt-to-capitalization ratio 33% 31%
(adjusted for working capital
& including preferred securities
as debt)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Common shares (millions)
Outstanding at September 30 465.0 477.4 465.0 477.4
Weighted average (diluted) 480.5 482.2 486.3 483.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------


(1)Impact of including share options in earnings calculations
If EnCana were to record compensation expense for outstanding share
options, net earnings per common share - basic would have been $5.58 per
common share, 11 cents per common share less, for the first nine months
of 2003.

(2)Important Notice: Readers are cautioned that comparisons to 2002 nine
months results are based on 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.


Operating Highlights 9 Months
(for the 9 Months 2002
period ended Q3 2003 Q3 2002 % 2003 Pro %
September 30) Actuals Actuals Change Actuals forma(2) Change
-------------------------------------------------------------------------

Sales
Natural gas (MMcf/d)
North America 2,954 2,679 +10 2,955 2,654 +11
U.K. 7 9 -22 11 10 +10
Total natural gas
(MMcf/d) 2,961 2,688 +10 2,966 2,664 +11

Oil and NGLs
(bbls/d)
North America 192,385 169,069 +14 184,523 166,572 +11
Ecuador 53,543 55,579 -4 48,667 51,467 -5
U.K. 5,813 9,538 -39 8,463 11,453 -26
Total oil and
NGLs(*) (bbls/d) 251,741 234,186 +7 241,653 229,492 +5
-------------------------------------------------------------------------
Total sales
(BOE/d)(*) 745,241 682,186 +9 735,986 673,492 +9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Prices
Natural Gas ($/Mcf)
Including hedging
Canada 5.76 3.53 +63 6.37 3.68 +73
U.S. 5.94 3.73 +59 6.68 3.61 +85
Excluding hedging
Canada 5.80 3.24 +79 6.71 3.56 +88
U.S. 6.11 3.16 +93 6.57 3.33 +97
-------------------------------------------------------------------------
Total North American
gas ($/Mcf)
Including hedging 5.81 3.56 +63 6.45 3.67 +76
Excluding hedging 5.88 3.21 +83 6.68 3.52 +90
-------------------------------------------------------------------------
Oil and NGLs ($/bbl)
Including hedging
North American oil
Light/medium 28.51 35.12 -19 31.08 31.56 -2
Heavy 20.01 28.55 -30 21.94 25.62 -14
International oil
Ecuador 28.40 33.59 -15 33.27 29.97 +11
U.K. 35.79 39.30 -9 38.37 35.72 +7
Natural gas liquids 33.10 31.18 +6 36.01 27.93 +29

Excluding hedging
North American oil
Light/medium 32.59 36.01 -9 36.56 32.65 +12
Heavy 23.96 29.44 -19 27.05 26.14 +3
International oil
Ecuador 28.40 33.59 -15 33.27 29.97 +11
U.K. 35.79 39.30 -9 38.37 35.83 +7
Natural gas liquids 33.10 31.18 +6 36.01 27.93 +29
-------------------------------------------------------------------------
Total oil and NGLs
($/bbl)
Including hedging 25.63 32.27 -21 28.75 29.09 -1
Excluding hedging 28.24 32.83 -14 32.12 29.59 +9
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(*) Excludes EnCana's share of Syncrude volumes, which averaged 3,401
barrels per day in the third quarter of 2003, compared to 36,039 barrels
per day in the third quarter of 2002. For the first nine months of 2003,
Syncrude volumes averaged 10,291 barrels per day, compared to 30,644
barrels per day in the same period in 2002.


Corporate developments
----------------------

Normal Course Issuer Bid purchases
In the past 12 months, EnCana invested approximately $1 billion to
purchase 20,224,400 common shares, representing approximately 4.25 percent of
the company's outstanding shares on October 21, 2002, at an average price of
$50.35 per common share. These purchases more than offset the approximately
4.8 million shares issued to date this year as a result of the exercise of
share purchase options. On October 14, 2003 the company's total common shares
outstanding was 464,246,813.

Normal Course Issuer Bid renewed
EnCana has received approval for the renewal of the company's Normal
Course Issuer Bid from the Toronto Stock Exchange. Under the renewed bid,
which commenced on October 22, 2003, EnCana may, over a 12-month period,
purchase for cancellation up to 23,212,341 of its common shares, representing
5 percent of the 464,246,813 common shares outstanding as at October 14, 2003.
The price paid will be the market price at the time of acquisition.

Dividend
The board of directors of EnCana declared a quarterly dividend of
10 cents per share payable on December 31, 2003 to common shareholders of
record as of December 12, 2003.

Cash tax outlook
EnCana's estimate of normalized annual cash tax expense, with its current
projected production, commodity prices, capital investment and exchange rate
profile, is about $500 million per year. Largely as a result of the business
reorganization arising from the merger, this pattern has shifted for 2003 and
2004. In 2003, cash taxes are expected to be about $400 million lower than the
normalized level, while 2004 cash taxes are expected to be higher by a similar
amount. For 2005, the company is expected to return to more normalized annual
levels of cash tax.

U.S. protocol reporting of financial and operating results
Starting with year-end 2003, EnCana plans to report its financial and
operating results following U.S. protocols in order to facilitate a more
direct comparison to other North American upstream exploration and development
companies. Financial results will be in U.S. dollars and EnCana's operating
results, namely production and reserves, will be reported on an after-
royalties basis. EnCana will also provide convenience statements prepared in
Canadian dollars, along with operating results following Canadian protocols -
production and reserves reported on a before-royalties basis.

Forecast of 10 percent internal sales growth in 2003 and 2004 confirmed
Total 2003 daily sales volumes from continuing operations are forecast to
increase approximately 10 percent from pro forma 2002 levels, averaging
between 740,000 and 797,000 barrels of oil equivalent, which is comprised of
between 3 billion and 3.1 billion cubic feet of gas per day and 240,000 and
280,000 barrels of oil and NGLs per day. In 2004, daily sales are expected to
average between 805,000 and 885,000 barrels of oil equivalent, comprised of
natural gas sales between 3.25 billion and 3.45 billion cubic feet per day and
265,000 and 310,000 barrels of oil and NGLs per day, representing a 10 percent
increase from the midpoint of forecast 2003 sales levels.

Financial strength
------------------

EnCana has a strong balance sheet. At September 30, 2003, the company's
debt-to-capitalization ratio was 33:67 (preferred securities included as
debt). EnCana's Debt-to-EBITDA multiple, on a trailing 12-month basis, was
1.1 times. Third quarter capital investment was $1,849 million. Divestiture
proceeds, net of acquisitions, were about $300 million.
On October 2, 2003, EnCana completed a public offering in the United
States of US$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 September 30, 2003, on a pro forma basis,
taking into account this offering, approximately 53 percent of EnCana's
outstanding debt was in U.S. dollars and 72 percent of total debt was long-
term fixed rate. EnCana has received strong investment grade credit ratings
from the major bond 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. The company also has a $4 billion credit facility with a
syndicate of major banks and lending institutions, of which more than
$1.78 billion remains unutilized at September 30, 2003.
Year to date core capital investment, before acquisitions and
dispositions, was about $4.6 billion, while acquisitions were about
$600 million and divestiture proceeds were about $2.4 billion, resulting in
net capital investment of about $2.8 billion in the first nine months.


Capital investment update

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EnCana 2003 forecast capital program
-------------------------------------------------------------------------

$ (millions)
-------------------------------------------------------------------------
Upstream
Offset production declines (estimated) 2,600
2003 and part of 2004 growth (estimated) 1,700
Exploration and long term development 600
Cutbank Ridge land purchase 400
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Upstream total 5,300
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Midstream
Original forecast 500
OCP Pipeline additional requirements 100
-------------------------------------------------------------------------
Midstream total 600
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Core Capital total (forecast) 5,900
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Other
Leased equipment purchases(*) 300
Minor corporate acquisitions 300
-------------------------------------------------------------------------
Other total 600
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Divestitures
Express and Cold Lake pipelines(xx) (1,600)
Syncrude (1,500)
-------------------------------------------------------------------------
Divestitures total (3,100)
-------------------------------------------------------------------------
Net Capital Investment (forecast) 3,400
-------------------------------------------------------------------------
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(*) Represents the conversion of previous operating leases to EnCana
ownership.
(xx) $1.6 billion less $600 million of net assumption, by the
purchaser, of debt resulted in net cash proceeds of $1.0 billion.


EnCana's 2003 upstream core capital investment is expected to be about
$5.3 billion, an increase of about $400 million from the upper end of previous
guidance. It is directed as follows: about $2.6 billion to offset annual
production declines and about $1.7 billion for 2003 and a portion of 2004
production growth. Another $1 billion is directed to exploration, including
Cutbank Ridge and multi-year development projects such as the Buzzard field.
Total Midstream & Marketing capital is about $600 million. Minor corporate
acquisitions total about $300 million and divestitures will generate total
proceeds of $3.1 billion, resulting in a net 2003 capital investment forecast
of $3.4 billion.

Preliminary reserve replacement cost estimated at less than $10 per
barrel of oil equivalent
Based on the total upstream capital investment of about $5.9 billion,
which includes core capital investment, minor acquisitions and most of the
cost of purchases of previously leased equipment, the company's preliminary
2003 proved reserve replacement cost estimate will be similar to that reported
in 2002. In 2002, EnCana's proved reserve replacement cost was $9.60 per
barrel of oil equivalent.

Merger synergies update
EnCana estimates that it has implemented sustainable capital investment
synergies of about $250 million and one-time, non-recurring capital synergies
of about $380 million. EnCana has a tremendous inventory of investment
opportunities, which in the post-merger period have led to more selective
capital decisions yielding stronger economic metrics than either predecessor
company could have accomplished. The company is also on track to realize
annual recurring operating and administrative synergies of about $250 million
per year.
Operating costs averaged $4.14 per barrel of oil equivalent for the third
quarter of 2003 and $4.10 per barrel of oil equivalent for the first nine
months of 2003, which is at the high end of the company's $3.80 to $4.10 per
barrel of oil equivalent target. With production forecast to increase in the
fourth quarter, EnCana expects its per unit operating costs to decline
marginally.

Operational highlights
----------------------

North America
-------------

Third quarter natural gas and liquids sales up 11 percent year over year
North American gas, oil and NGLs sales, excluding Syncrude, continued to
grow in the third quarter, averaging 685,000 barrels of oil equivalent per day
- an 11 percent increase over the average of 616,000 barrels of oil equivalent
per day in the third quarter of 2002. Natural gas sales were up 10 percent,
averaging 2.95 billion cubic feet per day. Liquids sales, excluding Syncrude,
were up 14 percent year over year, averaging 192,000 barrels per day.
Production from the U.S. Rockies continues to achieve very strong year-over-
year growth. An earlier than normal winter break up in northern Canadian
locations and a wet spring across much of the Canadian plains resulted in a
three-month delay in much of the company's drilling program. Favourable
weather has enabled much of the delayed program to be completed during the
summer. An estimated 200 million cubic feet of daily production is expected to
be connected to gathering systems during the fourth quarter. As a result of
these delays, EnCana expects to achieve average 2003 gas sales volumes at the
low end of its guidance range, but to exit 2003 already within the range of
its 2004 gas sales guidance.
During the third quarter, the company did not inject gas production into
storage since prices remained relatively high, with the AECO price index
averaging $6.29 per thousand cubic feet of gas.
EnCana drilled 1,817 net wells in North America during the third quarter,
and currently has about 25 rigs running in the U.S. Rockies and about 80 rigs
across Western Canada.

USA region gas production surpasses 800 million cubic feet per day
Third quarter gas sales from the USA region rose 38 percent in the past
year to average 757 million cubic feet per day, compared to an average of
550 million cubic feet per day for the same period in 2002. October production
to date, which is largely from the Jonah field in Wyoming and the Mamm Creek
field in Colorado, is more than 800 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 764 million cubic feet per day of gas sales for the remainder of
2003 at an average basis of US$0.52 per thousand cubic feet, and an average of
520 million cubic feet per day of forecast gas sales for 2004 through 2007 at
an average basis of US$0.49 per thousand cubic feet.
"The Mamm Creek field, which we purchased in early 2001, is a classic
resource play asset. Its production and reserves continue to grow and this low
decline gas field has a large unbooked resource potential. In each of the past
two years we have doubled daily gas production, from 35 million in 2001, to
70 million in 2002 and we are targeting a 2003 average of approximately
150 million cubic feet. At the same time, our costs to drill and complete a
well have decreased by about 25 percent. With about 20 rigs currently drilling
in the area, we are expecting continued strong performance from this high-
growth asset," said Roger Biemans, President of EnCana's USA region.
In the Gulf of Mexico, EnCana holds a 25 percent interest in the
recently-announced Sturgis deepwater discovery in Atwater Valley block 183,
about 240 kilometres southeast of New Orleans, Louisiana. Located in about
3,700 feet of water, the Sturgis No. 1 well encountered more than 100 feet of
net pay of hydrocarbon-bearing sands. A subsequent side-track wellbore was
drilled to a depth of 27,739 feet.
"Along with our earlier success this year in our appraisal drilling
program at Tahiti, we are very encouraged by this latest find. We look forward
to additional appraisal drilling at Sturgis by the operator - ChevronTexaco,"
said Gerry Macey, EnCana's President of International New Ventures
Exploration.

Second major resource play added in northeast British Columbia at Cutbank
Ridge
Over the past 18 months, EnCana has assembled more than 500,000 net acres
(about 780 sections) of prospective lands that the company believes constitute
a major new resource play at Cutbank Ridge near the foothills of the Canadian
Rocky Mountains. Straddling the B.C.-Alberta border, EnCana's Cutbank Ridge
lands are estimated to contain more than 4 trillion cubic feet of recoverable
gas.
"We believe Cutbank Ridge will perform like our other resource plays at
Greater Sierra in northeast B.C., the Jonah field in Wyoming, Mamm Creek in
Colorado and Palliser and Suffield in southern Alberta. It's exactly the type
of large-scale resource play we strive to capture and develop, one with the
potential to generate several hundred million cubic feet per day of long-life,
low decline gas production for many years to come," said Randy Eresman,
EnCana's Chief Operating Officer. "These are the kinds of assets where we
believe we can grow both production and reserves while our highly-focused
business unit teams drive down costs by applying our proven resource play
management system."
Cutbank Ridge is estimated to contain 6 billion cubic feet of recoverable
natural gas per section. The initial cost of drilling and completing each
horizontal well, including gathering pipelines and facilities, is estimated at
about $4 million. All in, full-life-cycle finding and development costs at
Cutbank Ridge are expected to be about $1.50 per thousand cubic feet of gas,
which should make the investment highly profitable.

Greater Sierra builds upon summer drilling program
EnCana's Greater Sierra project is nearing the completion of 80 summer
wells, more than double the number EnCana had planned earlier this year. With
the positive changes in the B.C. government's royalty regime for summer
drilling and its commitment to improve road infrastructure, EnCana has stepped
up its development at Greater Sierra. Production is currently about
220 million cubic feet per day and once summer wells are tied in, sales are
expected to exit the year near 300 million cubic feet per day. As well,
construction of EnCana's new Ekwan Pipeline is expected to start 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 planned start-up by
the second quarter of 2004, the Ekwan Pipeline is expected to facilitate
continued sales growth from northeast British Columbia.

Coalbed methane development expands
EnCana is continuing to obtain technical and operational data required
for large-scale coalbed methane (CBM) development on its 100-percent-owned
shallow gas lands east of Calgary. EnCana's commercial demonstration project
is producing about 3 million cubic feet of gas per day from about 35 wells.
During the last half of 2003, the company is drilling an additional 100 wells
that are expected to take production to about 10 million cubic feet per day by
year-end.

Suffield and Pelican Lake surpassing expectations
Heavy oil production growth at Suffield in southeast Alberta has risen
21 percent to over 40,000 barrels per day since the beginning of the year.
Performance of EnCana's Pelican Lake waterflood project in northeast Alberta
is exceeding expectations as production to date in 2003 has averaged 16,000
barrels per day, up about 20 percent from initial forecasts. Based on the
strong response from the 60 horizontal water injector wells turned on since
project initiation in early 2002, Pelican Lake production is expected to rise
more than 25 percent in 2004 to more than 20,000 barrels per day.

New phase underway for SAGD growth at Foster Creek
EnCana is injecting steam into its first expansion at Foster Creek in
northeast Alberta, where oil production averaged more than 22,000 barrels per
day during the third quarter. The six well pair expansion is expected to take
total EnCana SAGD production, which includes other projects, to approximately
35,000 barrels per day by mid 2004.

East Coast - encouraging exploration results
EnCana has completed the drilling of two exploration wells near its Deep
Panuke natural gas field, about 250 kilometres southeast of Halifax.
Preliminary results from both wells - Margaree and MarCoh - are encouraging.
EnCana holds 100 percent of Margaree and has 24.5 percent of MarCoh, where
ExxonMobil owns 51 percent and Shell Canada holds 24.5 percent. In February
2003, EnCana initiated a comprehensive review of its Deep Panuke project in
order to strengthen the anticipated economics of field development. The
drilling results from Margaree and MarCoh will be incorporated into the
company's overall review. EnCana plans to update federal and provincial
regulators on the status of its Deep Panuke evaluation in December.
"It is still too early to know precisely how development of this
promising field may unfold. However, we are certainly encouraged by this
additional drilling, which increases our confidence in the size of the reserve
and the development potential at Deep Panuke," Eresman said.

International
-------------

Third quarter oil sales from international operations averaged about
59,400 barrels of oil per day, down about 9 percent compared to the third
quarter last year. With the OCP Pipeline in operation and EnCana's expanded
ownership in the Scott and Telford oil fields, October daily oil production to
date from international locations is now more than 110,000 barrels of oil
equivalent per day.

Fourth quarter Ecuador production expected to double
Third quarter sales in Ecuador averaged about 53,500 barrels of oil per
day, down about 4 percent from an average of about 55,600 barrels per day one
year earlier. The lower sales are due largely to the delivery of about 6,800
barrels per day during the quarter for use as line fill on the new OCP
Pipeline, which recently completed and passed performance testing. EnCana had
hoped OCP would be completed early in the summer, but a significant volcanic
eruption and subsequent mud flows, which occurred as pipeline construction was
nearing completion, delayed the initial start date. However, with the opening
of the pipeline in early September, EnCana has now taken its Ecuador
production to more than 96,000 barrels per day, well on the way to the
company's 2004 target of more than 100,000 barrels per day of production. In
September, EnCana sold three tanker loads carrying more than 1.7 million
barrels of Napo, the new OCP crude oil blend.
"Ecuador has entered a new era in its economic and industrial
development. The opening of the first privately owned and operated pipeline,
where EnCana indirectly holds a 36 percent interest, is expected to attract
new investment to the country. We are continuing to develop our existing land
base and look for new lands to further expand our production," said Don
Swystun, President of EnCana's Ecuador region.

EnCana increases stake in North Sea's Scott and Telford fields and takes
over operatorship
On October 1, 2003, EnCana completed its acquisition of an additional
14 percent interest in each of the Scott and Telford oil fields. The company
took over operatorship of the Scott Telford production platform on October 1
and now holds 27.5 percent of the Scott field and 34.2 percent of the Telford
field. Net production is currently about 17,000 barrels of oil equivalent per
day.
During the fourth quarter, the U.K. Department of Industry and Trade is
expected to conclude its regulatory review of EnCana's development plan for
the North Sea's Buzzard oil field, estimated to contain more than 400 million
barrels of recoverable reserves. Preliminary selection of Aker Verdal of
Norway to construct three steel jackets has been announced. Bids for
additional components are being reviewed. Provided that regulatory and partner
approval is received, Buzzard is expected to start production in late 2006.
EnCana, the operator, holds approximately 43 percent of Buzzard, which is
expected to produce about 75,000 barrels per day of light, royalty free oil
net to EnCana at peak production.

Midstream & Marketing
---------------------
EnCana's Midstream & Marketing division generated $19 million of
operating cash flow in the third quarter of 2003. With the strong prices for
natural gas through the first three quarters of 2003, and lower than expected
seasonal price differentials during much of the year, EnCana has seen lower
prices bid for storage capacity and reduced opportunities for storage
optimization as compared to previous years.
During the year, the company changed its focus on the utilization of
Midstream & Marketing's proprietary storage capacity. EnCana's proprietary
production will not normally be injected into storage except to mitigate
short-term operational or transportation constraints. Proprietary storage
capacity will now be utilized by the company's gas storage business unit for
optimization activities and third party contracting.
During the fourth quarter, the company anticipates Midstream & Marketing
will achieve operating cash flow of approximately $40 million. Based on
current forward market gas prices we expect to capture significant margins on
our winter withdrawals of storage optimization volumes, but more heavily
weighted to realizations in the first quarter of 2004. Total operating cash
flow from Midstream & Marketing for 2003 is now expected to be approximately
$75 million, down from the previous estimate of $100 million to $130 million.

New Louisiana storage facility planned
EnCana Gas Storage is planning to build a new, high-deliverability gas
storage facility in southwest Louisiana. Starks Gas Storage L.L.C., an
indirect, wholly owned subsidiary of EnCana Gas Storage Inc., plans to develop
the project by converting existing underground brine caverns into a gas
storage facility with connections to a number of nearby, large-diameter gas
transmission pipelines. Located approximately 25 miles west of Lake Charles,
Louisiana, Starks plans to initially develop 8 billion cubic feet of gas
storage capacity with a withdrawal rate of approximately 400 million cubic
feet per day. Having completed the preliminary engineering work and secured
the property rights, Starks is now seeking customers with an interest in
booking capacity in the new facility. The project is anticipated to be fully
in-service by the third quarter of 2005.
EnCana continues to pursue expansions of its continental gas storage
network, primarily with the expansion of Wild Goose Storage in northern
California, and the completion of the first phase of the Countess gas storage
facility east of Calgary. The Wild Goose expansion, scheduled for completion
in April 2004, will raise total working gas capacity by 10 billion cubic feet
to approximately 24 billion cubic feet, plus expand daily withdrawal
capability by 140 percent to 480 million cubic feet per day and daily
injection capability more than fivefold to 450 million cubic feet per day. The
first phase of the Countess facility, scheduled for start-up November 1 of
this year, has 10 billion cubic feet of gas in inventory and available for
withdrawal during the coming winter. Two additional phases of Countess are
planned to take capacity to about 30 billion cubic feet in 2004 and 40 billion
cubic feet in 2005.

-------------------------------------------------------------------------
FINANCIAL INFORMATION

NOTE: All financial information in this news release reflects actual
results, except for the company's 2002 pro forma nine-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 first nine
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
convenience financial statements prepared in U.S. dollars, 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, Tuesday,
October 28, 2003 starting at 11 a.m., Mountain Time (1 p.m. Eastern
Time), to discuss EnCana's third quarter 2003 financial and operating
results.

To participate, please dial (719) 457-2623 approximately 10 minutes prior
to the conference call. An archived recording of the call will be
available from approximately 5 p.m. on October 28 until midnight
November 2, 2003 by dialing (888) 203-1112 or (719) 457-0820 and entering
pass code 178873.

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

EnCana Corporation
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. It has an enterprise value of approximately C$30 billion. 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 - In the interest of providing EnCana Corporation ("EnCana" or
the "Company") shareholders and potential investors with information regarding
the Company, certain statements throughout this news release constitute
forward-looking statements within the meaning of the United States Private
Securities Litigation Reform Act of 1995. Forward-looking statements are
typically identified by words such as "anticipate", "believe", "expect",
"plan", "intend", "forecast", "target", "project" or similar words suggesting
future outcomes or statements regarding an outlook. Forward-looking statements
in this news release include, but are not limited to, statements with respect
to: projected cash taxes for 2003, 2004 and beyond; projected oil shipment
volumes through the OCP Pipeline by the end of 2003 and in 2004 and beyond,
and the impact of the OCP Pipeline on investment in Ecuador; the timing for
completion of the various phases of the Countess, Wild Goose and Starks gas
storage projects, and storage capacities, injection and withdrawal rates
expected upon completion; the effect of certain forward contracts; the
production, growth and growth potential, including the Company's plans
therefor, with respect to EnCana's various assets and initiatives, including
assets and initiatives in North America, Ecuador, the U.K. central North Sea
and the Gulf of Mexico; projections relating to the Company's coalbed methane
and SAGD projects and initiatives; production and sales targets for oil,
natural gas and natural gas liquids for 2003 and 2004; the timing for
completion of regulatory review and the commencement of production from the
Buzzard project, and expected production rates therefrom; the Company's
projected capital investment levels for 2003; projected operating costs and
finding and development costs for 2003; the Company's execution of share
purchases under its Normal Course Issuer Bid; projections for wells and
production to be tied into gathering systems during the fourth quarter of
2003, and production increases expected therefrom; projected unbooked resource
potential available from various assets and initiatives; expectations
regarding 2003/2004 winter gas prices; gas storage levels for 2003 and 2004;
projected cash flow for 2003 from the Midstream & Marketing division;
estimated sustainable capital investment, operating and administrative
synergies; the projected per share growth rate for 2003; the projected sales
growth rate for 2003 and 2004; the impact of the company's investment strategy
on future share value; the company's estimate of its ability to convert
unbooked resource potential to reserves; plans to report financial and
operating results following U.S. protocols and in U.S. dollars; 2003 proved
reserves replacement cost; projected future usage plans for the company's
proprietary gas storage facilities; the projected profitability and margins
which may be achieved from various projects and initiatives, including Cutbank
Ridge and gas storage operations, and the timing for completion and capacity
of the Ekwan Pipeline project.
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 reserve 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 international war,
hostilities, civil insurrection and instability affecting countries in which
the Company operates and international terrorist threats; risks associated
with existing and potential future lawsuits and regulatory actions brought
against the Company; the risk that the anticipated synergies to be realized by
the merger of AEC and the Company will not be realized; costs relating to the
merger of AEC and the Company 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. Statements relating to
"reserves", "resources", and "resource potential" are deemed to be forward-
looking statements, as they involve the implied assessment, based on certain
estimates and assumptions that the reserves and resources described exist in
the quantities predicted or estimated, and can be profitably produced in the
future. 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.


Consolidated Financial Statements

For the period ended September 30, 2003

EnCana Corporation




Interim Report
For the period ended September 30, 2003

EnCana Corporation
CONSOLIDATED STATEMENT OF EARNINGS

September 30
--------------------------------
Three Months Nine Months
Ended Ended
(unaudited) ($ millions, except --------------------------------
per share amounts) 2003 2002 2003 2002
-------------------------------------------------------------------------
REVENUES, NET OF ROYALTIES AND
PRODUCTION TAXES (Note 3) $ 3,116 $ 2,741 $10,378 $ 6,388
-------------------------------------------------------------------------
EXPENSES (Note 3)
Transportation and selling 173 174 537 380
Operating 445 350 1,372 869
Purchased product 955 1,041 3,458 2,317
Administrative 56 50 172 111
Interest, net 87 112 257 242
Foreign exchange (gain) loss (Note 5) (25) 156 (560) (24)
Depreciation, depletion and
amortization 748 605 2,211 1,392
-------------------------------------------------------------------------
2,439 2,488 7,447 5,287
-------------------------------------------------------------------------
NET EARNINGS BEFORE THE
UNDERNOTED 677 253 2,931 1,101
Income tax expense (Note 6) 278 126 513 361
Distributions on Subsidiary
Preferred Securities,
net of tax - 11 - 11
-------------------------------------------------------------------------
NET EARNINGS FROM CONTINUING
OPERATIONS 399 116 2,418 729
NET EARNINGS FROM DISCONTINUED
OPERATIONS (Note 4) 1 88 294 66
-------------------------------------------------------------------------
NET EARNINGS $ 400 $ 204 $ 2,712 $ 795
DISTRIBUTIONS ON PREFERRED
SECURITIES, NET OF TAX 7 1 (8) 2
-------------------------------------------------------------------------
NET EARNINGS ATTRIBUTABLE TO
COMMON SHAREHOLDERS $ 393 $ 203 $ 2,720 $ 793
-------------------------------------------------------------------------
NET EARNINGS FROM CONTINUING
OPERATIONS PER COMMON SHARE (Note 9)
Basic $ 0.83 $ 0.24 $ 5.08 $ 1.83
Diluted $ 0.82 $ 0.24 $ 5.00 $ 1.80
-------------------------------------------------------------------------
NET EARNINGS PER COMMON SHARE (Note 9)
Basic $ 0.83 $ 0.43 $ 5.69 $ 1.99
Diluted $ 0.82 $ 0.42 $ 5.60 $ 1.96
-------------------------------------------------------------------------



CONSOLIDATED STATEMENT OF RETAINED EARNINGS

Nine Months
Ended
September 30
-----------------
(unaudited) ($ millions) 2003 2002
-------------------------------------------------------------------------
RETAINED EARNINGS, BEGINNING OF YEAR $ 4,684 $ 3,630
Net Earnings 2,712 795
Dividends on Common Shares and Other
Distributions, net of tax (135) (122)
Charges for Normal Course Issuer Bid (Note 8) (503) -
-------------------------------------------------------------------------
RETAINED EARNINGS, END OF PERIOD $ 6,758 $ 4,303
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.


EnCana Corporation
CONSOLIDATED BALANCE SHEET

As at As at
September December
(unaudited) ($ millions) 30, 2003 31, 2002
-------------------------------------------------------------------------
ASSETS
Current Assets
Cash and cash equivalents $ 335 $ 183
Accounts receivable and accrued revenue 1,295 1,987
Inventories 1,046 528
Assets of discontinued operations (Note 4) - 3,422
-------------------------------------------------------------------------
2,676 6,120
Capital Assets, net (Note 3) 24,440 22,356
Investments and Other Assets 627 377
Goodwill 2,469 2,469
-------------------------------------------------------------------------
(Note 3) $ 30,212 $ 31,322
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued liabilities $ 1,964 $ 2,282
Income tax payable 208 20
Liabilities of discontinued operations (Note 4) - 1,758
Current portion of long-term debt (Note 7) 50 212
-------------------------------------------------------------------------
2,222 4,272
Long-Term Debt (Note 7) 7,103 7,395
Deferred Credits and Other Liabilities 557 564
Future Income Taxes 5,377 4,840
Preferred Securities of Subsidiary - 457
-------------------------------------------------------------------------
15,259 17,528
-------------------------------------------------------------------------
Shareholders' Equity
Preferred securities 549 126
Share capital (Note 8) 8,527 8,732
Share options, net 98 133
Paid in surplus - 61
Retained earnings 6,758 4,684
Foreign currency translation adjustment (979) 58
-------------------------------------------------------------------------
14,953 13,794
-------------------------------------------------------------------------
$ 30,212 $ 31,322
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.


EnCana Corporation
CONSOLIDATED STATEMENT OF CASH FLOWS

September 30
--------------------------------
Three Months Nine Months
Ended Ended
--------------------------------
(unaudited) ($ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------
OPERATING ACTIVITIES
Net earnings from continuing
operations $ 399 $ 116 $ 2,418 $ 729
Depreciation, depletion and
amortization 748 605 2,211 1,392
Future income taxes (Note 6) 203 97 475 245
Other (3) 98 (467) (159)
-------------------------------------------------------------------------
Cash flow from continuing
operations 1,347 916 4,637 2,207
Cash flow from discontinued
operations 5 106 5 142
-------------------------------------------------------------------------
Cash flow 1,352 1,022 4,642 2,349
Net change in other assets
and liabilities (92) - (115) (22)
Net change in non-cash
working capital from
continuing operations 168 (322) 229 (811)
Net change in non-cash
working capital from
discontinued operations (4) 45 78 74
-------------------------------------------------------------------------
1,424 745 4,834 1,590
-------------------------------------------------------------------------
INVESTING ACTIVITIES
Business combination - - - (128)
Capital expenditures (Note 3) (1,849) (1,440) (4,880) (3,311)
Proceeds on disposal
of capital assets - 133 27 376
Corporate acquisitions (Note 2) (128) - (307) -
Equity investments (34) - (222) -
Net change in investments
and other (56) 27 (96) 15
Net change in non-cash
working capital from
continuing operations 63 83 (173) (167)
Discontinued operations 424 (65) 2,372 (134)
-------------------------------------------------------------------------
(1,580) (1,262) (3,279) (3,349)
-------------------------------------------------------------------------
FINANCING ACTIVITIES
Net issuance of
long-term debt 896 813 56 1,305
Issuance of common shares (Note 8) 16 27 136 96
Repurchase of common shares (Note 8) (772) - (940) -
Dividends on common shares (47) (47) (143) (120)
Payments to preferred
securities holders (20) (24) (32) (31)
Net change in non-cash
working capital from
continuing operations (5) 3 (13) 2
Discontinued operations - (4) (438) (9)
Other 11 7 (7) (25)
-------------------------------------------------------------------------
79 775 (1,381) 1,218
-------------------------------------------------------------------------
DEDUCT: FOREIGN EXCHANGE
(GAIN) LOSS ON CASH AND
CASH EQUIVALENTS HELD IN
FOREIGN CURRENCY (6) (4) 22 7
-------------------------------------------------------------------------
(DECREASE) INCREASE IN CASH
AND CASH EQUIVALENTS (71) 262 152 (548)
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD 406 153 183 963
-------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS,
END OF PERIOD $ 335 $ 415 $ 335 $ 415
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.



EnCana Corporation
Notes to Consolidated Financial Statements (unaudited)

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. 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. CORPORATE ACQUISITIONS

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:

($ millions) Vintage Savannah
-------------------------------------------------------------------------
Working Capital $ 2 $ 1
Capital Assets 194 155
Future Income Taxes (17) (28)
-------------------------------------------------------------------------
$ 179 $ 128
-------------------------------------------------------------------------
-------------------------------------------------------------------------


3. SEGMENTED INFORMATION

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

- Upstream includes the Company's exploration for and production of
natural gas, natural gas liquids and crude oil and related Non-
producing activities. The Company's Upstream operations are located
in Canada, the United States, the U.K. central North Sea, Ecuador and
International New Ventures exploration activity in the Gulf of
Mexico, the U.K. central North Sea, the Middle East, Africa,
Australia, Latin America, as well as, the Canadian East Coast and the
North American northern frontier.

- Midstream & Marketing includes natural gas storage operations,
natural gas liquids processing and power generation operations, as
well as, marketing 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.

The Company reports its segmented financial results showing revenue prior
to all royalty payments, both cash and in-kind, consistent with Canadian
disclosure practices for the oil and gas industry.

Operations that have been discontinued are disclosed in Note 4.


Results of Operations (For the three months ended September 30)

Upstream Midstream &
Marketing
--------------------------------------------
($ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Gross revenue $ 2,410 $ 1,828 $ 1,077 $ 1,165
Royalties and production
taxes 373 256 - -
-------------------------------------------------------------------------
Revenues, net of royalties
and production taxes 2,037 1,572 1,077 1,165

Expenses
Transportation and selling 158 126 15 48
Operating 357 296 88 54
Purchased product - - 955 1,041
Depreciation, depletion
and amortization 716 579 12 10
-------------------------------------------------------------------------
Segment Income $ 806 $ 571 $ 7 $ 12
-------------------------------------------------------------------------


Corporate Consolidated
--------------------------------------------
2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Gross revenue $ 2 $ 4 $ 3,489 $ 2,997
Royalties and production
taxes - - 373 256
-------------------------------------------------------------------------
Revenues, net of royalties
and production taxes 2 4 3,116 2,741

Expenses
Transportation and selling - - 173 174
Operating - - 445 350
Purchased product - - 955 1,041
Depreciation, depletion
and amortization 20 16 748 605
-------------------------------------------------------------------------
Segment Income $ (18) $ (12) 795 571
-------------------------------------------------------------------------
Administrative 56 50
Interest, net 87 112
Foreign exchange (gain) loss (25) 156
-------------------------------------------------------------------------
118 318
-------------------------------------------------------------------------
Net Earnings Before Income Tax 677 253
Income tax expense 278 126
Distributions on subsidiary
preferred securities,
net of tax - 11
-------------------------------------------------------------------------
Net Earnings from
Continuing Operations $ 399 $ 116
-------------------------------------------------------------------------



Geographic and Product Information
(For the three months ended September 30)

North America
------------------------------------------------------
Upstream Produced Gas and NGLs
Canada U.S. Rockies Crude Oil
------------------------------------------------------
($ millions) 2003 2002 2003 2002 2003 2002
Revenues
Gross revenue $ 1,324 $ 881 $ 480 $ 260 $ 359 $ 438
Royalties and
production taxes 180 83 130 55 21 54
-------------------------------------------------------------------------
Revenues, net of
royalties and
production taxes 1,144 798 350 205 338 384
Expenses
Transportation
and selling 99 58 30 32 12 17
Operating 128 123 26 18 113 91
Depreciation,
depletion and
amortization 377 290 107 103 167 116
-------------------------------------------------------------------------
Segment Income $ 540 $ 327 $ 187 $ 52 $ 46 $ 160
-------------------------------------------------------------------------


Ecuador U.K. North Sea Non-Producing
------------------------------------------------------
2003 2002 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Gross revenue $ 152 $ 186 $ 23 $ 37 $ 72 $ 26
Royalties and
production taxes 42 64 - - - -
-------------------------------------------------------------------------
Revenues, net of
royalties and
production taxes 110 122 23 37 72 26
Expenses
Transportation
and selling 12 14 5 5 - -
Operating 22 24 4 5 64 35
Depreciation,
depletion and
amortization 46 37 16 29 3 4
-------------------------------------------------------------------------
Segment Income $ 30 $ 47 $ (2) $ (2) $ 5 $ (13)
-------------------------------------------------------------------------

Total Upstream
-------------------
2003 2002
-------------------------------------------------------------------------
Revenues
Gross revenue $ 2,410 $ 1,828
Royalties and production taxes 373 256
-------------------------------------------------------------------------
Revenues, net of royalties and production taxes 2,037 1,572
Expenses
Transportation and selling 158 126
Operating 357 296
Depreciation, depletion and amortization 716 579
-------------------------------------------------------------------------
Segment Income $ 806 $ 571
-------------------------------------------------------------------------

Midstream & Marketing Total Midstream
Midstream Marketing (*) & Marketing
------------------------------------------------------
($ millions) 2003 2002 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Gross revenue $ 248 $ 156 $ 829 $ 1,009 $ 1,077 $ 1,165

Expenses
Transportation
and selling - - 15 48 15 48
Operating 79 48 9 6 88 54
Purchased product 155 72 800 969 955 1,041
Depreciation,
depletion and
amortization 10 9 2 1 12 10
-------------------------------------------------------------------------
Segment Income $ 4 $ 27 $ 3 $ (15) $ 7 $ 12
-------------------------------------------------------------------------

(*) 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 nine months ended September 30)

Upstream Midstream &
Marketing
--------------------------------------------
($ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Gross revenue $ 7,779 $ 4,255 $ 3,901 $ 2,735
Royalties and production
taxes 1,306 605 - -
-------------------------------------------------------------------------
Revenues, net of royalties
and production taxes 6,473 3,650 3,901 2,735

Expenses
Transportation and selling 474 277 63 103
Operating 1,026 676 346 193
Purchased product - - 3,458 2,317
Depreciation, depletion
and amortization 2,136 1,317 30 41
-------------------------------------------------------------------------
Segment Income $ 2,837 $ 1,380 $ 4 $ 81
-------------------------------------------------------------------------

Corporate Consolidated
---------------------------------------------
2003 2002 2003 2002
Revenues
Gross revenue $ 4 $ 3 $ 11,684 $ 6,993
Royalties and production
taxes - - 1,306 605
-------------------------------------------------------------------------
Revenues, net of royalties
and production taxes 4 3 10,378 6,388

Expenses
Transportation and selling - - 537 380
Operating - - 1,372 869
Purchased product - - 3,458 2,317
Depreciation, depletion
and amortization 45 34 2,211 1,392
-------------------------------------------------------------------------
Segment Income $ (41) $ (31) 2,800 1,430
-------------------------------------------------------------------------
Administrative 172 111
Interest, net 257 242
Foreign exchange (gain) (560) (24)
-------------------------------------------------------------------------
(131) 329
-------------------------------------------------------------------------
Net Earnings Before Income Tax 2,931 1,101
Income tax expense 513 361
Distributions on subsidiary
preferred securities,
net of tax - 11
-------------------------------------------------------------------------
Net Earnings from
Continuing Operations $ 2,418 $ 729
-------------------------------------------------------------------------



Geographic and Product Information
(For the nine months ended September 30)
North America
------------------------------------------------------
Upstream Produced Gas and NGLs
Canada U.S. Rockies Crude Oil
------------------------------------------------------
($ millions) 2003 2002 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Gross revenue $ 4,377 $ 2,193 $ 1,491 $ 467 $ 1,150 $ 1,040
Royalties and
production taxes 625 243 393 104 136 135
-------------------------------------------------------------------------
Revenues, net of
royalties and
production taxes 3,752 1,950 1,098 363 1,014 905
Expenses
Transportation
and selling 277 146 79 57 69 35
Operating 384 274 63 38 322 227
Depreciation,
depletion and
amortization 1,164 697 301 195 464 279
-------------------------------------------------------------------------
Segment Income $ 1,927 $ 833 $ 655 $ 73 $ 159 $ 364
-------------------------------------------------------------------------


Ecuador U.K. North Sea Non-Producing
------------------------------------------------------
2003 2002 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Gross revenue $ 475 $ 368 $ 105 $ 126 $ 181 $ 61
Royalties and
production taxes 152 123 - - - -
-------------------------------------------------------------------------
Revenues, net of
royalties and
production taxes 323 245 105 126 181 61

Expenses
Transportation
and selling 33 24 16 15 - -
Operating 70 55 13 11 174 71
Depreciation,
depletion and
amortization 124 88 76 48 7 10
-------------------------------------------------------------------------
Segment Income $ 96 $ 78 $ - $ 52 $ - $ (20)
-------------------------------------------------------------------------


Total Upstream
-------------------
2003 2002
-------------------------------------------------------------------------
Revenues
Gross revenue $ 7,779 $ 4,255
Royalties and production taxes 1,306 605
-------------------------------------------------------------------------
Revenues, net of royalties and production taxes 6,473 3,650
Expenses
Transportation and selling 474 277
Operating 1,026 676
Depreciation, depletion and amortization 2,136 1,317
-------------------------------------------------------------------------
Segment Income $ 2,837 $ 1,380
-------------------------------------------------------------------------



Midstream & Marketing Total Midstream
Midstream Marketing (*) & Marketing
------------------------------------------------------
($ millions) 2003 2002 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Gross revenue $ 940 $ 386 $ 2,961 $ 2,349 $ 3,901 $ 2,735
Expenses
Transportation
and selling - - 63 103 63 103
Operating 272 181 74 12 346 193
Purchased product 613 123 2,845 2,194 3,458 2,317
Depreciation,
depletion and
amortization 27 33 3 8 30 41
-------------------------------------------------------------------------
Segment Income $ 28 $ 49 $ (24) $ 32 $ 4 $ 81
-------------------------------------------------------------------------

(*) 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 Nine Months Ended
September 30 September 30
--------------------------------------------
($ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------
Upstream
Canada $ 1,238 $ 359 $ 3,250 $ 1,406
United States 384 876 885 1,500
Ecuador 90 96 247 168
United Kingdom 26 41 64 103
Other Countries 21 27 89 66
Midstream & Marketing 80 22 290 39
Corporate 10 19 55 29
-------------------------------------------------------------------------
Total $ 1,849 $ 1,440 $ 4,880 $ 3,311
-------------------------------------------------------------------------


Capital and Total Assets
Capital Assets Total Assets
--------------------------------------------
As at As at
--------------------------------------------
September December September December
($ millions) 30, 2003 31, 2002 30, 2003 31, 2002
-------------------------------------------------------------------------
Upstream $ 23,252 $ 21,422 $ 24,585 $ 25,192
Midstream & Marketing 970 742 2,469 2,216
Corporate 218 192 3,158 492
Assets of Discontinued
Operations - 3,422
-------------------------------------------------------------------------
Total $ 24,440 $ 22,356 $ 30,212 $ 31,322
-------------------------------------------------------------------------


Interim Report
For the period ended September 30, 2003

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)

4. 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 plus
closing adjustments. 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, subject to closing adjustments. 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 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.

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, and recorded an after-tax gain on
sale of $263 million.

The following table presents the effect of the discontinued operations on
the Consolidated Financial Statements:


Consolidated
Statement
of Earnings For the three months ended September 30
--------------------------------------------------------
Merchant Midstream -
Syncrude Energy Pipelines Total
--------------------------------------------------------
($ millions) 2003 2002 2003 2002 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues, net of
royalties and
production
taxes $ 11 $ 141 $ - $ 154 $ - $ 91 $ 11 $ 386
-------------------------------------------------------------------------
Expenses
Transportation
and selling - 2 - - - - - 2
Operating 6 44 - - - 33 6 77
Purchased
product - - - 162 - - - 162
Administrative - - - 16 - - - 16
Interest, net - - - - - 11 - 11
Foreign
exchange loss - - - - - 7 - 7
Depreciation,
depletion and
amortization 1 11 - - - 12 1 23
Gain) loss on
discontinuance - - - (29) - - - (29)
-------------------------------------------------------------------------
7 57 - 149 - 63 7 269
-------------------------------------------------------------------------
Net Earnings
Before Income Tax 4 84 - 5 - 28 4 117
Income tax
expense 3 16 - 2 - 11 3 29
-------------------------------------------------------------------------
Net Earnings from
Discontinued
Operations $ 1 $ 68 $ - $ 3 $ - $ 17 $ 1 $ 88
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Consolidated
Statement
of Earnings For the nine months ended September 30
--------------------------------------------------------
Merchant Midstream -
Syncrude(*) Energy Pipelines(*) Total
--------------------------------------------------------
($ millions) 2003 2002 2003 2002 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues, net of
royalties and
production
taxes $ 129 $ 231 $ - $1,463 $ - $ 149 $ 129 $1,843
-------------------------------------------------------------------------
Expenses
Transportation
and selling 2 3 - - - - 2 3
Operating 69 112 - - - 53 69 165
Purchased
product - - - 1,475 - - - 1,475
Administrative - - - 34 - - - 34
Interest, net - - - - - 22 - 22
Foreign
exchange (gain) - - - - - (3) - (3)
Depreciation,
depletion and
amortization 10 18 - 1 - 23 10 42
(Gain) loss on
discontinuance - - - 24 (343) - (343) 24
-------------------------------------------------------------------------
81 133 - 1,534 (343) 95 (262) 1,762
-------------------------------------------------------------------------
Net Earnings
(Loss) Before
Income Tax 48 98 - (71) 343 54 391 81
Income tax
expense
(recovery) 17 18 - (25) 80 22 97 15
-------------------------------------------------------------------------
Net Earnings
(Loss) from
Discontinued
Operations $ 31 $ 80 $ - $ (46)$ 263 $ 32 $ 294 $ 66
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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


Consolidated
Balance Sheet As at September 30
--------------------------------------------------------
Merchant Midstream -
Syncrude Energy Pipelines Total
--------------------------------------------------------
($ millions) 2003 2002 2003 2002 2003 2002 2003 2002
-------------------------------------------------------------------------
Assets
Cash and cash
equivalents $ - $ 15 $ - $ - $ - $ 60 $ - $ 75
Accounts
receivable
and accrued
revenue - 54 - 55 - 32 - 141
Inventories - 17 - - - 1 - 18
-------------------------------------------------------------------------
- 86 - 55 - 93 - 234
Capital assets,
net - 1,332 - - - 819 - 2,151
Investments and
other assets - - - - - 369 - 369
Goodwill - 417 - - - - - 417
-------------------------------------------------------------------------
- 1,835 - 55 - 1,281 - 3,171
-------------------------------------------------------------------------
Liabilities
Accounts payable
and accrued
liabilities - 96 - 30 - 44 - 170
Income tax
payable - (2) - - - 5 - 3
Current portion
of long-term
debt - - - - - 25 - 25
-------------------------------------------------------------------------
- 94 - 30 - 74 - 198
Deferred credits
and other
liabilities - 21 - - - - - 21
Long-term debt - - - - - 583 - 583
Future income
taxes - 341 - - - 155 - 496
-------------------------------------------------------------------------
- 456 - 30 - 812 - 1,298
-------------------------------------------------------------------------
Net Assets of
Discontinued
Operations $ - $1,379 $ - $ 25 $ - $ 469 $ - $1,873
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Consolidated Balance Sheet
As at
December 31
--------------
($ millions) 2002 2001
-------------------------------------------------------------------------

Assets
Cash and cash equivalents $ 97 $ -
Accounts receivable and accrued revenue 96 632
Inventories 16 70
-------------------------------------------------------------------------
209 702
Capital assets, net 2,231 9
Investments and other assets 374 17
Goodwill 608 -
-------------------------------------------------------------------------
3,422 728
-------------------------------------------------------------------------
Liabilities
Accounts payable and accrued liabilities 153 584
Income tax payable 11 -
Short-term debt 438 -
Current portion of long-term debt 23 -
-------------------------------------------------------------------------
625 584
Long-term debt 576 -
Deferred credits and other liabilities 21 2
Future income taxes 536 -
-------------------------------------------------------------------------
1,758 586
-------------------------------------------------------------------------
Net Assets of Discontinued Operations $1,664 $ 142
-------------------------------------------------------------------------
-------------------------------------------------------------------------


5. FOREIGN EXCHANGE (GAIN) LOSS

Three Months Ended Nine Months Ended
September 30 September 30
------------------------------------------
($ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------
Unrealized foreign exchange
(gain) loss on translation
of U.S. dollar debt $ (18) $ 183 $ (511) $ (21)
Other foreign exchange (gains) (7) (27) (49) (3)
-------------------------------------------------------------------------
$ (25) $ 156 $ (560) $ (24)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


6. INCOME TAXES

Three Months Ended Nine Months Ended
September 30 September 30
------------------------------------------
($ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------
Provision for Income Taxes
Current
Canada $ 47 $ 73 $ (12) $ 137
United States 14 (57) 14 (49)
Ecuador 11 7 30 14
United Kingdom 2 4 5 12
Other Countries 1 2 1 2
-------------------------------------------------------------------------
75 29 38 116
Future 203 97 961 287
Future tax rate
reductions (*) - - (486) (42)
-------------------------------------------------------------------------
$ 278 $ 126 $ 513 $ 361
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(*) During the second quarter of 2003, both the Canadian federal and
Alberta governments substantively enacted income tax rate reductions
previously announced.


7. LONG-TERM DEBT
As at As at
September 30, December 31,
($ millions) 2003 2002
-------------------------------------------------------------------------

Canadian Dollar Denominated Debt
Revolving credit and term loan borrowings $ 1,624 $ 1,388
Unsecured notes and debentures 1,725 1,825
-------------------------------------------------------------------------
3,349 3,213
-------------------------------------------------------------------------

U.S. Dollar Denominated Debt
Revolving credit and term loan borrowings 728 696
Unsecured notes and debentures 2,989 3,608
-------------------------------------------------------------------------
3,717 4,304
-------------------------------------------------------------------------

Increase in Value of Debt Acquired (*) 87 90
Current Portion of Long-term Debt (50) (212)
-------------------------------------------------------------------------
$ 7,103 $ 7,395
-------------------------------------------------------------------------
-------------------------------------------------------------------------

On October 2, 2003, the Company completed the issuance of US$500 million
unsecured notes with a coupon rate of 4.75%. These notes mature in 2013.
Proceeds from the offering were used to repay amounts recorded as
revolving credit and term loan borrowings.

(*) 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 23 years.


8. SHARE CAPITAL

September 30, 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 4.7 136 5.5 139
Shares Repurchased (18.6) (341) - -
-------------------------------------------------------------------------
Common Shares Outstanding,
End of Period 465.0 $ 8,527 478.9 $ 8,732
-------------------------------------------------------------------------
-------------------------------------------------------------------------


During the quarter, the Company purchased, for cancellation, 15,281,500
common shares (Year-to-date - 18,624,400 common shares) for total
consideration of approximately $772 million (Year-to-date -
$940 million). Of the $940 million paid this year, $341 million was
charged to Share capital, $96 million was charged to Paid in surplus and
$503 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 from the date the options were
granted.

The following tables summarize the information about options to purchase
common shares at September 30, 2003:

Weighted
Stock Average
Options Exercise
(millions) Price ($)
-------------------------------------------------------------------------
Outstanding, Beginning of Year 29.6 39.74
Granted under EnCana Plans 6.1 47.98
Exercised (4.7) 28.59
Forfeited (1.1) 47.44
-------------------------------------------------------------------------
Outstanding, End of Period 29.9 42.89
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Exercisable, End of Period 16.2 38.54
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Outstanding Options Exercisable Options
-----------------------------------------------------------
Weighted
Number of Average Weighted Number of Weighted
Range of Options Remaining Average Options Average
Exercise Outstanding Contractual Exercise Outstanding Exercise
Price ($) (millions) Life (years) Price ($) (millions) Price ($)
-------------------------------------------------------------------------
13.50 to 19.99 1.8 0.8 18.87 1.8 18.87
20.00 to 24.99 1.4 1.7 22.35 1.4 22.35
25.00 to 29.99 2.3 1.7 26.51 2.3 26.51
30.00 to 43.99 1.4 2.5 38.78 1.2 38.30
44.00 to 53.00 23.0 3.8 47.93 9.5 47.69
-------------------------------------------------------------------------
29.9 2.8 42.89 16.2 38.54
-------------------------------------------------------------------------
-------------------------------------------------------------------------


The Company does not record compensation expense in the Consolidated
Financial Statements for share options granted to employees and
directors. If the fair-value method had been used, the Company's Net
Earnings and Net Earnings per Common Share would approximate the
following pro forma amounts:

Nine Months
Ended
September 30
---------------------
($ millions, except per share amounts) 2003 2002
-------------------------------------------------------------------------
Compensation Costs 53 65

Net Earnings
As reported 2,712 795
Pro forma 2,659 730

Net Earnings per Common Share
Basic
As reported 5.69 1.99
Pro forma 5.58 1.83
Diluted
As reported 5.60 1.96
Pro forma 5.49 1.80
-------------------------------------------------------------------------


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:

Nine Months
Ended
September 30
---------------------
2003 2002
-------------------------------------------------------------------------
Weighted Average Fair Value of Options Granted $12.21 $13.35
Risk Free Interest Rate 3.89% 4.36%
Expected Lives (years) 3.00 3.00
Expected Volatility 0.33 0.35
Annual Dividend per Share $0.40 $0.40
-------------------------------------------------------------------------


9. PER SHARE AMOUNTS

The following table summarizes the common shares used in calculating net
earnings per common share:
Nine
Three Months Ended Months Ended
------------------------------------------------------
March 31 June 30 September 30 September 30
(millions) 2003 2003 2003 2002 2003 2002
-------------------------------------------------------------------------
Weighted Average
Common Shares
Outstanding -
Basic 479.9 480.6 473.4 476.8 478.0 397.8
Effect of Dilutive
Securities 7.0 6.3 7.1 5.4 8.3 6.9
-------------------------------------------------------------------------
Weighted Average
Common Shares
Outstanding -
Diluted 486.9 486.9 480.5 482.2 486.3 404.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------


10. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

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

As at
September 30,
($ millions) 2003
-------------------------------------------------------------------------
Commodity Price Risk
Crude oil $ (224)
Gas storage optimization 82
Natural gas 374
Power 4
Foreign Currency Risk 23
Interest Rate Risk 59
-------------------------------------------------------------------------
Unrecognized Gains $ 318
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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 September 30,
2003.

Crude Oil

As at September 30, 2003, the Company's corporate oil risk management
activities had an unrecognized loss of $224 million. The contracts were
as follows:

Unrecognized
Notional Average Gain/
Volumes Price (Loss) (Cdn$
(bbl/d) Term (US$/bbl) millions)
-------------------------------------------------------------------------
Fixed WTI NYMEX Price 85,000 2003 25.28 $ (37)
Fixed WTI NYMEX Price 62,500 2004 23.13 (109)
Collars on WTI NYMEX 40,000 2003 21.95-29.00 (5)
Collars on WTI NYMEX 62,500 2004 20.00-25.69 (73)
-------------------------------------------------------------------------
$ (224)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Gas Storage Optimization

As part of the Company's gas storage optimization program, the Company
has entered into financial contracts at various locations and terms over
the next 13 months to manage the price volatility of the corresponding
physical transactions and inventory.

As at September 30, 2003, the unrecognized gain on gas storage
optimization contracts was $82 million. The contracts are as follows:

Unrecognized
Notional Gain/
Volumes Price (Loss) (Cdn$
(bcf) (US$/mcf) millions)
-------------------------------------------------------------------------
Financial Instruments
Purchases 213.1 5.21 $ (77)
Sales 251.4 5.44 125
-------------------------------------------------------------------------
48
Physical Contracts 34
-------------------------------------------------------------------------
$ 82
-------------------------------------------------------------------------
-------------------------------------------------------------------------


The unrecognized gain does not reflect unrealized gains on physical
inventory in storage.

Natural Gas

At September 30, 2003, the fair value of financial instruments and
physical contracts that related to the corporate gas risk management
activities was $374 million. The contracts are as follows:

Notional Unrecognized
Volumes Physical/ Gain/(Loss)
(MMcf/d) Financial Term Price (Cdn$ millions)
-------------------------------------------------------------------------
Fixed Price
Contracts
Sales Contracts
Fixed AECO price 561 Financial 2003 6.36 Cdn$/mcf $27
Fixed AECO price 10 Financial 2003 3.37 US$/mmbtu (1)
Fixed AECO price 10 Physical 2003 3.34 US$/mmbtu (1)
NYMEX Fixed
price(*) 536 Financial 2003 4.50 US$/mmbtu (19)
NYMEX Collars 50 Physical 2003 2.46-4.90 US$/mmbtu (1)

Fixed AECO price 453 Financial 2004 6.20 Cdn$/mcf 77
AECO Collars 71 Financial 2004 5.34-7.52 Cdn$/mcf 8
NYMEX Fixed
price(*) 536 Financial 2004 5.06 US$/mmbtu 48
Chicago Fixed
price 40 Financial 2004 5.42 US$/mmbtu 9
NYMEX Collars 10 Financial 2004 4.60-6.55 US$/mmbtu 2
NYMEX Collars 50 Physical 2004 2.46-4.90 US$/mmbtu (16)

NYMEX Collars 47 Physical 2005-2007 2.46-4.90 US$/mmbtu (40)

Basis Contracts
Sales Contracts
Fixed NYMEX to
AECO basis(*) 364 Financial 2003 (0.55) US$/mmbtu (2)
Fixed NYMEX to
Rockies basis 280 Financial 2003 (0.50) US$/mmbtu (2)
Fixed NYMEX to
Rockies basis 418 Physical 2003 (0.52) US$/mmbtu (5)
Fixed NYMEX to
San Juan basis 33 Financial 2003 (0.63) US$/mmbtu (1)
Fixed NYMEX to
San Juan basis 33 Physical 2003 (0.64) US$/mmbtu (1)

Fixed NYMEX to
AECO basis(*) 336 Financial 2004 (0.54) US$/mmbtu 24
Fixed NYMEX to
Rockies basis 190 Financial 2004 (0.42) US$/mmbtu 16
Fixed NYMEX to
Rockies basis 403 Physical 2004 (0.49) US$/mmbtu 20
Fixed NYMEX to
San Juan basis 60 Financial 2004 (0.63) US$/mmbtu (1)
Fixed NYMEX to
San Juan basis 50 Physical 2004 (0.64) US$/mmbtu (1)

Fixed NYMEX to
AECO basis(*) 677 Financial 2005-2007 (0.65) US$/mmbtu 69
Fixed NYMEX to
Rockies basis 132 Financial 2005-2007 (0.44) US$/mmbtu 49
Fixed NYMEX to
Rockies basis 250 Physical 2005-2007 (0.47) US$/mmbtu 83
Fixed NYMEX to
San Juan basis 69 Financial 2005-2006 (0.63) US$/mmbtu -
Fixed NYMEX to
San Juan basis 46 Physical 2005-2006 (0.64) US$/mmbtu (1)
Purchase Contracts
Fixed Nymex to
AECO basis(*) 119 Financial 2003 (0.77) US$/mmbtu 2

Alliance Pipeline
Mitigation
Sale Contracts 14 Financial 2003 3.92 US$/mmbtu (1)
Purchase
Contracts 15 Physical 2003 3.24 Cdn$/mcf 3
-------------------------------------------------------------------------
344
Gas Marketing
Financial
Positions(1) (3)
Gas Marketing
Physical
Positions(1) 33
-------------------------------------------------------------------------
$374
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) Certain Fixed NYMEX to AECO basis and NYMEX Fixed price contracts
have previously been combined and reported as Fixed AECO prices. They
are now reclassified and reported separately.

(1) The gas marketing activities are part of the daily ongoing operations
of the Company's proprietary production management.


11. 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 by contacting: Investor contact:


Investor contact:
EnCana Corporate Development
Sheila McIntosh
Senior Vice-President, Investor Relations
(403) 645-2194

Greg Kist
Manager, Investor Relations
(403) 645-2194
Media contact:

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

ECA stock price

TSX $14.27 Can -0.540

NYSE $11.11 USD -0.510

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