EnCana's second quarter cash flow increases 53% to $1.4 billion, earnings approach $1.1 billion, including tax and currency gains

CALGARY, July 29 /CNW/ - With strong year-over-year production growth and
robust oil and natural gas prices, EnCana Corporation's (TSX & NYSE: ECA)
second quarter 2003 cash flow reached $1.44 billion, or $2.95 per common share
diluted, up 53 percent from $938 million in the second quarter of 2002. Net
earnings were $1.07 billion, or $2.21 per common share diluted, including the
impact of tax rate changes and foreign exchange gains.
Second quarter earnings included an unrealized after-tax gain of
$199 million, or 41 cents per common share diluted, relating to translation of
US$ debt and a gain of $486 million, or $1.00 per common share diluted,
relating to changes in Canadian and Alberta corporate income tax rates for the
oil and gas industry. Canadian federal tax rates were reduced for other
industries in 2000. These gains had no impact on cash flow. Excluding these
gains, EnCana earned $381 million, or 80 cents per common share diluted.
In the second quarter of 2002, EnCana earned $458 million, or $0.97 per
common share diluted, which included an unrealized after-tax gain of
$163 million related to foreign exchange on translation of US$ debt and
$42 million related to tax rate changes. Excluding these gains, EnCana earned
$253 million, or $0.53 per share diluted in the second quarter of 2002. Year
over year, second quarter 2003 earnings, excluding these gains, increased
51 percent. Revenues, net of royalties and production taxes, in the second
quarter of 2003 were $3.2 billion; capital investment was $1.5 billion.
EnCana recently completed the sale of its remaining 3.75 percent interest
in Syncrude and its results are reflected as discontinued operations.
"As we move into the second half, we are on target to achieve industry-
leading internal sales growth and record financial and operating performance
in 2003. Second quarter natural gas sales increased 13 percent from one year
earlier. Strong growth in North American oil and natural gas liquids (NGLs)
sales was largely offset by decreased sales in Ecuador. However, the
completion of the OCP Pipeline is about to mark an exciting new era of oil
production in Ecuador. This technically-advanced, privately-owned and operated
pipeline is expected to allow us to more reliably control the delivery of our
greatly increased production from wellhead to tidewater in the months and
years ahead," said Gwyn Morgan, EnCana's President & Chief Executive Officer.
"EnCana continues to deliver strong financial and operating performance.
We are focused on building the intrinsic value of every share by growing
production, increasing our reserves, and achieving top-quartile cost
performance. Prices remain strong at a time when we expect to achieve second
half production growth through North America's largest natural gas drilling
program and increased oil volumes from Canada, the U.K. and Ecuador," Morgan
said.

Second quarter natural gas sales up 13 percent in 2003

Second quarter daily oil, NGLs and natural gas sales averaged 727,000
barrels of oil equivalent (BOE), up 9 percent compared to sales of 669,000
barrels of oil equivalent per day during the second quarter of 2002. Daily
natural gas sales increased 13 percent to average 2.9 billion cubic feet
compared to 2.6 billion cubic feet during the same period in 2002. Oil and
NGLs sales averaged 240,000 barrels per day, compared to 239,000 barrels per
day in the second quarter of 2002. EnCana drilled 956 net wells in the second
quarter of 2003. Operating costs averaged $4.03 per barrel of oil equivalent
for the quarter, on track to achieve the company's 2003 target of $3.80 to
$4.10 per barrel of oil equivalent.

Focused upstream investment strategy

EnCana continues to focus its investment strategy on high-working
interest, upstream assets where the company's staff can apply their core
competencies. On July 10, EnCana completed the sale of its remaining
3.75 percent interest in the Syncrude oilsands surface mining operation for
approximately $417 million, subject to closing and post-closing adjustments.
Future Alberta oilsands development will concentrate on EnCana's huge,
100-percent-owned resources where the company is the leader in new generation
thermal enhanced recovery from horizontally-drilled wells. EnCana also
recently reached an agreement to increase its interests in the Scott and
Telford producing oil fields in the U.K. central North Sea. This agreement
involved the exchange of a 22.5 percent non-operated interest in the Llano oil
discovery in the Gulf of Mexico.

Growth founded in resource plays
"EnCana's growth forecast is built principally upon our large, long-life
resource plays. We expect these high-quality oil and gas reservoirs to deliver
predictable and reliable production increases for years ahead. Our resource
plays include millions of acres of tight gas sands in Alberta, Wyoming and
Colorado, our top-quality oilsands lands in northeast Alberta and our
extensive Greater Sierra gas play in northeast British Columbia," Morgan said.
"The confidence we have in our growth forecast is founded in both the
strength of our reserve base and our large unbooked resource potential. We
estimate that the unbooked 'captured resource potential' on EnCana's existing
North America lands is approximately 9 trillion cubic feet of gas and
650 million barrels of oil. We define resource potential as those quantities
of oil and gas which are estimated to be potentially recoverable on EnCana's
existing land base from known accumulations and which are not currently
classified as proved or risked probable reserves.
"It's important to note that our 10 percent per-share growth forecast is
based upon captured resources on EnCana lands. Our very large North American
and international exploration program provides potential upside," Morgan said.

All references to production, sales and financial information for the
first six 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.

Six months cash flow hits $3.3 billion, earnings more than $2.3 billion

During the first six months of 2003, EnCana's earnings increased
272 percent from the first half of 2002 to $2.3 billion, or $4.79 per common
share diluted. Earnings include gains totalling $878 million, or $1.81 per
common share diluted, as a result of foreign exchange translation on US$ debt
and changes to corporate tax rates. While the stronger Canadian dollar results
in gains on the US$ denominated debt, it adversely impacts the average net
Canadian dollar price realized by the company on its sales of oil and natural
gas, which are either directly denominated in U.S. dollars or denominated in
Canadian dollars but closely tied to U.S. currency. Six months 2003 cash flow
was up 92 percent over the first half of 2002 to $3.3 billion, or $6.77 per
common share diluted. Revenues, net of royalties and production taxes, in the
first six months were $7.3 billion. Capital investment was $3.0 billion, while
divestiture proceeds were $2.6 billion.

Natural gas prices remain strong

North American natural gas prices continued to be strong in the wake of
weakening supply in Canada and the U.S. In the second quarter, the average
AECO index price was $6.99 per thousand cubic feet, up 58 percent from the
second quarter of 2002. Storage injections have increased in recent months,
but storage volumes remain below long-term averages. Storage demands prior to
winter are expected to keep prices strong throughout 2003.

World oil prices remain strong in the wake of continued supply
uncertainty

During the second quarter, the average benchmark West Texas Intermediate
crude oil price was US$28.91 per barrel, up 10 percent over the same period
last year. Continued unrest in key oil producing regions has kept global oil
prices higher than expected. Price volatility is expected to continue.

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. EnCana has entered into various fixed-price transactions for a portion
of its forecast 2003 sales as a means of managing the cash flow at risk,
thereby stabilizing financial strength and funding for capital programs. With
the high oil and gas prices and changes to exchange rates in the second
quarter, EnCana's commodity price and currency risk management measures
resulted in pre-tax revenue being lower by approximately $120 million,
comprised of $42 million on oil sales and $78 million on gas sales. The
detailed risk management positions are given in Note 10 to the second quarter
Consolidated Financial Statements.

<<
Consolidated Highlights
-----------------------

-------------------------------------------------------------------------
Financial Highlights (unaudited)
(as at and for the periods ended 6 Months
June 30) Q2 Q2 6 Months 2002
($ millions, except per share 2003 2002 2003 Pro
amounts) Actuals Actuals Actuals Forma(2)
-------------------------------------------------------------------------
Revenues, net of royalties and
production taxes 3,194 2,586 7,262 4,748
-------------------------------------------------------------------------
Cash Flow 1,438 938 3,290 1,717
Per common share - diluted 2.95 2.00 6.77 3.55
-------------------------------------------------------------------------
Net earnings 1,066 458 2,312 621
Per common share - basic(1) 2.24 0.99 4.84 1.31
Per common share - diluted 2.21 0.97 4.79 1.28

Less
Foreign exchange gain on
translation of US$ debt
(after-tax) 199 163 392 162
Per common share - basic 0.41 0.35 0.82 0.34
Per common share - diluted 0.41 0.35 0.81 0.33

Less
Tax rate change gain 486 42 486 42
Per common share - basic 1.01 0.09 1.01 0.09
Per common share - diluted 1.00 0.09 1.00 0.09
-------------------------------------------------------------------------
Net earnings, excluding gains 381 253 1,434 417
Per common share - basic 0.82 0.55 3.01 0.88
Per common share - diluted 0.80 0.53 2.98 0.86
-------------------------------------------------------------------------
Capital investment 1,505 1,390 3,031 2,644
-------------------------------------------------------------------------
at Dec.
31/02

Total assets 29,603 31,322
Long-term debt 6,122 7,395
Preferred securities 549 583
Shareholders' equity 15,356 13,794

Debt-to-capitalization ratio 28% 31%
(adjusted for working capital &
including preferred securities
as debt)

Common shares
Outstanding at June 30 (millions) 479.9 476.3 479.9 476.3
Weighted average diluted (millions) 486.9 470.0 486.3 483.6
------------------------------------------------------------------------
(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 $4.78
per common share, 6 cents per common share less, for the first six
months of 2003.
(2) Important Notice: Readers are cautioned that comparisons to 2002 six
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 6 Months
(for the period Q2 Q2 6 Months 2002
ended 2003 2002 % 2003 Pro %
June 30) Actuals Actuals Change Actuals forma(2) Change
-------------------------------------------------------------------------
Sales
Natural gas (MMcf/d)
North America 2,911 2,572 +13 2,956 2,641 +12
U.K. 12 8 +50 12 10 +20
Total natural gas
(MMcf/d) 2,923 2,580 +13 2,968 2,651 +12

Oil and NGLs (bbls/d)
North America 181,250 166,951 +9 180,527 165,304 +9
Ecuador 49,575 59,864 -17 46,189 49,377 -6
U.K. 9,019 11,966 -25 9,810 12,425 -21
Total oil and NGLs(*)
(bbls/d) 239,844 238,781 - 236,526 227,106 +4
-------------------------------------------------------------------------
Total sales (BOE/d)(*) 727,011 668,781 +9 731,193 668,939 +9
-------------------------------------------------------------------------
Prices, including
hedging
Natural Gas ($/Mcf)
Canada 6.12 4.11 +49 6.67 3.75 +78
U.S. 5.89 3.62 +63 7.09 3.53 +101
-------------------------------------------------------------------------
North American gas
($/Mcf) 6.06 4.02 +51 6.77 3.72 +82
-------------------------------------------------------------------------
North American oil
($/bbl)
Light/medium 32.22 33.76 -5 32.39 29.84 +9
Heavy 23.20 26.09 -11 23.08 23.95 -4
International crude oil
($/bbl)
Ecuador 29.50 31.63 -7 36.13 27.90 +29
U.K. 35.58 37.78 -6 39.25 34.15 +15
Natural gas liquids
($/bbl) 31.45 29.92 +5 37.41 26.34 +42
-------------------------------------------------------------------------
Total liquids ($/bbl) 28.23 30.59 -8 30.44 27.41 +11
-------------------------------------------------------------------------
(*) Excludes Syncrude which averaged 7,383 barrels per day in the second
quarter of 2003, compared to 24,295 barrels per day in the second
quarter of 2002. For the first six months of 2003, Syncrude averaged
13,792 barrels per day.
(2) See footnote on previous page


Forecast of 10 percent internal sales growth in 2003 and 2004 confirmed

Total 2003 daily oil, NGLs and natural gas 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
oil, NGLs and natural gas 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 forecast 2003
sales levels.


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

Normal Course Issuer Bid purchases

As of July 28, 2003, EnCana has invested approximately $358 million
purchasing 7,112,800 of its common shares for cancellation at an average price
of $50.38 per common share under the company's Normal Course Issuer Bid, which
allows for purchases of up to 23,843,565 common shares, representing 5 percent
of the outstanding shares on October 4, 2002. The company expects to continue
to purchase shares under the terms of its current bid and it intends to apply
to renew the bid, which expires October 21, 2003.

Dividend

The board of directors of EnCana declared a quarterly dividend of 10
cents per share payable on September 30, 2003 to common shareholders of record
as of September 12, 2003.


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

EnCana has one of the strongest balance sheets among North American
independents. At June 30, 2003, the company's debt-to-capitalization ratio was
28:72 (preferred securities included as debt). EnCana's debt-to-EBITDA
multiple, on a trailing 12-month basis, was 0.9 times. Second quarter capital
investment was $1,505 million. Net proceeds from asset dispositions were
$17 million, resulting in net capital investment of $1,488 million.
EnCana's 2003 net capital investment is forecast to be between
$2.5 billion and $2.9 billion as outlined below.

-------------------------------------------------------------------------
EnCana 2003 forecast capital program
(millions)
-------------------------------------------------------------------------
Core capital program (forecast) $ 5,000 - 5,400
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Additional capital
-------------------------------------------------------------------------
Ecuador reserves and land acquisition $ 180
-------------------------------------------------------------------------
Leased equipment purchases $ 290
-------------------------------------------------------------------------
OCP Pipeline completion requirements $ 100
-------------------------------------------------------------------------
Sub total $ 570
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Divestitures
-------------------------------------------------------------------------
Express and Cold Lake pipelines(3) $ (1,600)
-------------------------------------------------------------------------
Syncrude $ (1,500)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Sub total $ (3,100)
-------------------------------------------------------------------------
Net capital investment (forecast) $ 2,470 - 2,870
-------------------------------------------------------------------------
(3) $1.6 billion less $600 million of net assumption of debt resulted in
net cash proceeds of $1.0 billion.

EnCana maintains strong investment grade ratings from the major bond
rating services: Dominion Bond Rating Service Limited, A(low), Moody's
Investors Service, Baa1, and Standard and Poor's Ratings Services, A-. The
company also has a $4 billion credit facility with a syndicate of major banks
and lending institutions, of which more than $2.6 billion remains unutilized.


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

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

Second quarter natural gas and liquids sales up 12 percent year over year

North American gas, oil and NGLs sales continued to grow at double digit
rates in the second quarter, averaging 666,417 barrels of oil equivalent per
day - a 12 percent increase over the average of 595,618 barrels of oil
equivalent per day in the second quarter of 2002. Natural gas sales were up
13 percent, averaging 2.9 billion cubic feet per day. EnCana currently has no
produced gas in storage. Liquids production was up 9 percent year over year,
averaging 181,250 barrels per day. Growth in gas production was led by
increased production from the U.S. Rockies and the Greater Sierra area in
northeast B.C. Oil production continues to increase from EnCana's two steam-
assisted gravity drainage (SAGD) projects in northeast Alberta, as well as
from continued development at Pelican Lake and Suffield. In North America,
EnCana drilled 944 net wells during the second quarter and has about 100 rigs
running this summer from northeast B.C. to Colorado.

USA region growth strong, led by Rockies production

Second quarter gas sales from the USA region were up 63 percent to
average 698 million cubic feet per day, compared to an average of 428 million
cubic feet per day for the same period in 2002. Production growth is primarily
from the Jonah field in Wyoming and the Mamm Creek field in Colorado. In order
to help mitigate pricing risk due to gas transmission constraints out of the
U.S. Rockies, EnCana has fixed the NYMEX price differential on 576 million
cubic feet per day of forecast 2003 gas sales at an average basis of US$0.50
per thousand cubic feet, and 392 million cubic feet per day of forecast gas
sales for 2004 through 2007 at an average basis of US$0.44 per thousand cubic
feet.
"Our U.S. Rockies business continues to deliver very strong growth. We
are currently producing more than 700 million cubic feet per day and expect to
continue double-digit production growth for years to come," said Roger
Biemans, President of EnCana's USA Region.
In the Gulf of Mexico, appraisal drilling on the Tahiti discovery has
confirmed one of the most significant net pay accumulations in the history of
deep water drilling in the Gulf. EnCana continues to work with the operator in
development planning for this promising oil find.

Summer drilling ramps up in northeast British Columbia

Production from the Greater Sierra area of northeast B.C. averaged about
200 million cubic feet per day in the second quarter, an increase of more than
25 percent from one year earlier. EnCana has pioneered new ways to add value
in this high growth region through the use of interlocking wooden mats - a
simple technology that forms drilling islands in the soft Canadian muskeg.
Traditionally, northern exploration and drilling have been restricted to
winter only - the 100 days when the ground is frozen hard enough to permit the
movement of large equipment. But with the availability of more than 30,000
wooden mats, EnCana recently doubled its summer drilling plans from 35 to 70
wells, taking this year's target for Greater Sierra to about 170 wells.
"The use of these wooden mats can truly change the way oil and gas
companies do business during summer in the remote northern regions. Until now,
these wet muskeg lands have only seen modest drilling activity during the
warmest part of the year. We expect to reduce costs in both summer and winter
as we achieve a more balanced drilling program through the entire year," said
Randy Eresman, EnCana's Chief Operating Officer.
With a total land base of more than 2.4 million net acres along this
prolific gas trend, EnCana has a multi-year inventory of development drilling
locations. In anticipation of the region's growth potential, EnCana has
applied to the National Energy Board to construct a new, 80-kilometre pipeline
to deliver, by mid 2004, in excess of 100 million cubic feet of natural gas
from the company's Sierra gas plant to a connection on the Nova Gas
Transmission mainline in northwest Alberta. In addition, recent initiatives by
the B.C. government have improved the region's growth opportunities for
several years ahead.
"EnCana welcomes the province's recent plans to improve road
infrastructure, streamline the regulatory process, upgrade the Sierra Yoyo
Desan road and adopt a royalty structure that increases the region's
competitiveness. These progressive changes have added new confidence to our
strong expected growth and investment plans for B.C. We have expanded
investment and drilling in our world-class Greater Sierra resource play, where
the company now expects to grow production to more than 400 million cubic feet
per day over the next few years," Eresman said.

Next phase of SAGD growth well underway

With design capacity of 20,000 barrels per day of production successfully
achieved at Foster Creek, EnCana plans to increase oil production from its
largest SAGD project by about 10,000 barrels per day in 2004. An additional
six well pairs, taking the project's total to 30 well pairs, are being drilled
to tap additional reserves. Since May, the new Foster Creek co-generation
plant has been delivering about 40 megawatts of electricity to the Alberta
power grid, and output is expected to increase to its full capacity of 80
megawatts in the fourth quarter of 2003.


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

Second quarter oil and NGLs sales from international operations averaged
58,594 barrels per day, down about 18 percent from the second quarter last
year.

Ecuador oil production about to ramp up, first OCP Pipeline oil
deliveries expected this summer.

Second quarter sales in Ecuador averaged 49,575 barrels of oil per day,
down about 17 percent from an average of 59,864 barrels per day one year
earlier. The decrease is due to about 2,800 barrels per day having been
delivered to the new OCP Pipeline for commissioning, timing of shipments from
port and operational problems on the SOTE pipeline, currently Ecuador's main
oil export pipeline. EnCana's production capability is approximately 80,000
barrels per day, with additional capacity available to be added through the
last half of the year. Mainline and facilities construction of the OCP
Pipeline is nearing completion and it is expected that oil deliveries for
export will begin in mid to late August. EnCana production will be ramped up
once the OCP is fully operational, with a doubling of its production levels to
about 100,000 barrels per day targeted for 2004.
"EnCana is pleased to see the completion of this monumental economic
development for the people of Ecuador. This is the culmination of more than
four years of challenging work by EnCana and its partners that will see
critically-needed investment and revenue growth for this proud South American
nation," said Don Swystun, President of EnCana's Ecuador region.

EnCana expands interests in U.K. central North Sea, Buzzard development
progresses

EnCana has reached an agreement with Amerada Hess to acquire an
additional 14 percent interest in each of the Scott and Telford oil fields.
This transaction will increase EnCana's working interest in the Scott field
from 13.5 to 27.5 percent and in the Telford field from 20.2 to 34.2 percent
in exchange for EnCana's 22.5 percent non-producing working interest in the
Llano oil discovery in the Gulf of Mexico. On closing, expected this fall,
EnCana will become the largest working interest owner of both the Scott and
Telford fields, where EnCana is also seeking approval to become the operator.
Net production is anticipated to increase from a year-to-date production of
about 11,500 barrels of oil equivalent per day to approximately 20,000 barrels
of oil equivalent per day. In addition, EnCana has agreed to acquire Amerada
Hess' 42.1 percent working interest in Block 15/21 outside of the Scott and
Telford and Ivanhoe and Rob Roy field units.
In June, EnCana filed the environmental statement with the Department of
Trade and Industry for the development of the Buzzard field, which is expected
to start production in late 2006.


Midstream & Marketing
---------------------
EnCana's Midstream & Marketing division experienced a $40 million
operating cash flow loss in the second quarter of 2003, including the impact
of the regulatory settlement referred to in EnCana's July 28, 2003 news
release. The results reflect a challenging first half for gas storage, as low
summer/winter gas price spreads reduced demand for storage services and
limited margin opportunities. In addition, NGLs extraction was adversely
impacted by low processing margins as a result of the strong natural gas
prices. For the full year, operating cash flow is now expected to be in the
range of $100 million to $130 million.

New gas storage at Countess starts operations, Wild Goose expansion in
California ahead of schedule

EnCana has started injecting customers' natural gas into the first
10 billion cubic feet of new storage capacity at Countess, Alberta, located
about 85 kilometres east of Calgary. The second phase of Countess is expected
to take total capacity from 10 billion to about 40 billion cubic feet by April
2005. In northern California, Wild Goose Storage Inc. is expected to expand
the gas deliverability from the storage facility by November, four months
ahead of schedule and in time for the winter season. November withdrawal
capacity is expected to rise from 200 million to 320 million cubic feet per
day. This first phase of the Wild Goose expansion is expected to be fully
operational by April 2004, when withdrawal capacity is expected to more than
double from the current 200 million to 480 million cubic feet per day. Gas
storage capacity is planned to increase from 14 billion to approximately
24 billion cubic feet, while injection capacity is expected to rise from
80 million to 450 million cubic feet per day. A second phase of expansion
anticipates increasing capacity to about 29 billion cubic feet and withdrawal
rates to 700 million cubic feet per day by spring 2005, depending upon market
demand.

-------------------------------------------------------------------------
FINANCIAL INFORMATION
NOTE: All financial information in this news release is actual results,
except for the company's 2002 pro forma six-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 six 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 press release and EnCana's supplemental information, including
convenience financial statements prepared in $US, are posted on the
company's Web site: www.encana.com.
-------------------------------------------------------------------------

-------------------------------------------------------------------------
CONFERENCE CALL TODAY
EnCana Corporation will host a conference call today, Tuesday, July 29,
2003 starting at 11 a.m., Mountain Time (1 p.m. Eastern Time), to discuss
EnCana's second quarter 2003 financial and operating results.

To participate, please dial (719) 457-2658 approximately 10 minutes prior
to the conference call. An archived recording of the call will be
available from approximately 5 p.m. on July 29 until midnight August 8,
2003 by dialing (888) 203-1112 or (719) 457-0820 and entering pass code
342577.

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
with an enterprise value of approximately C$30 billion. EnCana is North
America's largest independent natural gas producer and gas storage operator.
Ninety percent of the company's assets are in four key North American growth
platforms. EnCana is the largest producer and landholder in Western Canada and
is a key player in Canada's emerging offshore East Coast basins. Through its
U.S. subsidiaries, EnCana is one of the largest gas explorers and producers in
the Rocky Mountain states and has a strong position in the deepwater Gulf of
Mexico. The company has two key high potential international growth platforms:
through its international subsidiaries, EnCana is the largest private sector
oil producer in Ecuador and is the operator of a large oil discovery in the
U.K. central North Sea. The company also conducts 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 interests of providing EnCana shareholders and
potential investors with information regarding EnCana, including management's
assessment of EnCana's and its subsidiaries' future plans and operations,
certain statements contained in this news release are forward-looking
statements within the meaning of the "safe harbour" provisions of the United
States Private Securities Litigation Reform Act of 1995. Forward-looking
statements in this news release and referenced in the conference call noted
above include, but are not limited to: future economic performance, including
production and sales growth targets for 2003, 2004 and beyond (including per
share sales growth); anticipated increases in production, including increases
achieved through successful drilling programs, from Ecuador upon completion of
the OCP pipeline, from the USA region and from the U.K.; the company's ability
to achieve per share sales and production growth targets over the next several
years and the predictability thereof; projected drilling activity in North
America in 2003 and beyond; resource potential, reserves and production
increases potentially available from the Company's resource plays, including
resource plays located in Alberta, British Columbia, Wyoming and Colorado; the
demand for gas storage and its effect on gas prices through the remainder of
2003; anticipated oil and natural gas prices for the remainder of 2003 and
continued volatility of world oil prices; forecast oil, gas and natural gas
liquids sales volumes for 2003; increased electrical generation capacity from
the Foster Creek co-generation plant expected in the fourth quarter of 2003;
the timing for completion and capacity of the company's proposed new pipeline;
the impact of EnCana's risk management program on commodity price, interest
rate and exchange rate volatility; increased oil production from SAGD projects
by 2004; the timing for commencement of oil shipments through the OCP pipeline
and projected capacity utilization in 2003 and 2004; the timing for completion
of the various phases of the Countess gas storage project and the Wild Goose
gas storage project in 2003, 2004, 2005 and beyond, and storage capacities,
injection and withdrawal rates upon completion; the timing for completion and
commencement of production from the Buzzard field; anticipated purchases under
the Company's Normal Course Issuer Bid program and the potential renewal of
the Normal Course Issuer Bid; increased capital expenditures for 2003; the
impact of the use of wooden mats on summer drilling and drilling costs;
EnCana's internal projections, expectations or beliefs concerning future
operating results, and various components thereof; EnCana's ability to invest
selectively and returns on such investments; and the production and growth
potential of EnCana's various assets, including assets in the U.S. Rockies,
Greater Sierra, offshore Canada's East Coast, the U.K. central North Sea, the
Gulf of Mexico and Ecuador.
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 made
against the company; the risk that the anticipated synergies to be realized by
the merger of AEC and PCE will not be realized; costs relating to the merger
of AEC and PCE being higher than anticipated and other risks and uncertainties
described from time to time in the reports and filings made with securities
regulatory authorities by EnCana. Although EnCana believes that the
expectations represented by such forward-looking statements are reasonable,
there can be no assurance that such expectations will prove to be correct.
Readers are cautioned that the foregoing list of important factors is not
exhaustive. Furthermore, the forward-looking statements contained in this news
release are made as of the date of this news release, and EnCana does not
undertake any obligation to update publicly or to revise any of the included
forward-looking statements, whether as a result of new information, future
events or otherwise. The forward-looking statements contained in this news
release are expressly qualified by this cautionary statement.



Consolidated Financial Statements

For the period ended June 30, 2003


EnCana Corporation


Interim Report
For the period ended June 30, 2003

EnCana Corporation
CONSOLIDATED STATEMENT OF EARNINGS

June 30
---------------------------------------
Three Months Ended Six Months Ended
---------------------------------------
(unaudited) ($ millions,
except per share amounts) 2003 2002 2003 2002
-------------------------------------------------------------------------

REVENUES, NET OF
ROYALTIES AND
PRODUCTION TAXES (Note 3) $ 3,194 $ 2,586 $ 7,262 $ 3,647

EXPENSES (Note 3)
Transportation
and selling 175 157 364 206
Operating 454 348 927 519
Purchased product 1,076 896 2,503 1,276
Administrative 60 44 116 61
Interest, net 84 103 170 130
Foreign
exchange (gain) (Note 5) (241) (170) (535) (180)
Depreciation,
depletion and
amortization 725 573 1,463 787
-------------------------------------------------------------------------
2,333 1,951 5,008 2,799
-------------------------------------------------------------------------
NET EARNINGS BEFORE
THE UNDERNOTED 861 635 2,254 848
Income tax (recovery)
expense (Note 6) (202) 153 235 235
-------------------------------------------------------------------------
NET EARNINGS FROM
CONTINUING OPERATIONS 1,063 482 2,019 613
NET EARNINGS (LOSS)
FROM DISCONTINUED
OPERATIONS (Note 4) 3 (24) 293 (22)
-------------------------------------------------------------------------
NET EARNINGS $ 1,066 $ 458 $ 2,312 $ 591
DISTRIBUTIONS ON
PREFERRED SECURITIES,
NET OF TAX (9) 1 (15) 1
-------------------------------------------------------------------------
NET EARNINGS ATTRIBUTABLE
TO COMMON SHAREHOLDERS $ 1,075 $ 457 $ 2,327 $ 590
-------------------------------------------------------------------------
-------------------------------------------------------------------------

NET EARNINGS FROM
CONTINUING OPERATIONS
PER COMMON SHARE (Note 9)
Basic $ 2.23 $ 1.04 $ 4.23 $ 1.71
Diluted $ 2.20 $ 1.02 $ 4.19 $ 1.68
-------------------------------------------------------------------------
-------------------------------------------------------------------------

NET EARNINGS PER
COMMON SHARE (Note 9)
Basic $ 2.24 $ 0.99 $ 4.84 $ 1.65
Diluted $ 2.21 $ 0.97 $ 4.79 $ 1.62
-------------------------------------------------------------------------
-------------------------------------------------------------------------


CONSOLIDATED STATEMENT OF RETAINED EARNINGS
Six Months Ended
June 30
-------------------
(unaudited) ($ millions) 2003 2002
-------------------------------------------------------------------------

RETAINED EARNINGS,
BEGINNING OF YEAR $ 4,684 $ 3,630
Net Earnings 2,312 591
Dividends on Common
Shares and Other
Distributions,
net of tax (81) (74)
Charges for Normal
Course Issuer Bid (Note 8) (15) -
-------------------------------------------------------------------------
RETAINED EARNINGS,
END OF PERIOD $ 6,900 $ 4,147
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.



Interim Report
For the period ended June 30, 2003

EnCana Corporation
CONSOLIDATED BALANCE SHEET
As at As at
June December
30, 31,
(unaudited) ($ millions) 2003 2002
-------------------------------------------------------------------------

ASSETS
Current Assets
Cash and cash equivalents $ 406 $ 183
Accounts receivable and accrued revenue 1,567 1,987
Income tax receivable 208 -
Inventories 652 528
Assets of discontinued operations (Note 4) 571 3,422
-------------------------------------------------------------------------
3,404 6,120
Capital Assets, net (Note 3) 23,185 22,356
Investments and Other Assets 545 377
Goodwill 2,469 2,469
-------------------------------------------------------------------------
(Note 3) $ 29,603 $ 31,322
-------------------------------------------------------------------------
-------------------------------------------------------------------------


LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued liabilities $ 2,109 $ 2,282
Income tax payable - 20
Liabilities of discontinued operations (Note 4) 140 1,758
Current portion of long-term debt (Note 7) 150 212
-------------------------------------------------------------------------
2,399 4,272
Long-Term Debt (Note 7) 6,122 7,395
Deferred Credits and Other Liabilities 565 564
Future Income Taxes 5,161 4,840
Preferred Securities of Subsidiary - 457
-------------------------------------------------------------------------
14,247 17,528
-------------------------------------------------------------------------
Shareholders' Equity
Preferred securities 549 126
Share capital (Note 8) 8,791 8,732
Share options, net 102 133
Paid in surplus - 61
Retained earnings 6,900 4,684
Foreign currency translation adjustment (986) 58
-------------------------------------------------------------------------
15,356 13,794
-------------------------------------------------------------------------
$ 29,603 $ 31,322
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.



Interim Report
For the period ended June 30, 2003

EnCana Corporation
CONSOLIDATED STATEMENT OF CASH FLOWS

June 30
---------------------------------------
Three Months Ended Six Months Ended
---------------------------------------
(unaudited) ($ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------

OPERATING ACTIVITIES
Net earnings from
continuing operations $ 1,063 $ 482 $ 2,019 $ 613
Depreciation, depletion
and amortization 725 573 1,463 787
Future income taxes (Note 6) (131) 106 272 148
Other (174) (257) (464) (257)
-------------------------------------------------------------------------
Cash flow from
continuing operations 1,483 904 3,290 1,291
Cash flow from
discontinued operations (45) 34 - 36
-------------------------------------------------------------------------
Cash flow 1,438 938 3,290 1,327
Net change in other
assets and liabilities (17) - (23) -
Net change in non-cash
working capital from
continuing operations 8 (240) 61 (508)
Net change in non-cash
working capital from
discontinued operations 65 (11) 82 42
-------------------------------------------------------------------------
1,494 687 3,410 861
-------------------------------------------------------------------------

INVESTING ACTIVITIES
Business combination - (128) - (128)
Capital expenditures (Note 3) (1,505) (1,390) (3,031) (1,871)
Proceeds on disposal
of capital assets 17 240 27 243
Corporate acquisition (Note 2) - - (179) -
Equity investments (122) - (188) -
Net change in
investments and other (6) 5 (40) (12)
Net change in non-cash
working capital from
continuing operations (33) (219) (236) (250)
Discontinued operations (15) (69) 1,948 (69)
-------------------------------------------------------------------------
(1,664) (1,561) (1,699) (2,087)
-------------------------------------------------------------------------

FINANCING ACTIVITIES
Net issuance (repayment)
of long-term debt 505 572 (840) 492
Issuance of
common shares (Note 8) 76 51 120 69
Repurchase of
common shares (Note 8) (168) - (168) -
Dividends on
common shares (48) (48) (96) (73)
Payments to preferred
securities holders (4) (7) (12) (7)
Net change in non-cash
working capital from
continuing operations (3) 2 (8) (1)
Discontinued operations - (5) (438) (5)
Other (17) (32) (18) (32)
-------------------------------------------------------------------------
341 533 (1,460) 443
-------------------------------------------------------------------------

DEDUCT: FOREIGN EXCHANGE
LOSS ON CASH AND
CASH EQUIVALENTS HELD
IN FOREIGN CURRENCY 25 9 28 11

INCREASE (DECREASE) IN
CASH AND CASH
EQUIVALENTS 146 (350) 223 (794)
CASH AND CASH
EQUIVALENTS, BEGINNING
OF PERIOD 260 503 183 947
-------------------------------------------------------------------------
CASH AND CASH
EQUIVALENTS,
END OF PERIOD $ 406 $ 153 $ 406 $ 153
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.



Interim Report
For the period ended June 30, 2003

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 ACQUISITION

On January 31, 2003, the Company acquired the Ecuadorian interests of
Vintage Petroleum Inc. for net cash consideration of $179 million
(US$116 million). The purchase was accounted for using the purchase
method with the results reflected in the consolidated results of
EnCana from the date of acquisition. The acquisition was accounted
for as follows:

($ millions)
-------------------------------------------------------------------------
Working Capital $ 2
Capital Assets 194
Future Income Taxes (17)
-------------------------------------------------------------------------
$ 179
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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 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 June 30)

Upstream Midstream & Marketing
-------------------------------------------------------------------------
($ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Gross revenue $ 2,453 $ 1,773 $ 1,173 $ 1,091
Royalties and production
taxes 434 281 - -
-------------------------------------------------------------------------
Revenues, net of royalties
and production taxes 2,019 1,492 1,173 1,091

Expenses
Transportation and selling 154 107 21 50
Operating 338 270 116 78
Purchased product - - 1,076 896
Depreciation, depletion
and amortization 700 535 10 26
-------------------------------------------------------------------------
Segment Income $ 827 $ 580 $ (50) $ 41
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Corporate Consolidated
-------------------------------------------------------------------------
2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Gross revenue $ 2 $ 3 $ 3,628 $ 2,867
Royalties and production
taxes - - 434 281
-------------------------------------------------------------------------
Revenues, net of royalties
and production taxes 2 3 3,194 2,586

Expenses
Transportation and selling - - 175 157
Operating - - 454 348
Purchased product - - 1,076 896
Depreciation, depletion and
amortization 15 12 725 573
-------------------------------------------------------------------------
Segment Income (13) (9) 764 612
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Administrative 60 44 60 44
Interest, net 84 103 84 103
Foreign exchange (gain) (241) (170) (241) (170)
-------------------------------------------------------------------------
(97) (23) (97) (23)
-------------------------------------------------------------------------
Net Earnings Before Income Tax 84 14 861 635
Income tax (recovery) expense (202) 153 (202) 153
-------------------------------------------------------------------------
Net Earnings from Continuing
Operations $ 286 $ (139) $ 1,063 $ 482
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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

Upstream North America
-----------------------------------------------------
Produced Gas and NGLs
-----------------------------------------------------
Canada U.S. Rockies Crude Oil
($ millions) 2003 2002 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Gross revenue $ 1,376 $ 954 $ 440 $ 175 $ 396 $ 398
Royalties and
production taxes 221 132 119 42 50 48
-------------------------------------------------------------------------
Revenues, net of
royalties and
production taxes 1,155 822 321 133 346 350

Expenses
Transportation
and selling 86 57 26 25 26 10
Operating 121 107 22 15 107 84
Depreciation,
depletion and
amortization 385 290 94 75 150 107
-------------------------------------------------------------------------
Segment Income $ 563 $ 368 $ 179 $ 18 $ 63 $ 149
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Ecuador U.K. North Sea
-----------------------------------
2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Gross revenue $ 144 $ 182 $ 33 $ 45
Royalties and production taxes 44 59 - -
-------------------------------------------------------------------------
Revenues, net of royalties and
production taxes 100 123 33 45

Expenses
Transportation and selling 11 10 5 5
Operating 26 31 5 3
Depreciation, depletion and
amortization 43 51 26 9
-------------------------------------------------------------------------
Segment Income $ 20 $ 31 $ (3) $ 28
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Non-Producing Total Upstream
-----------------------------------
2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Gross revenue $ 64 $ 19 $ 2,453 $ 1,773
Royalties and production taxes - - 434 281
-------------------------------------------------------------------------
Revenues, net of royalties and
production taxes 64 19 2,019 1,492

Expenses
Transportation and selling - - 154 107
Operating 57 30 338 270
Depreciation, depletion and
amortization 2 3 700 535
-------------------------------------------------------------------------
Segment Income $ 5 $ (14) $ 827 $ 580
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Midstream & Marketing Total Midstream
Midstream Marketing (*) & Marketing
-----------------------------------------------------
($ millions) 2003 2002 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Gross revenue $ 211 $ 157 $ 962 $ 934 $ 1,173 $ 1,091

Expenses
Transportation
and selling - - 21 50 21 50
Operating 73 78 43 - 116 78
Purchased product 150 51 926 845 1,076 896
Depreciation,
depletion and
amortization 10 20 - 6 10 26
-------------------------------------------------------------------------
Segment Income $ (22) $ 8 $ (28) $ 33 $ (50) $ 41
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) includes 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 six months ended June 30)

Midstream
Upstream & Marketing
-----------------------------------
($ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Gross revenue $ 5,369 $ 2,427 $ 2,824 $ 1,570
Royalties and production taxes 933 349 - -
-------------------------------------------------------------------------
Revenues, net of royalties and
production taxes 4,436 2,078 2,824 1,570

Expenses
Transportation and selling 316 151 48 55
Operating 669 380 258 139
Purchased product - - 2,503 1,276
Depreciation, depletion and
amortization 1,420 738 18 31
-------------------------------------------------------------------------
Segment Income $ 2,031 $ 809 $ (3) $ 69
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Corporate Consolidated
-----------------------------------
2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Gross revenue $ 2 $ (1) $ 8,195 $ 3,996
Royalties and production taxes - - 933 349
-------------------------------------------------------------------------
Revenues, net of royalties and
production taxes 2 (1) 7,262 3,647

Expenses
Transportation and selling - - 364 206
Operating - - 927 519
Purchased product - - 2,503 1,276
Depreciation, depletion and
amortization 25 18 1,463 787
-------------------------------------------------------------------------
Segment Income (23) (19) 2,005 859
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Administrative 116 61 116 61
Interest, net 170 130 170 130
Foreign exchange (gain) (535) (180) (535) (180)
-------------------------------------------------------------------------
(249) 11 (249) 11
-------------------------------------------------------------------------
Net Earnings Before Income Tax 226 (30) 2,254 848
Income tax expense 235 235 235 235
-------------------------------------------------------------------------
Net Earnings from Continuing
Operations $ (9) $ (265) $ 2,019 $ 613
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Geographic and Product Information (For the six months ended June 30)

Upstream North America
-----------------------------------------------------
Produced Gas and NGLs
Canada U.S. Rockies Crude Oil
-----------------------------------------------------
($ millions) 2003 2002 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Gross revenue $ 3,053 $ 1,312 $ 1,011 $ 207 $ 791 $ 602
Royalties and
production taxes 445 160 263 49 115 81
-------------------------------------------------------------------------
Revenues, net of
royalties and
production taxes 2,608 1,152 748 158 676 521

Expenses
Transportation
and selling 178 88 49 25 57 18
Operating 256 151 37 20 209 136
Depreciation,
depletion and
amortization 787 407 194 92 297 163
-------------------------------------------------------------------------
Segment Income $ 1,387 $ 506 $ 468 $ 21 $ 113 $ 204
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Ecuador U.K. North Sea
-----------------------------------
2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Gross revenue $ 323 $ 182 $ 82 $ 89
Royalties and production taxes 110 59 - -
-------------------------------------------------------------------------
Revenues, net of royalties and
production taxes 213 123 82 89

Expenses
Transportation and selling 21 10 11 10
Operating 48 31 9 6
Depreciation, depletion and
amortization 78 51 60 19
-------------------------------------------------------------------------
Segment Income $ 66 $ 31 $ 2 $ 54
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Non-Producing Total Upstream
-----------------------------------
2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Gross revenue $ 109 $ 35 $ 5,369 $ 2,427
Royalties and production taxes - - 933 349
-------------------------------------------------------------------------
Revenues, net of royalties and
production taxes 109 35 4,436 2,078

Expenses
Transportation and selling - - 316 151
Operating 110 36 669 380
Depreciation, depletion and
amortization 4 6 1,420 738
-------------------------------------------------------------------------
Segment Income $ (5) $ (7) $ 2,031 $ 809
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Midstream & Marketing Total Midstream
Midstream Marketing (*) & Marketing
-----------------------------------------------------
($ millions) 2003 2002 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues
Gross revenue $ 692 $ 230 $ 2,132 $ 1,340 $ 2,824 $ 1,570

Expenses
Transportation
and selling - - 48 55 48 55
Operating 193 133 65 6 258 139
Purchased product 458 51 2,045 1,225 2,503 1,276
Depreciation,
depletion and
amortization 17 24 1 7 18 31
-------------------------------------------------------------------------
Segment Income $ 24 $ 22 $ (27) $ 47 $ (3) $ 69
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) includes 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 Six Months Ended
June 30 June 30
-------------------------------------------
($ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------
Upstream
Canada $ 944 $ 699 $ 2,012 $ 1,047
United States 274 537 501 624
Ecuador 47 72 157 72
United Kingdom 14 23 38 62
Other Countries 43 36 68 39
Midstream & Marketing 156 16 210 17
Corporate 27 7 45 10
-------------------------------------------------------------------------
Total $ 1,505 $ 1,390 $ 3,031 $ 1,871
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Capital and Total Assets
Capital Assets Total Assets
-------------------------------------------
As at As at
-------------------------------------------
December December
June 30, 31, June 30, 31,
($ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------
Upstream $ 22,061 $ 21,422 $ 23,392 $ 25,192
Midstream & Marketing 902 742 3,110 2,216
Corporate 222 192 2,530 492
Assets of Discontinued
Operations 571 3,422
-------------------------------------------------------------------------
Total $ 23,185 $ 22,356 $ 29,603 $ 31,322
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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
proceeds of $417 million, subject to closing adjustments. This
transaction completes 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 June 30
-------------------------------------------
Syncrude Merchant Energy
-------------------------------------------
($ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues, net of royalties
and production taxes $ 28 $ 90 $ - $ 563
-------------------------------------------------------------------------

Expenses
Transportation and selling 1 1 - -
Operating 20 68 - -
Purchased product - - - 580
Administrative - - - 8
Interest, net - - - -
Foreign exchange - - - -
Depletion, depreciation and
amortization 2 7 - 1
Loss on discontinuance - - - 53
-------------------------------------------------------------------------
23 76 - 642
-------------------------------------------------------------------------
Net Earnings Before Income Tax 5 14 - (79)
Income tax expense (recovery) 2 2 - (28)
-------------------------------------------------------------------------
Net Earnings (Loss) from
Discontinued Operations $ 3 $ 12 $ - $ (51)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

For the three months ended June 30
-------------------------------------------
Midstream - Pipelines Total
-------------------------------------------
($ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues, net of royalties
and production taxes $ - $ 58 $ 28 $ 711
-------------------------------------------------------------------------

Expenses
Transportation and selling - - 1 1
Operating - 20 20 88
Purchased product - - - 580
Administrative - - - 8
Interest, net - 11 - 11
Foreign exchange - (10) - (10)
Depletion, depreciation and
amortization - 11 2 19
Loss on discontinuance - - - 53
-------------------------------------------------------------------------
- 32 23 750
-------------------------------------------------------------------------
Net Earnings Before Income Tax - 26 5 (39)
Income tax expense (recovery) - 11 2 (15)
-------------------------------------------------------------------------
Net Earnings (Loss) from
Discontinued Operations $ - $ 15 $ 3 $ (24)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Consolidated Statement of Earnings

For the six months ended June 30
-------------------------------------------
Syncrude(*) Merchant Energy
-------------------------------------------
($ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues, net of royalties
and production taxes $ 118 $ 90 $ - $ 1,309
-------------------------------------------------------------------------

Expenses
Transportation and selling 2 1 - -
Operating 63 68 - -
Purchased product - - - 1,313
Administrative - - - 18
Interest, net - - - -
Foreign exchange - - - -
Depletion, depreciation
and amortization 9 7 - 1
(Gain) loss on
discontinuance - - - 53
-------------------------------------------------------------------------
74 76 - 1,385
-------------------------------------------------------------------------
Net Earnings Before
Income Tax 44 14 - (76)
Income tax expense (recovery) 14 2 - (27)
-------------------------------------------------------------------------
Net Earnings (Loss) from
Discontinued Operations $ 30 $ 12 $ - $ (49)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

For the six months ended June 30
-------------------------------------------
Midstream - Pipelines(*) Total
-------------------------------------------
($ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------
Revenues, net of royalties
and production taxes $ - $ 58 $ 118 $ 1,457
-------------------------------------------------------------------------

Expenses
Transportation and selling - - 2 1
Operating - 20 63 88
Purchased product - - - 1,313
Administrative - - - 18
Interest, net - 11 - 11
Foreign exchange - (10) - (10)
Depletion, depreciation
and amortization - 11 9 19
(Gain) loss on
discontinuance (343) - (343) 53
-------------------------------------------------------------------------
(343) 32 (269) 1,493
-------------------------------------------------------------------------
Net Earnings Before
Income Tax 343 26 387 (36)
Income tax expense (recovery) 80 11 94 (14)
-------------------------------------------------------------------------
Net Earnings (Loss) from
Discontinued Operations $ 263 $ 15 $ 293 $ (22)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) Reflects only three months of earnings for 2002 as EnCana did not, at
that time, own the operations which have been discontinued.


Consolidated Balance Sheet

As at June 30
-------------------------------------------
Syncrude Merchant Energy
-------------------------------------------
($ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------
Assets
Cash and cash equivalents $ 8 $ 14 $ - $ -
Accounts receivable and
accrued revenue 14 27 - 338
Inventories 4 15 - -
-------------------------------------------------------------------------
26 56 - 338
Capital assets, net 426 1,273 - -
Investments and other assets - - - -
Goodwill 119 417 - -
-------------------------------------------------------------------------
571 1,746 - 338
-------------------------------------------------------------------------
Liabilities
Accounts payable and
accrued liabilities 21 94 - 240
Income tax payable 55 6 - -
Current portion of
long-term debt - - - -
-------------------------------------------------------------------------
76 100 - 240
Deferred credits and
other liabilities 6 21 - -
Long-term debt - - - -
Future income taxes 58 317 - -
-------------------------------------------------------------------------
140 438 - 240
-------------------------------------------------------------------------
Net Assets of Discontinued
Operations $ 431 $ 1,308 $ - $ 98
-------------------------------------------------------------------------
-------------------------------------------------------------------------

As at June 30
-------------------------------------------
Midstream - Pipelines Total
-------------------------------------------
($ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------
Assets
Cash and cash equivalents $ - $ 66 $ 8 $ 80
Accounts receivable and
accrued revenue - 44 14 409
Inventories - 1 4 16
-------------------------------------------------------------------------
- 111 26 505
Capital assets, net - 807 426 2,080
Investments and other assets - 417 - 417
Goodwill - 191 119 608
-------------------------------------------------------------------------
- 1,526 571 3,610
-------------------------------------------------------------------------
Liabilities
Accounts payable and
accrued liabilities - 68 21 402
Income tax payable - 4 55 10
Current portion of
long-term debt - 23 - 23
-------------------------------------------------------------------------
- 95 76 435
Deferred credits and
other liabilities - - 6 21
Long-term debt - 567 - 567
Future income taxes - 163 58 480
-------------------------------------------------------------------------
- 825 140 1,503
-------------------------------------------------------------------------
Net Assets of Discontinued
Operations $ - $ 701 $ 431 $ 2,107
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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 liabilities 21 2
Future income taxes 536 -
-------------------------------------------------------------------------
1,758 586
-------------------------------------------------------------------------
Net Assets of Discontinued Operations $ 1,664 $ 142
-------------------------------------------------------------------------
-------------------------------------------------------------------------


5. FOREIGN EXCHANGE (GAIN)

Three Months Ended Six Months Ended
June 30 June 30
-------------------------------------------
($ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------
Unrealized foreign exchange
(gain) on translation of
U.S. dollar debt $ (248) $ (192) $ (493) $ (194)
Other foreign exchange losses
(gains) 7 22 (42) 14
-------------------------------------------------------------------------
$ (241) $ (170) $ (535) $ (180)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


6. INCOME TAXES

Three Months Ended Six Months Ended
June 30 June 30
-------------------------------------------
($ millions) 2003 2002 2003 2002
-------------------------------------------------------------------------

Provision for Income Taxes
Current
Canada $ (81) $ 27 $ (59) $ 64
United States - 8 - 8
Ecuador 7 7 19 7
United Kingdom 3 5 3 8
-------------------------------------------------------------------------
(71) 47 (37) 87
Future 355 148 758 190
Future tax rate reductions(*) (486) (42) (486) (42)
-------------------------------------------------------------------------
$ (202) $ 153 $ 235 $ 235
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) During the quarter both the Canadian federal and Alberta governments
substantively enacted income tax rate reductions previously
announced.


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

Canadian Dollar Denominated Debt
Revolving credit and term loan borrowings $ 1,043 $ 1,388
Unsecured notes and debentures 1,825 1,825
-------------------------------------------------------------------------
2,868 3,213
-------------------------------------------------------------------------

U.S. Dollar Denominated Debt
U.S. revolving credit and term loan borrowings 317 696
U.S. unsecured notes and debentures 2,999 3,608
-------------------------------------------------------------------------
3,316 4,304
-------------------------------------------------------------------------

Increase in Value of Debt Acquired (Note A) 88 90
Current Portion of Long-term Debt (150) (212)
-------------------------------------------------------------------------
$ 6,122 $ 7,395
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(A) Increase in Value of Debt Acquired

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 24 years.


8. SHARE CAPITAL

June 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 4.3 120 5.5 139
Shares Repurchased (3.3) (61) - -
-------------------------------------------------------------------------
Common Shares Outstanding,
End of Period 479.9 $ 8,791 478.9 $ 8,732
-------------------------------------------------------------------------
-------------------------------------------------------------------------

During the quarter, the Company purchased, for cancellation, 3,342,900
common shares for total consideration of approximately $168 million. Of
the $168 million paid, $61 million was charged to Share capital,
$92 million was charged to Paid in surplus and $15 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 June 30, 2003:

Weighted
Stock Average
Options Exercise
(millions) Price ($)
-------------------------------------------------------------------------
Outstanding, Beginning of Year 29.6 39.74
Granted under EnCana Plans 5.8 47.50
Exercised (4.3) 28.09
Forfeited (0.8) 47.34
-------------------------------------------------------------------------
Outstanding, End of Period 30.3 42.71
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Exercisable, End of Period 16.4 38.29
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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 1.9 1.1 18.86 1.9 18.86
20.00 to
24.99 1.4 1.9 22.33 1.4 22.33
25.00 to
29.99 2.4 1.9 26.52 2.4 26.52
30.00 to
43.99 1.5 2.7 38.69 1.3 38.18
44.00 to
53.00 23.1 3.8 47.90 9.4 47.71
-------------------------------------------------------------------------
30.3 2.9 42.71 16.4 38.29
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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:

Six Months Ended
June 30
---------------------
($ millions, except per share amounts) 2003 2002
-------------------------------------------------------------------------

Compensation Costs 33 50

Net Earnings
As reported 2,312 591
Pro forma 2,279 541

Net Earnings per Common Share
Basic
As reported 4.84 1.65
Pro forma 4.78 1.51
Diluted
As reported 4.79 1.62
Pro forma 4.72 1.48
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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:

Six Months Ended
June 30
---------------------
2003 2002
-------------------------------------------------------------------------
Weighted Average Fair Value of Options Granted $ 12.18 $ 13.40
Risk Free Interest Rate 3.96% 4.46%
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.

Three Months Ended Six Months Ended
------------------------------------------------------
March 31 June 30 June 30
------------------------------------------------------
(millions) 2003 2003 2002 2003 2002
-------------------------------------------------------------------------
Weighted Average
Common Shares
Outstanding - Basic 479.9 480.6 461.1 480.3 358.2
Effect of Dilutive
Securities 7.0 6.3 8.9 6.0 6.8
-------------------------------------------------------------------------
Weighted Average
Common Shares
Outstanding -
Diluted 486.9 486.9 470.0 486.3 365.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------


10. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

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

As at
($ millions) June 30, 2003
-------------------------------------------------------------------------
Commodity Price Risk
Natural gas $ 211
Crude oil (240)
Gas storage optimization 32
Power 5
Foreign Currency Risk 39
Interest Rate Risk 65
-------------------------------------------------------------------------
Unrecognized Gains $ 112
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Information with respect to 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.

Natural Gas

At June 30, 2003, the fair value of financial instruments that related to
the corporate gas risk management activities was $167 million. The
contracts were as follows:

Unrecognized
Notional Gain/(Loss)
Volumes Physical/ (Cdn$
(MMcf/d) Financials Term Price millions)
-------------------------------------------------------------------------
Fixed Price
Contracts
Sales
Contracts
Fixed AECO
price 565 Financial 2003 6.36 Cdn$/mcf $ (24)
Fixed AECO
price 10 Financial 2003 3.37 US$/mmbtu (4)
Fixed AECO
price 5 Physical 2003 5.88 Cdn$/mcf (1)
Fixed AECO
price 10 Physical 2003 3.34 US$/mmbtu (4)
Nymex Fixed
price(*) 526 Financial 2003 4.50 US$/mmbtu (134)
Nymex
Collars 50 Physical 2003 2.46-4.90 US$/mmbtu (10)
Alliance
Pipeline
Mitigation 27 Financial 2003 3.92 US$/mmbtu (11)
Fixed AECO
price 453 Financial 2004 6.20 Cdn$/mcf 10
AECO Collars 71 Financial 2004 5.34-7.52 Cdn$/mcf 1
Nymex Fixed
price(*) 291 Financial 2004 5.06 US$/mmbtu (18)
Chicago Fixed
price 40 Financial 2004 5.42 US$/mmbtu 3
Nymex Collars 10 Financial 2004 4.60-6.55 US$/mmbtu 1
Nymex Collars 50 Physical 2004 2.46-4.90 US$/mmbtu (21)

Nymex Collars 47 Physical 2005- 2.46-4.90 US$/mmbtu (47)
2007
Purchase Contracts
Alliance
Pipeline
Mitigation 30 Physical 2003 3.24 Cdn$/mcf 18

Basis Contracts
Sales Contracts
Fixed NYMEX
to AECO
basis(*) 368 Financial 2003 (0.55) US$/mmbtu 13
Fixed Nymex
to Rockies
basis 220 Financial 2003 (0.49) US$/mmbtu 18
Fixed Nymex
to Rockies
basis 356 Physical 2003 (0.51) US$/mmbtu 27
Fixed NYMEX
to AECO
basis(*) 271 Financial 2004 (0.50) US$/mmbtu 32
Fixed Nymex
to Rockies
basis 190 Financial 2004 (0.42) US$/mmbtu 39
Fixed Nymex
to Rockies
basis 343 Physical 2004 (0.46) US$/mmbtu 64
Fixed NYMEX
to AECO
basis(*) 387 Financial 2005- (0.59) US$/mmbtu 81
2007
Fixed Nymex
to Rockies
basis 132 Financial 2005- (0.44) US$/mmbtu 50
2007
Fixed Nymex
to Rockies
basis 214 Physical 2005- (0.43) US$/mmbtu 84
2007
-------------------------------------------------------------------------
167
Gas Marketing
Financial
positions(1) 7
Gas Marketing
Physical
positions(1) 37
-------------------------------------------------------------------------
$ 211
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) 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.


Crude Oil

As at June 30, 2003, the Company's corporate oil risk management
activities had an unrecognized loss of $240 million. The contracts were
as follows:

Notional Average Unrecognized
Volumes Price Gain/(Loss)
(bbl/d) Term (US$/bbl) (Cdn$ millions)
-------------------------------------------------------------------------
Fixed WTI NYMEX Price 85,000 2003 25.28 $ (77)
Fixed WTI NYMEX Price 62,500 2004 23.13 (88)
Collars on WTI NYMEX 40,000 2003 21.95-29.00 (15)
Collars on WTI NYMEX 62,500 2004 20.00-25.69 (60)
-------------------------------------------------------------------------
$ (240)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Gas Storage Optimization

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

As at June 30, 2003, the unrecognized gain was as follows:

Notional Unrecognized
Volumes Price Gain/(Loss)
(bcf) (US$/mcf) (Cdn$ millions)
-------------------------------------------------------------------------
Purchases 171.9 5.68 $ (34)
Sales 198.1 5.81 53
-------------------------------------------------------------------------
19
Physical Contracts 13
-------------------------------------------------------------------------
$ 32
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
The unrecognized gain does not reflect unrealized gains on physical
inventory in storage.


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: EnCana Corporate Development, Sheila McIntosh, Senior Vice-President, Investor Relations (403) 645-2194; Greg Kist, Manager, Investor Relations, (403) 645-4737, Media contact: Alan Boras, Manager, Media Relations, (403) 645-4747

ECA stock price

TSX $15.12 Can 0.200

NYSE $11.85 USD 0.160

As of 2017-11-17 16:02. Minimum 15 minute delay