EnCana earns $1.25 billion in 2002, cash flow exceeds $4.2 billion

Annual sales increase 12 percent to 723,000 barrels of oil equivalent per day Natural gas sales surpass 3 billion cubic feet per day in fourth quarter

CALGARY, Feb. 20 /CNW/ - EnCana Corporation (TSX & NYSE: ECA) earned pro
forma $1.254 billion, or $2.59 per common share diluted, in 2002 and generated
pro forma $4.211 billion of cash flow, or $8.71 per common share diluted.
Daily pro forma oil and gas sales exceeded the midpoint of the company's 2002
target range, averaging 723,000 barrels of oil equivalent (BOE), up 12 percent
per common share from the pro forma 2001 results of EnCana's legacy companies.
Daily sales were comprised of about 2.8 billion cubic feet of natural gas, up
16 percent per share in the past year, and about 263,000 barrels of oil and
natural gas liquids (NGLs), up 5 percent per share over pro forma sales in
2001. Conventional operating and administrative costs on a pro forma basis in
2002 were approximately $4.77 per barrel of oil equivalent.
All references to 2001 production and sales and 2002 production, sales
and financial information in this news release text and tables for EnCana are
presented on a pro forma basis as if the merger of PanCanadian Energy
Corporation ("PanCanadian" or "PCE") and Alberta Energy Company Ltd. ("AEC")
had occurred at the beginning of the respective periods. All $ figures are
Canadian unless otherwise stated.
"2002 can only be described as a year of remarkable achievement for
EnCana. Just over one year ago, we set out to create a best-in-class
independent oil and gas company. We have made tremendous progress towards that
goal," said Gwyn Morgan, EnCana's President & Chief Executive Officer.
"In our inaugural year, we created the world's largest independent,
surpassed the midpoint of our sales growth targets, replaced production by
190 percent on a proved basis, increasing total conventional proved reserves
by 10 percent, and refined our strategy to concentrate on premium growth, high
return conventional exploration and production investments," Morgan said.
"EnCana's strategy is focused on operated, high working interest
conventional oil and gas properties where we believe we can leverage our core
competencies, control the pace of development and manage capital and operating
costs," Morgan said. "In the past year, we've put this strategy into action.
We sold our interests in two major oil pipelines, reached an agreement to sell
a 10 percent interest in Syncrude, and divested of approximately $700 million
in non-core properties and assets. We acquired high quality natural gas assets
through two complementary acquisitions in the U.S. Rockies, brought the
world's first large scale steam-assisted gravity drainage (SAGD) project
on stream and participated in a world-class Gulf of Mexico discovery. And,
EnCana shares achieved a total return of 19 percent, including dividends, in
2002," Morgan said.

Strong fourth quarter earnings and cash flow, gas sales rise 21 percent
During the fourth quarter of 2002, EnCana earned $429 million, or $0.88
per common share diluted. Cash flow was $1.472 billion, or $3.03 per common
share diluted. Revenues, net of royalties and production taxes, in the fourth
quarter were $3.392 billion, while capital investment, including acquisitions
and dispositions, was $1.223 billion. Fourth quarter natural gas sales
averaged 3.04 billion cubic feet per day, up 21 percent over pro forma results
in the fourth quarter of 2001. EnCana withdrew an average of 149 million cubic
feet per day of natural gas from storage to capitalize on strong seasonal
prices. Oil and NGLs sales averaged 271,000 barrels per day, up about
8 percent, compared to pro forma results in the fourth quarter of 2001.
Conventional operating plus administrative costs were approximately $4.93 per
barrel of oil equivalent in the quarter. EnCana drilled 905 net wells in the
fourth quarter.
"With a successful first year in the books, we believe EnCana is poised
to continue to grow annual sales by an average of 10 percent per common share
for several years ahead. We intend to manage our capital investment to target
the highest returns and profitability from our premium quality assets in North
America and in select offshore and international locations," Morgan said. "Add
to that advantage the continent's largest independent network of natural gas
storage, and you have a powerful enterprise able to turn prospects into
production, reserves into revenue and a unique vision into shareholder value."

EnCana continues to grow per share value with strong reserve additions
During 2002, EnCana added 473 million barrels of oil equivalent of
conventional proved reserves, which is equivalent to replacing 190 percent of
2002 production on a proved basis. The company's proved reserve replacement
cost was C$9.60 per barrel of oil equivalent (US$8.20 after royalties). The
company drilled 3,019 net wells in 2002.
"The heart of EnCana's value creation is founded in its oil and gas
reserves, which are 100 percent evaluated by external, independent reservoir
engineering firms. We implemented this 'best-in-class' practice to help give
shareholders confidence in an oil and gas company's most important asset,"
Morgan said.
The inaugural evaluation of EnCana's total conventional reserve base
(excluding Syncrude) resulted in a year-end 2002 balance of about 2.5 billion
barrels of oil equivalent proved reserves before royalties, estimated using
constant prices and costs. Discoveries, extensions to existing pools and net
acquisitions were approximately 552 million barrels of oil equivalent proved
reserves. Negative net revisions of approximately 79 million barrels of oil
equivalent of conventional proved reserves were recorded.
EnCana's major positive proved reserve additions and revisions before
acquisitions and dispositions occurred in the U.S. Rockies, Oilsands and
Foothills regions and internationally in the U.K. central North Sea. Major
negative proved revisions occurred in the Southern and Central Plains regions
of Alberta following the first fully independent reserves assessment of these
assets. "Despite these revisions, EnCana still delivered strong growth in
conventional proved reserves of 10 percent. That is an outstanding
achievement," Morgan said.

<<
Reserves at year-end 2002 Constant prices, before royalties
-------------------------------------------------------------------------
Proved Proved + Probable
-------------------------------------------------------------------------
Natural gas (billion cubic feet) 8,973 12,431
-------------------------------------------------------------------------
Conventional oil and NGLs
(millions of barrels) 983 1,738
-------------------------------------------------------------------------
Total conventional (millions of BOE) 2,479 3,810
-------------------------------------------------------------------------
Syncrude (millions of barrels) 434 713
-------------------------------------------------------------------------
Total (millions of BOE) 2,913 4,523
-------------------------------------------------------------------------


2002 Conventional reserves
replacement cost Constant prices
-------------------------------------------------------------------------
C$ before royalties Proved Proved + Probable
-------------------------------------------------------------------------
2002 9.60 6.20
-------------------------------------------------------------------------
Recycle ratio 1.9 3.0
-------------------------------------------------------------------------

US$ after royalties
-------------------------------------------------------------------------
2002 8.20 5.10
-------------------------------------------------------------------------

Four engineering companies conducted the inaugural evaluation of 100
percent of EnCana's reserves. McDaniel & Associates Consultants Ltd. and
Gilbert Laustsen Jung Associates Ltd. evaluated EnCana's Western Canada
reserves, while Netherland, Sewell & Associates, Inc. evaluated EnCana's U.S.
onshore reserves. Ryder Scott Company conducted the independent reserve
evaluations for EnCana's offshore and international assets. Also, EnCana has
an independent reserves committee of its board of directors which reviews the
process used in the evaluation of reserves and the qualifications of the
company's independent engineering firms.

EnCana targeting 10 percent per common share internal sales growth in
2003
EnCana's 2003 total daily conventional oil and gas sales volumes are
forecast to grow by an average of 10 percent per common share from 2002 pro
forma rates to between 740,000 and 797,000 barrels of oil equivalent. That
sales forecast is comprised of between 3 billion and 3.1 billion cubic feet of
gas per day and 240,000 and 280,000 conventional barrels of oil and NGLs per
day. These figures exclude any contribution from Syncrude prior to the sale of
EnCana's interests.

Tight supply and cold winter boost natural gas prices as year closes out
For 2002, EnCana's average realized gas price was $4.07 per thousand
cubic feet, down 29 percent from the 2001 average. However, in the fourth
quarter, EnCana's average realized gas price was $5.11 per thousand cubic
feet, up 42 percent over the fourth quarter of 2001, reflecting the tight
supply and cold weather experienced across large consuming regions of North
America. Prices have strengthened further in 2003, and are expected to
continue at strong levels through the year.

Oil prices rose through 2002, Canadian heavy oil differentials narrowed
In 2002, EnCana's realized oil and natural gas liquids price averaged
$30.98 per barrel, up 8 percent from 2001. In the fourth quarter, EnCana's
realized oil and natural gas liquids price was $32.94, up 26 percent over one
year earlier. The average 2002 West Texas Intermediate (WTI) crude oil
benchmark price was US$26.15 per barrel, up slightly from US$25.95 per barrel
in 2001. Global oil prices rose to average US$28.23 WTI per barrel during the
fourth quarter of 2002 principally due to continued speculation over a
possible war in Iraq and the widespread strike in Venezuela. During 2002,
Canadian heavy oil differentials narrowed substantially, averaging US$5.93 per
barrel compared with US$9.87 per barrel in 2001. In Ecuador, the oil quality
differential also narrowed, dropping to average US$4.16 from US$7.02 per
barrel in 2001.

EnCana manages risk with series of natural gas and oil price hedges
EnCana has established a series of risk management strategies on a
portion of its forecast oil and gas sales. In 2003, EnCana has fixed price
arrangements on about 33 percent of its forecast gas sales and about
46 percent of its forecast oil and NGLs sales. A summary of EnCana's current
oil and gas hedges follows.

2003 Price Basis Term Volume Price
-------------------------------------------------------------------------
Natural Gas AECO Fixed Price Calendar 03 757 MMcf/d C$6.10/Mcf
-------------------------------------------------------------------------
AECO less
AECO Basis Swap Calendar 03 156 MMcf/d US$0.50/Mcf
-------------------------------------------------------------------------
NYMEX Fixed Price Calendar 03 259 MMcf/d US$4.20/Mcf
-------------------------------------------------------------------------
U.S. Rockies NYMEX less
Basis Swap Calendar 03 547 MMcf/d US$0.55/Mcf
-------------------------------------------------------------------------
U.S. Rockies US$2.08 -
Collar Calendar 03 50 MMcf/d US$4.52/Mcf
-------------------------------------------------------------------------
US$21.95 -
Oil Costless Collars Calendar 03 40,000 bbls/d US$29.00/bbl
-------------------------------------------------------------------------
Swaps Calendar 03 85,000 bbls/d US$25.28/bbl
-------------------------------------------------------------------------
-------------------------------------------------------------------------

2004-2007 Price Basis Term Volume Price
-------------------------------------------------------------------------
Natural Gas AECO Fixed Price Calendar 04 114 MMcf/d C$6.01/Mcf
-------------------------------------------------------------------------
AECO less
AECO Basis Swap 2004-07 218 MMcf/d US$0.50/Mcf
-------------------------------------------------------------------------
C$5.28-
AECO Collar Calendar 04 62 MMcf/d C$7.49/Mcf
-------------------------------------------------------------------------
NYMEX Fixed Price Calendar 04 50 MMcf/d US$4.41/Mcf
-------------------------------------------------------------------------
U.S. Rockies NYMEX less
Basis Swap 2004-07 344 MMcf/d US$0.45/Mcf
-------------------------------------------------------------------------
U.S. Rockies US$2.08 -
Collar 2004-07 50 MMcf/d US$4.52/Mcf
-------------------------------------------------------------------------
US$20.00 -
Oil Costless Collars Calendar 04 62,500 bbls/d US$25.69/bbl
-------------------------------------------------------------------------
Swaps Calendar 04 62,500 bbls/d US$23.13/bbl
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Important Notice: Readers are cautioned that a portion of the 12 month
results and the comparisons to prior years' 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.

Consolidated EnCana Highlights

Financial Highlights
(as at and for the period EnCana EnCana
ended December 31, 2002) 3 months 12 months
($ millions, except per share amounts) Actuals Pro Forma
-------------------------------------------------------------------------
Revenues, net of royalties
and production taxes 3,392 11,213

Cash Flow 1,472 4,211
Per share - basic 3.08 8.89
Per share - diluted 3.03 8.71

Net earnings 429 1,254
Per share - basic(1) 0.90 2.64
Per share - diluted 0.88 2.59

Capital investment, excluding dispositions 1,506 5,752

Total assets 31,322 31,322
Long-term debt 7,395 7,395
Preferred securities (including
those of subsidiaries) 583 583
Shareholders' equity 13,794 13,794

Debt-to-capitalization ratio 36% 36%
(adjusted for working capital and
including preferred securities as debt)
-------------------------------------------------------------------------
Common shares
Outstanding at December 31, 2002 (millions) 478.9 478.9
Weighted average diluted (millions) 485.2 483.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Impact of including share options in earnings calculations
If EnCana were to record compensation expense for outstanding stock
options, earnings per share - basic would have been $2.47 per share, $0.17 per
share less, for the pro forma year ended December 31, 2002.

-------------------------------------------------------------------------
Operating
Highlights
(for the period Q4 2002 Q4 2001 % 2002 2001 %
ended Dec. 31) Actuals Pro forma Change Pro forma Pro forma Change
-------------------------------------------------------------------------
Sales
Total (BOE/d) 777,215 669,147 +16 722,554 646,025 +12
Guidance
midpoint 712,500

Natural gas
(MMcf/d) 3,037 2,509 +21 2,758 2,376 +16
Guidance
midpoint 2,750

Total liquids
(bbls/d) 271,048 250,980 +8 262,887 250,025 +5
Guidance
midpoint 254,500

Onshore North
America
Conventional
oil and NGLs 179,067 156,739 +14 169,722 156,077 +9
Syncrude 34,261 32,347 +6 31,556 30,687 +3
Offshore &
International 57,720 61,894 -7 61,609 63,261 -3
-------------------------------------------------------------------------
Prices
North American
gas price ($/Mcf) 5.11 3.60 +42 4.07 5.75 -29
-------------------------------------------------------------------------
North American
conventional
oil price ($/bbl)
Light/medium 35.10 26.82 +31 32.40 30.20 +7
Heavy 24.63 18.81 +31 25.34 19.48 +30
Syncrude ($/bbl) 42.29 41.83 +1 40.11 42.02 -5
International
crude oil ($/bbl)
Ecuador 35.38 23.62 +50 31.30 26.24 +19
U.K. 37.99 35.96 +6 36.14 36.21 -
Natural gas liquids
($/bbl) 36.15 22.85 +58 30.44 32.53 -6
-------------------------------------------------------------------------
Total liquids
($/bbl) 32.94 26.14 +26 30.98 28.60 +8
-------------------------------------------------------------------------
-------------------------------------------------------------------------

EnCana corporate developments
EnCana sells interests in two major oil pipelines and agrees to sell
10 percent share of Syncrude
Early in January 2003, EnCana closed the sales of its indirect
100 percent ownership of the Express Pipeline System and its indirect
70 percent interest in the Cold Lake Pipeline System for a total of
approximately $1.6 billion, which included assumed debt of approximately
$599 million. On February 3, EnCana announced an agreement with Canadian Oil
Sands Limited (Canadian Oil Sands) to sell a 10 percent share of the Syncrude
project for approximately $1.07 billion. EnCana has also granted Canadian Oil
Sands an option to purchase EnCana's remaining 3.75 percent share and an
overriding royalty for approximately $417 million. The sale of the 10 percent
share is expected to close on or about February 28, 2003 and Canadian Oil
Sands holds its option until December 31, 2003.

AEC capital securities redeemed
On December 9, 2002, AEC redeemed its 8.38% Capital Securities due
June 27, 2040 and its 8.50% Capital Securities due December 20, 2040, paying
security holders approximately $495 million.

Dividends
The board of directors of EnCana declared a quarterly dividend of
10 cents (C$0.10) per share payable on March 31, 2003 to common shareholders
of record as of March 14, 2003.

Normal Course Issuer Bid approved
Effective October 16, 2002, EnCana received approval from the Toronto
Stock Exchange for a Normal Course Issuer Bid. Under the bid, EnCana may
purchase for cancellation up to 23,843,565 of its Common Shares, representing
5 percent of the 476,871,300 Common Shares outstanding as at October 4, 2002.
On October 22, 2002, the company became entitled to make purchases under the
bid for a period of up to one year. To date, EnCana has made no purchases
under the bid.

Financial strength
EnCana maintains the strongest financial position in its upstream
independent peer group. At December 31, 2002, the company's debt-to-
capitalization ratio was 36:64 (all preferred securities included as debt).
2002 core capital investment was $4,525 million. Asset acquisitions were
$1,227 million and proceeds from asset and corporate dispositions were
$695 million, resulting in net capital investment of $5,057 million.
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-. On
October 2, 2002, EnCana issued C$300 million in medium term notes that bear an
annual interest rate of 5.30 percent. The company also consolidated its
borrowing capacity into a $4 billion credit facility with a syndicate of major
banks and lending institutions.

EnCana operational highlights

Onshore North America

Fourth quarter gas and conventional liquids production up 14 percent,
reflecting solid growth in 2002
EnCana's North American gas and conventional liquids production continued
to grow at a strong pace in 2002, topped off by a 14 percent year-over-year
increase in the fourth quarter to average 659,100 barrels of oil equivalent
per day on a pro forma basis. Gas production averaged 2.88 billion cubic feet
per day, and conventional liquids averaged approximately 179,100 barrels per
day. Quarterly gas production growth was led by increases in the U.S. Rockies
and northeast British Columbia, where declining Ladyfern production was more
than offset by increases in the region. Conventional liquids production
increases came from the ramping up of the company's SAGD projects at Foster
Creek and Christina Lake, new NGLs production at Ferrier and increased
production at Suffield. For the full year 2002, gas production averaged
2.72 billion cubic feet per day, up 12 percent from 2.43 billion cubic feet
per day in 2001. Conventional liquids production rose 9 percent to average
about 169,700 barrels per day in 2002. Onshore North America drilled 889 net
wells during the fourth quarter, for a total of 2,964 in 2002.

U.S. Rockies gas growth up significantly for second year in a row
U.S. Rockies fourth quarter gas production almost doubled, rising to
654 million from 331 million cubic feet per day on a pro forma basis from the
fourth quarter of 2001. On an annualized daily basis, EnCana's pro forma gas
production from this high growth region has grown from 93 million cubic feet
in 2000, to 279 million cubic feet in 2001 to 500 million cubic feet in 2002.
"We have built a high growth gas producing region in a very short period
of time. Following opportunistic acquisitions, including two complementary
additions in 2002, we have applied highly successful drilling and completion
techniques to assemble a leading growth engine for EnCana," said Randy
Eresman, EnCana's Chief Operating Officer.

Greater Sierra growing with success
EnCana has more than 30 rigs running in the Greater Sierra area this
winter - expanding production from another of the company's high growth gas
regions. With a 2 million-net-acre land base and a five year inventory of more
than 600 well locations, EnCana's Foothills team is developing this large
northeast British Columbia resource play in an assembly line fashion. In 2002,
Greater Sierra production averaged 145 million cubic feet per day.
"We continue to drive down costs and enhance economic returns at Greater
Sierra, which is typical of EnCana's experience with other resource plays. In
the past three years, drilling times have decreased from 25 to 15 days per
well, contributing to drilling cost reductions of about 25 percent, which has
made this a highly profitable growth area," Eresman said.

Ladyfern declines offset by gas growth in Foothills region
Production at Ladyfern in 2002 averaged about 104 million cubic feet per
day, closing the year with daily production of about 61 million cubic feet
during December. Despite the decline at Ladyfern, production from EnCana's
Foothills region increased by about 8 percent in 2002 due to increases at
Greater Sierra and Grande Prairie.

EnCana preparing to expand Canada's first commercial coalbed methane
production
Canada's first demonstration-scale commercial coalbed methane (CBM)
project is producing comparatively small but promising volumes from the
company's fee simple lands east of Calgary. Recently, the company decided to
pursue an independent CBM strategy, ending its joint venture arrangement with
MGV Energy. EnCana's CBM potential is considerable, with about 4 million acres
of 100 percent owned contiguous fee simple lands in southern Alberta that have
extensive shallow gas production infrastructure in place.

Canada's leading SAGD project grows production
EnCana's oilsands strategy is focused on developing the huge resource
potential of its conventional production oilsands holdings through the
application of steam-assisted gravity drainage (SAGD), primarily at Foster
Creek and Christina Lake. Oil production from EnCana's Foster Creek SAGD
project in northeast Alberta reached design capacity of about 20,000 barrels
of daily production during the fourth quarter. Construction of a cogeneration
plant, which is anticipated to lower Foster Creek's steam costs while
generating electricity for the SAGD facility and the Alberta grid, is nearing
completion. It is expected that the additional steam should allow for a low
cost expansion at Foster Creek to take production volumes to an anticipated
30,000 barrels per day in 2004. The Christina Lake pilot project is currently
producing about 3,300 barrels per day.
"The world's first large-scale commercial SAGD project at Foster Creek
encountered a series of challenges through its start up phase in 2002. We have
resolved these and are targeting to build new efficiencies into future stages
of this innovative oilsands development. With an estimated 30 billion barrels
of oilsands resource located on EnCana lands, we are adopting a staged,
orderly development of this tremendous resource to targeted volumes of more
than 100,000 barrels per day. Our oilsands growth is designed to be brought on
stream in incremental steps to match the staged establishment of downstream
marketing arrangements in consuming regions," said Eresman.

Redefining EnCana's oilsands strategy - agreement reached to sell
10 percent of Syncrude
"Our plans to sell our Syncrude interest are driven by our focus on
investing in premium growth, high return conventional oil and gas assets where
we operate, own a high working interest and are able to apply our core
competencies to control the pace of development and achieve industry leading
cost performance. Our investment in Syncrude did not match this strategy,"
said Eresman. "EnCana will continue to actively manage its asset base and
identify non-core assets that do not meet our operating strategies."
EnCana's share of Syncrude production during the fourth quarter of 2002
averaged 34,261 barrels per day, up 6 percent from the same period in 2001. In
2002, Syncrude produced 31,556 barrels per day for EnCana, up 3 percent from
one year earlier. Operating costs for 2002 averaged $18.53 per barrel.

Offshore & International

Ecuador - complementary acquisition nearly doubles undeveloped land
position
In January 2003, EnCana acquired three largely undeveloped blocks from
Vintage Petroleum, Inc. for about US$137.4 million (C$210 million), which
includes about US$25.7 million of working capital and is subject to normal
post closing adjustments. The acquisition adds about 4,600 barrels per day of
oil production and about 603,000 net acres adjacent to EnCana's non-operated
Block 15. This complementary acquisition, which closed January 31, 2003 and
includes 100 percent of the Shiripuno Block, 75 percent of Block 14 and
70 percent of Block 17, enhances EnCana's opportunity to increase production
and meet its targeted transportation commitments on the OCP Pipeline earlier
than anticipated.
"This acquisition increases our net land position in Ecuador's under-
explored and oil-prone Oriente Basin by about 80 percent. The acquired blocks
are in the very early stages of development - the kind of assets where we
believe we can efficiently grow production by leveraging off our current
operations," Eresman said.
Fourth quarter oil sales in Ecuador, which are limited by pipeline
capacity, averaged 49,934 barrels per day, down 2 percent from the fourth
quarter one year earlier. The OCP Pipeline project is about 85 percent
complete and on schedule to transport its initial oil volumes in mid 2003.

U.K. North Sea - Buzzard moving through regulatory process
EnCana is preparing to file a comprehensive Environmental Statement with
the U.K. Department of Trade and Industry on its Buzzard oil development
project in the central North Sea. The Buzzard field, located about
100 kilometres northeast of Aberdeen, Scotland, contains an estimated
180 million barrels of recoverable light oil net to EnCana. Drilling of
production wells is planned to commence in mid 2005 and first oil is expected
to start flowing in 2006. Net production to EnCana is expected to be about
75,000 barrels per day when the project reaches plateau volumes in 2007.
EnCana owns 45 and 35 percent of the two blocks where Buzzard is located.

East Coast of Canada - Deep Panuke
EnCana is undertaking a comprehensive review of its Deep Panuke natural
gas project with an aim to strengthen anticipated project economics. To
accomplish the review, EnCana has requested an adjournment of the regulatory
approval process from the Canada-Nova Scotia Offshore Petroleum Board and the
National Energy Board. EnCana expects to be able to update the regulators as
to the progress on enhancements to the Deep Panuke project by the end of 2003.

Gulf of Mexico - Tahiti appraisal ongoing
EnCana and its partners are currently drilling two appraisal wells on the
Tahiti oil discovery, which is operated by ChevronTexaco and contains an
estimated 100 million to 125 million barrels of recoverable oil net to EnCana.
The company holds a 25 percent interest in Tahiti, located in the deep water
Green Canyon Block 640. The appraisal program is expected to be completed in
the second quarter of 2003.

Midstream & Marketing

EnCana's Midstream & Marketing division achieved operating cash flow from
continuing operations of about $230 million on a pro forma basis in 2002.

Two major oil pipelines sold for $1.6 billion
Early in 2003, EnCana completed the sale of its indirect 100 percent
interest in the Express Pipeline System and its indirect 70 percent interest
in the Cold Lake Pipeline System. Inter Pipeline Fund purchased EnCana's
interest in Cold Lake for approximately $425 million. A consortium including
BC Gas Inc., Borealis Infrastructure Management Inc., and Ontario Teachers'
Pension Plan purchased the interest in the Express Pipeline System for
approximately $1.175 billion, which included assumed debt of approximately
$599 million.

EnCana to open first phase of Countess gas storage
EnCana is on track to open the first phase of its new Countess gas
storage facility, located about 85 kilometres east of Calgary, with an
anticipated capacity of 10 billion cubic feet. The drilling of injection and
withdrawal wells has been helped by a mild winter and the initial injections
are expected to start in the second quarter of this year. The Countess project
is expected to continue expanding to a total of 40 billion cubic feet of
storage capacity by April 2005. In northern California, construction is
progressing on a doubling of EnCana's Wild Goose storage facility to an
estimated 29 billion cubic feet of capacity.
"Our Alberta and California expansions, slated for completion in 2005,
are expected to increase EnCana's continental storage capacity to about
200 billion cubic feet, and total peak withdrawal capacity to approximately
4 billion cubic feet per day. These will serve to strengthen EnCana's ranking
as North America's largest independent owner and operator of gas storage,"
said Bill Oliver, President of EnCana's Midstream & Marketing division.

EnCana first Canadian producer to publish crude oil prices
EnCana is stepping up its North America crude oil marketing effort as the
first Canadian producer to publish its crude oil prices. Historically in
Canada, only refineries have posted prices that they will pay for various
grades of crude. Canadian crudes have traditionally traded at a discount to
competitive international and U.S. domestic streams entering the U.S. Midwest
from the Gulf Coast. This discount is primarily due to Canada having just one
export sales option, the United States. As a seller, EnCana expects to
generate more market responsive prices from the buying refineries, thereby
reducing the discount for Canadian barrels and achieving closer pricing parity
to refiner's crude alternatives. With daily marketing of close to 320,000
barrels of Western Canadian crude oil, EnCana believes it has an obligation to
use its marketing strength to achieve the best possible prices. The posting of
prices for EnCana's crudes is one further step to extracting added value from
the company's higher level of production. EnCana's oil price is posted on its
Web site at www.encana.com/crudeoilpricing.

IMPORTANT NOTICE

NOTE: This press release includes EnCana's financial statements as well
as pro forma financial statements which better reflect the way EnCana views
its business:
1) EnCana's actual financial statements, which reflect results as
illustrated in the table below.

EnCana actual financial statements
-------------------------------------------------------------------------
Q4 2002 Q4 2001 12 months 2002 12 months 2001
-------------------------------------------------------------------------
EnCana PCE alone EnCana PCE alone
(PCE & AEC) (PCE & AEC)
for Q2, Q3
& Q4, plus
PCE alone Q1
-------------------------------------------------------------------------

2) EnCana's pro forma 2002 financial statements, which reflect results as
if the merger of PanCanadian Energy Corporation ("PCE") and Alberta
Energy Company Ltd. ("AEC") had occurred at the beginning of 2002.


This press release and EnCana's supplemental information are posted on
the company Web site www.encana.com.


CONFERENCE CALL TODAY

EnCana Corporation will host a conference call today, Thursday,
February 20, 2003 starting at 9:30 a.m., Mountain Time (11:30 a.m. Eastern
Time) to discuss EnCana's fourth quarter and year-end pro forma 2002 financial
and operating results.
To participate, please dial 416-640-1907 approximately 10 minutes prior
to the conference call. An archived recording of the call will be available
from approximately midnight on February 20, 2003 until February 27, 2003 by
dialing 416-640-1917 and entering pass code 234688 followed by the pound key.
A live audio Web cast of the conference call will also be available
either via EnCana's Web site, www.encana.com, under Investor Relations or via
Canada NewsWire at the following address:
http://webevents.broadcast.com/cnw/encana20030220. 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. In the U.S.,
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: EnCana is the
largest private sector oil producer in Ecuador and is the operator of a very
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 best-in-class 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 future plans and operations, certain statements
contained in this news release are forward-looking statements within the
meaning of the "safe harbour" provisions of the United States Private
Securities Litigation Reform Act of 1995. Forward-looking statements in this
news release include, but are not limited to, EnCana's internal projections,
expectations or beliefs concerning future operating results, and various
components thereof; future economic performance; the production and growth
potential of its various assets, including assets in the U.S. Rockies, Greater
Sierra, offshore Canada's East Coast, the U.K. central North Sea and Ecuador;
the anticipated oil and natural gas prices for the remainder of 2003; the
ability to achieve production and sales growth targets for 2003 and beyond
(including per share sales growth); the sources and deployment of expected
capital in 2003; the projected annual post-merger synergies in 2003; the
anticipated completion in 2005 of the Countess and Wild Goose gas storage
projects; the timing of updates to regulators regarding progress on
enhancements to the Deep Panuke project; projected gas storage capacity in
2005; the success of future drilling prospects; potential exploration; the
potential success of certain projects such as SAGD (including in 2003 and
2004), Buzzard, coalbed methane, the OCP Pipeline and Syncrude and the
expected rates of returns from such projects; the potential capacity of the
OCP Pipeline; the ability and timing of meeting EnCana's targeted
transportation commitments on the OCP Pipeline; the potential closing date for
the sale of EnCana's interest in Syncrude; the proposed dates of drilling and
production in the U.K. central North Sea; and the potential success of other
exploratory wells in the Gulf of Mexico, offshore Canada's East Coast and the
U.K. central North Sea.
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; imprecision of reserve
estimates; 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 risk that the anticipated synergies to be realized by
the merger of AEC and PanCanadian will not be realized; costs relating to the
merger of AEC and PanCanadian 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 and its indirect wholly-owned
subsidiary, AEC. Although EnCana believes that the expectations represented by
such forward-looking statements are reasonable, there can be no assurance that
such expectations will prove to be correct. Readers are cautioned that the
foregoing list of important factors is not exhaustive. Furthermore, the
forward-looking statements contained in this news release are made as of the
date of this news release, and EnCana does not undertake any obligation to
update publicly or to revise any of the included forward-looking statements,
whether as a result of new information, future events or otherwise. The
forward-looking statements contained in this news release are expressly
qualified by this cautionary statement.

Further information on EnCana Corporation and Alberta Energy Company Ltd.
is available on the company's Web site, www.encana.com.

Interim Report
For the period ended December 31, 2002

EnCana Corporation


Consolidated Statement of Earnings

December 31
-----------------------------------
Three Months
Ended Year Ended
-----------------------------------
(unaudited) ($ millions,
except per share amounts) 2002 2001 2002 2001
-----------------------------------------------------------------------
Revenues, Net of
Royalties and
Production Taxes (Note 4) $ 3,392 $ 944 $10,011 $ 4,894
-----------------------------------------------------------------------
Expenses (Note 4)
Transportation and selling 191 47 574 172
Operating 457 163 1,438 693
Purchased product 1,131 283 3,448 1,144
Administrative 76 6 187 83
Interest, net 177 24 419 45
Foreign exchange loss
(gain) (Note 8) 4 6 (20) 20
Depreciation, depletion and
amortization 743 261 2,153 852
Gain on corporate disposition (51) - (51) -
-----------------------------------------------------------------------
2,728 790 8,148 3,009
-----------------------------------------------------------------------
Net Earnings Before the
Undernoted 664 154 1,863 1,885
Income tax expense (Note 6) 239 65 618 631
Distributions on Subsidiary
Preferred Securities, net of
tax 9 - 20 -
-----------------------------------------------------------------------
Net Earnings from Continuing
Operations 416 89 1,225 1,254
Net Earnings (Loss)
from Discontinued
Operations (Note 5) 13 1 (1) 33
-----------------------------------------------------------------------
Net Earnings $ 429 $ 90 $ 1,224 $ 1,287
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Net Earnings from
Continuing Operations
per Common Share (Note 10)
Basic $ 0.87 $ 0.35 $ 2.92 $ 4.89
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Diluted $ 0.86 $ 0.33 $ 2.87 $ 4.77
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Net Earnings per Common
Share (Note 10)
Basic $ 0.90 $ 0.35 $ 2.92 $ 5.02
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Diluted $ 0.88 $ 0.34 $ 2.87 $ 4.90
-----------------------------------------------------------------------
-----------------------------------------------------------------------


Consolidated Statement of Retained Earnings

Year Ended December 31
-----------------------
(unaudited) ($ millions) 2002 2001
-----------------------------------------------------------------------

Retained Earnings, Beginning of Year
As previously reported $ 3,689 $ 3,721
Retroactive adjustment for change in
accounting policy (Note 2) (59) (42)
-----------------------------------------------------------------------
As restated 3,630 3,679
Net Earnings 1,224 1,287
Dividends on Common Shares and Other
Distributions, net of tax (170) (1,286)
Other Adjustments - (50)
-----------------------------------------------------------------------
Retained Earnings, End of Year $ 4,684 $ 3,630
-----------------------------------------------------------------------
-----------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.


Consolidated Balance Sheet


As at December 31,
(unaudited) ($ millions) 2002 2001
-----------------------------------------------------------------------
Assets
Current Assets
Cash and cash equivalents $ 212 $ 963
Accounts receivable and accrued revenue 2,052 623
Inventories 543 87
Assets of discontinued operations (Note 5) 1,482 -
-----------------------------------------------------------------------
4,289 1,673
Capital Assets, net (Note 4) 23,770 8,162
Investments and Other Assets 377 237
Assets of Discontinued Operations (Note 5) - 728
Goodwill (Note 3) 2,886 -
-----------------------------------------------------------------------
(Note 4) $31,322 $10,800
-----------------------------------------------------------------------

Liabilities and Shareholders' Equity
Current Liabilities
Accounts payable and accrued liabilities $ 2,390 $ 824
Income tax payable 14 656
Liabilities of discontinued operations (Note 5) 825 -
Short-term debt (Note 7) 438 -
Current portion of long-term debt (Note 8) 212 160
-----------------------------------------------------------------------
3,879 1,640
Long-Term Debt (Note 8) 7,395 2,210
Deferred Credits and Other Liabilities 585 325
Future Income Taxes 5,212 2,060
Liabilities of Discontinued Operations (Note 5) - 586
Preferred Securities of Subsidiary 457 -
-----------------------------------------------------------------------
17,528 6,821
-----------------------------------------------------------------------
Shareholders' Equity
Preferred securities 126 126
Share capital (Note 9) 8,732 196
Share options, net (Note 3) 133 -
Paid in surplus 61 27
Retained earnings 4,684 3,630
Foreign currency translation adjustment (Note 2) 58 -
-----------------------------------------------------------------------
13,794 3,979
-----------------------------------------------------------------------
$31,322 $10,800
-----------------------------------------------------------------------
-----------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.


Consolidated Statement of Cash Flows

December 31
-----------------------------------
Three Months
Ended Year Ended
-----------------------------------
(unaudited) ($ millions,
except per share amounts) 2002 2001 2002 2001
-----------------------------------------------------------------------
Operating Activities
Net earnings from continuing
operations $ 416 $ 89 $ 1,225 $ 1,254
Depreciation, depletion and
amortization 743 261 2,153 852
Future income taxes (Note 6) 396 23 667 134
Other (106) 11 (266) 19
-----------------------------------------------------------------------
Cash flow from continuing
operations 1,449 384 3,779 2,259
Cash flow from discontinued
operations 23 2 42 47
-----------------------------------------------------------------------
Cash flow 1,472 386 3,821 2,306
Net change in non-cash working
capital from continuing
operations (524) 25 (1,347) 515
Net change in non-cash working
capital from discontinued
operations 18 23 97 (47)
-----------------------------------------------------------------------
966 434 2,571 2,774
-----------------------------------------------------------------------

Investing Activities
Business combination
with Alberta Energy
Company Ltd. (Note 3) - - (128) -
Capital expenditures (Note 4) (1,506) (661) (4,940) (1,955)
Proceeds on disposal of
capital assets 190 4 566 47
Corporate (acquisitions) and
dispositions 93 - 93 84
Net change in investments and
other 51 31 64 30
Net change in non-cash working
capital from continuing
operations 460 118 293 88
Discontinued operations (1) (1) (10) 9
-----------------------------------------------------------------------
(713) (509) (4,062) (1,697)
-----------------------------------------------------------------------

Financing Activities
Issuance of short-term debt 438 - 438 440
Repayment of short-term debt - (440) - (690)
Issuance of long-term debt 892 1,322 2,354 1,566
Repayment of long-term debt (1,729) (150) (1,886) (399)
Issuance of common shares 43 7 139 48
Repurchase of common shares - (7) - (7)
Dividends on common shares (47) (26) (167) (1,282)
Payments to preferred
securities holders - (1) (31) (7)
Net change in non-cash working
capital from continuing
operations (7) 3 (5) 1
Discontinued operations (4) - (13) -
Other (57) - (82) -
-----------------------------------------------------------------------
(471) 708 747 (330)
-----------------------------------------------------------------------

Deduct: Foreign Exchange (Gain) Loss
on Cash and Cash Equivalents held
in Foreign Currency - (4) 7 (19)
-----------------------------------------------------------------------

(Decrease) Increase in Cash
and Cash Equivalents (218) 637 (751) 766
Cash and Cash Equivalents,
Beginning of Period 430 326 963 197
-----------------------------------------------------------------------
Cash and Cash Equivalents, End
of Period $ 212 $ 963 $ 212 $ 963
-----------------------------------------------------------------------
-----------------------------------------------------------------------

Cash Flow per Common
Share (Note 10)
Basic $ 3.08 $ 1.51 $ 9.15 $ 9.02
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Diluted $ 3.03 $ 1.47 $ 8.99 $ 8.81
-----------------------------------------------------------------------
-----------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.


Notes to Consolidated Financial Statements (unaudited)

1. BASIS OF PRESENTATION

The interim Consolidated Financial Statements include the accounts of
EnCana Corporation, formerly PanCanadian Energy Corporation ("PanCanadian"),
and its subsidiaries (the "Company"), including Alberta Energy Company Ltd.
(see Note 3), 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 and crude oil, as well as pipelines,
natural gas liquids processing and gas storage 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, 2001, except as described in Note 2. 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, 2001.

2. CHANGES IN ACCOUNTING POLICIES AND PRACTICES

Foreign Currency Translation

At January 1, 2002, the Company retroactively adopted amendments to the
Canadian accounting standard for foreign currency translation. As a result of
the amendments, all exchange gains and losses on long-term monetary items that
do not qualify for hedge accounting are recorded in earnings as they arise.
Specifically, the Company is now required to translate long-term debt
denominated in U.S. dollars into Canadian dollars at the period end exchange
rate with any resulting adjustment recorded in the Consolidated Statement of
Earnings or as a foreign currency translation adjustment in the Consolidated
Balance Sheet for self-sustaining entities. Previously, these exchange gains
and losses were deferred and amortized over the remaining life of the monetary
item.
As required by the standard, all prior periods have been restated for the
change in accounting policy. The change results in an increase in net earnings
of $12 million for the three months ended December 31, 2002 (2001 - $1 million
decrease) and an increase in net earnings of $28 million for the year ended
December 31, 2002 (2001 - $17 million decrease). The effect of this change on
the December 31, 2001 Consolidated Balance Sheet is an increase in long-term
debt and a reduction in deferred credits and other liabilities of $92 million,
as well as a reduction in investments and other assets and retained earnings
of $59 million.
In conjunction with the business combination described in Note 3, the
Company reviewed its accounting practices for operations outside of Canada and
determined that such operations are self-sustaining. The accounts of self-
sustaining foreign subsidiaries are translated using the current rate method,
whereby assets and liabilities are translated at period-end exchange rates,
while revenues and expenses are translated using average rates for the period.
Translation gains and losses relating to the subsidiaries are deferred and
included as a separate component of shareholders' equity. Previously,
operations outside of Canada were considered to be integrated and translated
using the temporal method. Under the temporal method, monetary assets and
liabilities were translated at the period-end exchange rate, other assets and
liabilities at the historical rates and revenues and expenses at the average
monthly rates except depreciation, depletion and amortization, which were
translated on the same basis as the related assets.
This change in practice was adopted prospectively beginning April 5,
2002, and results in an increase in net earnings of $9 million for the three
months ended December 31, 2002 and an increase of $2 million for the year
ended December 31, 2002.

3. BUSINESS COMBINATION WITH ALBERTA ENERGY COMPANY LTD.

On January 27, 2002, PanCanadian and Alberta Energy Company Ltd. ("AEC")
announced plans to combine their companies. The transaction was accomplished
through a plan of arrangement (the "Arrangement") under the Business
Corporations Act (Alberta). The Arrangement included a common share exchange,
pursuant to which holders of common shares of AEC received 1.472 common shares
of PanCanadian for each common share of AEC that they held. After obtaining
approvals of the common shareholders and optionholders of AEC and the common
shareholders of PanCanadian, the Court of Queen's Bench of Alberta and
appropriate regulatory and other authorities, the transaction closed April 5,
2002, and PanCanadian changed its name to EnCana Corporation ("EnCana").

This business combination has been accounted for using the purchase
method with the results of operations of AEC included in the Consolidated
Financial Statements from the date of acquisition. The Arrangement resulted in
PanCanadian issuing 218.5 million common shares and a transaction value of
$8,714 million. The calculation of the purchase price and the allocation to
assets and liabilities acquired as of April 5, 2002 is shown below. Further
information related to AEC can be obtained from the audited Consolidated
Financial Statements included in the Joint Information Circular concerning the
merger of AEC and PanCanadian.

($ millions)
------------------------------------------------------------------------
Calculation of Purchase Price:
Common Shares issued to AEC shareholders (millions) 218.5
Price of Common Shares ($ per common share) 38.43
----------------------------------------------------------------------
Value of Common Shares issued $ 8,397
Fair value of AEC share options exchanged
for share options of EnCana Corporation
("Share options") 167
Transaction costs 150
----------------------------------------------------------------------
Total purchase price 8,714
Plus: Fair value of liabilities assumed
Current liabilities 1,781
Long-term debt, including Capital Securities 4,843
Project financing debt 604
Preferred securities 458
Other non-current liabilities 193
Future income taxes 2,647
------------------------------------------------------------------------
Total Purchase Price and Liabilities Assumed $19,240
------------------------------------------------------------------------
------------------------------------------------------------------------

($ millions)
------------------------------------------------------------------------
Fair Value of Assets Acquired:
Current assets $ 1,505
Capital assets 14,053
Other non-current assets 605
Goodwill 3,077
------------------------------------------------------------------------
Total Fair Value of Assets Acquired $19,240
------------------------------------------------------------------------
------------------------------------------------------------------------

($ millions)
------------------------------------------------------------------------
Goodwill Allocation:
Onshore North America $ 2,808
Midstream & Marketing 78
------------------------------------------------------------------------
2,886
Discontinued Operations 191
------------------------------------------------------------------------
Total Goodwill Allocation $ 3,077
------------------------------------------------------------------------
------------------------------------------------------------------------

4. SEGMENTED INFORMATION

Due to the business combination described in Note 3, the Company has
redefined its operations into the following segments.
- Onshore North America includes the Company's North America onshore
exploration for, and production of, natural gas, natural gas liquids and crude
oil.
- Offshore & International combines the following two divisions:
- the Offshore & International Operations Division develops the
reserves associated with offshore and international discoveries.
The Division currently has production in Ecuador and the U.K. central
North Sea and major developments in the East Coast of Canada, the
Gulf of Mexico and the U.K. central North Sea.
- the Offshore & New Ventures Exploration Division includes the
Company's exploration activity in the Canadian East Coast, the North
American frontier region, the Gulf of Mexico, the U.K. central North
Sea, the Middle East, Africa, Australia and Latin America.

- 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.
All prior periods have been restated to conform to these definitions.
Operations that have been discontinued are disclosed in Note 5.

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

Onshore North Offshore &
America International
---------------------------------------
($ millions) 2002 2001 2002 2001
--------------------------------------------------------------------
Revenues
Gross revenue $ 2,203 $ 663 $ 207 $ 41
Royalties and production
taxes 324 59 57 -
--------------------------------------------------------------------
Revenues, net of
royalties and production
taxes 1,879 604 150 41

Expenses
Transportation and selling 144 38 14 5
Operating 296 110 43 6
Purchased product - - - -
Depreciation, depletion
and amortization 589 197 118 44
--------------------------------------------------------------------
Segment Income $ 850 $ 259 $ (25) $ (14)
--------------------------------------------------------------------
--------------------------------------------------------------------

Midstream
& Marketing
-------------------
($ millions) 2002 2001
--------------------------------------------------------------------
Revenues
Gross revenue $ 1,352 $ 325
Royalties and production taxes - -
--------------------------------------------------------------------
Revenues, net of royalties and production taxes 1,352 325

Expenses
Transportation and selling 33 4
Operating 118 47
Purchased product 1,131 283
Depreciation, depletion and amortization 17 10
--------------------------------------------------------------------
Segment Income $ 53 $ (19)
--------------------------------------------------------------------
--------------------------------------------------------------------


Corporate Consolidated
---------------------------------------
2002 2001 2002 2001
--------------------------------------------------------------------
Revenues
Gross revenue $ 11 $ (26) $ 3,773 $ 1,003
Royalties and production
taxes - - 381 59
--------------------------------------------------------------------
Revenues, net of
royalties and production
taxes 11 (26) 3,392 944

Expenses
Transportation and selling - - 191 47
Operating - - 457 163
Purchased product - - 1,131 283
Depreciation, depletion
and amortization 19 10 743 261
Gain on corporate
disposition (51) - (51) -
--------------------------------------------------------------------
Segment Income 43 (36) 921 190
--------------------------------------------------------------------
--------------------------------------------------------------------
Administrative 76 6 76 6
Interest, net 177 24 177 24
Foreign exchange loss 4 6 4 6
--------------------------------------------------------------------
257 36 257 36
--------------------------------------------------------------------
Net Earnings Before
Income Tax (214) (72) 664 154
Income tax expense 239 65 239 65
Distributions on
Subsidiary Preferred
Securities, net of tax 9 - 9 -
--------------------------------------------------------------------
Net Earnings from
Continuing Operations $ (462) $ (137) $ 416 $ 89
--------------------------------------------------------------------
--------------------------------------------------------------------

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


Onshore North America Produced Gas and NGLs
---------------------------------------
Canada U.S. Rockies
---------------------------------------
2002 2001 2002 2001
--------------------------------------------------------------------
Revenues
Gross revenue $ 1,252 $ 444 $ 395 $ 24
Royalties and production
taxes 176 25 92 7
--------------------------------------------------------------------
Revenues, net of
royalties and production
taxes 1,076 419 303 17

Expenses
Transportation and selling 89 33 34 -
Operating 133 49 21 5
--------------------------------------------------------------------
Operating Cash Flow $ 854 $ 337 $ 248 $ 12
--------------------------------------------------------------------
--------------------------------------------------------------------

Conventional
Crude Oil Syncrude
---------------------------------------
2002 2001 2002 2001
---------------------------------------
Revenues
Gross revenue $ 421 $ 195 $ 135 $ -
Royalties and production
taxes 55 27 1 -
--------------------------------------------------------------------
Revenues, net of
royalties and production
taxes 366 168 134 -
Expenses
Transportation and selling 20 5 1 -
Operating 90 56 52 -
--------------------------------------------------------------------
Operating Cash Flow $ 256 $ 107 $ 81 $ -
--------------------------------------------------------------------
--------------------------------------------------------------------


Total Onshore
North America
-------------------
2002 2001
-------------------
Revenues
Gross revenue $ 2,203 $ 663
Royalties and production taxes 324 59
--------------------------------------------------------------------
Revenues, net of royalties and production taxes 1,879 604

Expenses
Transportation and selling 144 38
Operating 296 110
--------------------------------------------------------------------
Operating Cash Flow $ 1,439 $ 456
--------------------------------------------------------------------
--------------------------------------------------------------------


Offshore & International
Ecuador U.K. North Sea
---------------------------------------
2002 2001 2002 2001
--------------------------------------------------------------------
Revenues
Gross revenue $ 173 $ - $ 34 $ 41
Royalties and production
taxes 57 - - -
--------------------------------------------------------------------
Revenues, net of
royalties and production
taxes 116 - 34 41

Expenses
Transportation and selling 10 - 4 5
Operating 28 - 7 6
--------------------------------------------------------------------
Operating Cash Flow $ 78 $ - $ 23 $ 30
--------------------------------------------------------------------
--------------------------------------------------------------------


Total Offshore
Other & International
---------------------------------------
2002 2001 2002 2001
--------------------------------------------------------------------
Revenues
Gross revenue $ - $ - $ 207 $ 41
Royalties and production
taxes - - 57 -
--------------------------------------------------------------------
Revenues, net of
royalties and production
taxes - - 150 41

Expenses
Transportation and selling - - 14 5
Operating 8 - 43 6
--------------------------------------------------------------------
Operating Cash Flow $ (8) $ - $ 93 $ 30
--------------------------------------------------------------------
--------------------------------------------------------------------


Midstream & Marketing
Midstream Marketing
---------------------------------------
2002 2001 2002 2001
--------------------------------------------------------------------
Revenues
Gross revenue $ 328 $ 39 $ 1,024 $ 286

Expenses
Transportation and selling - - 33 4
Operating 110 40 8 7
Purchased product 142 - 989 283
--------------------------------------------------------------------
Operating Cash Flow $ 76 $ (1) $ (6) $ (8)
--------------------------------------------------------------------
--------------------------------------------------------------------

Total Midstream
& Marketing
-------------------
2002 2001
--------------------------------------------------------------------
Revenues
Gross revenue $ 1,352 $ 325

Expenses
Transportation and selling 33 4
Operating 118 47
Purchased product 1,131 283
--------------------------------------------------------------------
Operating Cash Flow $ 70 $ (9)
--------------------------------------------------------------------
--------------------------------------------------------------------


Results of Operations
(For the years ended December 31)
Onshore Offshore &
North America International
---------------------------------------
($ millions) 2002 2001 2002 2001
--------------------------------------------------------------------
Revenues
Gross revenue $ 6,152 $ 3,569 $ 701 $ 171
Royalties and production
taxes 809 303 180 -
--------------------------------------------------------------------
Revenues, net of
royalties and production
taxes 5,343 3,266 521 171

Expenses
Transportation and selling 385 137 53 19
Operating 952 429 135 17
Purchased product - - - -
Depreciation, depletion
and amortization 1,776 703 260 96
--------------------------------------------------------------------
Segment Income $ 2,230 $ 1,997 $ 73 $ 39
--------------------------------------------------------------------
--------------------------------------------------------------------

Midstream
& Marketing
------------------
($ millions) 2002 2001
--------------------------------------------------------------------
Revenues
Gross revenue $ 4,133 $ 1,462
Royalties and production taxes - -
--------------------------------------------------------------------
Revenues, net of royalties and production taxes 4,133 1,462

Expenses
Transportation and selling 136 16
Operating 351 247
Purchased product 3,448 1,144
Depreciation, depletion and amortization 62 20
--------------------------------------------------------------------
Segment Income $ 136 $ 35
--------------------------------------------------------------------
--------------------------------------------------------------------


Corporate Consolidated
---------------------------------------
2002 2001 2002 2001
--------------------------------------------------------------------
Revenues
Gross revenue $ 14 $ (5) $ 11,000 $ 5,197
Royalties and production
taxes - - 989 303
--------------------------------------------------------------------
Revenues, net of
royalties and production
taxes 14 (5) 10,011 4,894

Expenses
Transportation and selling - - 574 172
Operating - - 1,438 693
Purchased product - - 3,448 1,144
Depreciation, depletion
and amortization 55 33 2,153 852
Gain on corporate
disposition (51) - (51) -
--------------------------------------------------------------------
Segment Income 10 (38) 2,449 2,033
--------------------------------------------------------------------
--------------------------------------------------------------------
Administrative 187 83 187 83
Interest, net 419 45 419 45
Foreign exchange (gain)
loss (20) 20 (20) 20
--------------------------------------------------------------------
586 148 586 148
--------------------------------------------------------------------
Net Earnings Before
Income Tax (576) (186) 1,863 1,885
Income tax expense 618 631 618 631
Distributions on
Subsidiary Preferred
Securities, net of tax 20 - 20 -
--------------------------------------------------------------------
Net Earnings from
Continuing Operations $ (1,214) $ (817) $ 1,225 $ 1,254
--------------------------------------------------------------------
--------------------------------------------------------------------

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

Produced Gas and NGL's
---------------------------------------
Onshore North America Canada U.S. Rockies
---------------------------------------
2002 2001 2002 2001
--------------------------------------------------------------------
Revenues
Gross revenue $ 3,451 $ 2,544 $ 869 $ 118
Royalties and production
taxes 419 141 196 39
--------------------------------------------------------------------
Revenues, net of
royalties and production
taxes 3,032 2,403 673 79

Expenses
Transportation and selling 235 112 91 -
Operating 407 175 64 17
--------------------------------------------------------------------
Operating Cash Flow $ 2,390 $ 2,116 $ 518 $ 62
--------------------------------------------------------------------
--------------------------------------------------------------------

Conventional
Crude Oil Syncrude
---------------------------------------
2002 2001 2002 2001
--------------------------------------------------------------------
Revenues
Gross revenue $ 1,463 $ 907 $ 369 $ -
Royalties and production
taxes 190 123 4 -
--------------------------------------------------------------------
Revenues, net of
royalties and production
taxes 1,273 784 365 -

Expenses
Transportation and selling 55 25 4 -
Operating 317 237 164 -
--------------------------------------------------------------------
Operating Cash Flow $ 901 $ 522 $ 197 $ -
--------------------------------------------------------------------
--------------------------------------------------------------------

Total Onshore
North America
-------------------
2002 2001
--------------------------------------------------------------------
Revenues
Gross revenue $ 6,152 $ 3,569
Royalties and production taxes 809 303
--------------------------------------------------------------------
Revenues, net of royalties and production taxes 5,343 3,266

Expenses
Transportation and selling 385 137
Operating 952 429
--------------------------------------------------------------------
Operating Cash Flow $ 4,006 $ 2,700
--------------------------------------------------------------------
--------------------------------------------------------------------

Offshore & International
Ecuador U.K. North Sea
---------------------------------------
2002 2001 2002 2001
--------------------------------------------------------------------
Revenues
Gross revenue $ 541 $ - $ 160 $ 171
Royalties and production
taxes 180 - - -
--------------------------------------------------------------------
Revenues, net of
royalties and production
taxes 361 - 160 171

Expenses
Transportation and selling 34 - 19 19
Operating 83 - 18 17
--------------------------------------------------------------------
Operating Cash Flow $ 244 $ - $ 123 $ 135
--------------------------------------------------------------------
--------------------------------------------------------------------

Total Offshore
Other & International
---------------------------------------
2002 2001 2002 2001
--------------------------------------------------------------------
Revenues
Gross revenue $ - $ - $ 701 $ 171
Royalties and production
taxes - - 180 -
--------------------------------------------------------------------
Revenues, net of
royalties and production
taxes - - 521 171

Expenses
Transportation and selling - - 53 19
Operating 34 - 135 17
--------------------------------------------------------------------
Operating Cash Flow $ (34) $ - $ 333 $ 135
--------------------------------------------------------------------
--------------------------------------------------------------------

Midstream & Marketing

Midstream Marketing
---------------------------------------
2002 2001 2002 2001
--------------------------------------------------------------------
Revenues
Gross revenue $ 760 $ 260 $ 3,373 $ 1,202

Expenses
Transportation and selling - - 136 16
Operating 331 228 20 19
Purchased product 265 - 3,183 1,144
--------------------------------------------------------------------
Operating Cash Flow $ 164 $ 32 $ 34 $ 23
--------------------------------------------------------------------
--------------------------------------------------------------------

Total Midstream
& Marketing
-------------------
2002 2001
--------------------------------------------------------------------
Revenues
Gross revenue $ 4,133 $ 1,462

Expenses
Transportation and selling 136 16
Operating 351 247
Purchased product 3,448 1,144
--------------------------------------------------------------------
Operating Cash Flow $ 198 $ 55
--------------------------------------------------------------------
--------------------------------------------------------------------


Capital Expenditures

Three Months Ended Year Ended
December 31 December 31
---------------------------------------
2002 2001 2002 2001
--------------------------------------------------------------------
Onshore North America $ 997 $ 454 $ 3,662 $ 1,356
Offshore & International 423 142 1,126 407
Midstream & Marketing 49 60 87 165
Corporate 37 5 65 27
--------------------------------------------------------------------
Total $ 1,506 $ 661 $ 4,940 $ 1,955
--------------------------------------------------------------------
--------------------------------------------------------------------

Capital and Total Assets
As at December 31,
---------------------------------------
Capital Assets Total Assets
---------------------------------------
2002 2001 2002 2001
--------------------------------------------------------------------
Onshore North America $ 18,994 $ 6,442 $ 22,977 $ 6,970
Offshore & International 3,710 1,154 4,023 1,247
Midstream & Marketing 874 458 2,348 849
Corporate 192 108 492 1,006
Assets of Discontinued
Operations - - 1,482 728
--------------------------------------------------------------------
Total $ 23,770 $ 8,162 $ 31,322 $ 10,800
--------------------------------------------------------------------
--------------------------------------------------------------------

5. DISCONTINUED OPERATIONS

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.
On July 9, 2002, the Company announced that it planned to sell its 70%
equity investment in the Cold Lake Pipeline System and its 100% interest in
the Express Pipeline System. Both crude oil pipeline systems were acquired in
the business combination with Alberta Energy Company Ltd. on April 5, 2002
described in Note 3. Accordingly, these operations have been accounted for as
discontinued operations. The Company, through indirect wholly owned
subsidiaries, is a shipper on the Cold Lake pipeline and the Express system.
The financial results for the year ended December 31, 2002 shown below
includes tariff revenue of $54 million paid by the Company for services on
Express (three months ended - $12 million). On January 2, 2003 and January 9,
2003, the Company announced it had completed the sale of its interest in the
Cold Lake Pipeline System and Express Pipeline System for total proceeds of
approximately $1.6 billion, including assumption of related long-term debt
(see Note 12).
As the wind-down of the merchant energy operation was substantially
complete at December 31, 2002, and the midstream pipelines were sold
subsequent to year end, all discontinued operations at December 31, 2002 have
been classified as current on the Consolidated Balance Sheet.
The following tables present the effect of the discontinued operations on
the Consolidated Financial Statements:

Consolidated Statement of Earnings

For the Three Months Ended December 31
-----------------------------------------
Merchant Energy Midstream - Pipelines
-----------------------------------------
($ millions) 2002 2001 2002 2001
---------------------------------------------------------------------
Revenues $ (9) $ 736 $ 63 $ -
---------------------------------------------------------------------

Expenses
Operating - - 25 -
Purchased product (10) 730 - -
Administrative 1 3 - -
Interest, net - - 8 -
Depreciation, depletion
and amortization (1) 1 4 -
Loss on discontinuance 6 - - -
---------------------------------------------------------------------
(4) 734 37 -
---------------------------------------------------------------------
Net (Loss) Earnings
Before Income Tax (5) 2 26 -
Income tax expense (2) 1 10 -
---------------------------------------------------------------------
Net (Loss) Earnings from
Discontinued Operations $ (3) $ 1 $ 16 $ -
---------------------------------------------------------------------
---------------------------------------------------------------------

Total
-------------------

($ millions) 2002 2001
--------------------------------------------------------------------
Revenues $ 54 $ 736
--------------------------------------------------------------------
Expenses
Operating 25 -
Purchased product (10) 730
Administrative 1 3
Interest, net 8 -
Depreciation, depletion and amortization 3 1
Loss on discontinuance 6 -
--------------------------------------------------------------------
33 734
--------------------------------------------------------------------
Net (Loss) Earnings Before Income Tax 21 2
Income tax expense 8 1
--------------------------------------------------------------------
Net (Loss) Earnings from Discontinued Operations $ 13 $ 1
--------------------------------------------------------------------
--------------------------------------------------------------------


For the Years Ended December 31
-------------------------------
Merchant Energy
------------------
($ millions) 2002 2001
--------------------------------------------------------------------

Revenues $ 1,454 $ 4085(xx)
--------------------------------------------------------------------
Expenses
Operating - -
Purchased product 1,465 3983(xx)
Administrative 35 43
Interest, net - -
Foreign exchange (gain) - -
Depreciation, depletion and amortization - 4
Loss on discontinuance 30 -
--------------------------------------------------------------------
1,530 4,030
--------------------------------------------------------------------
Net (Loss) Earnings Before Income Tax (76) 55
Income tax expense (recovery) (27) 22
--------------------------------------------------------------------
Net (Loss) Earnings from Discontinued Operations $ (49) $ 33
--------------------------------------------------------------------
--------------------------------------------------------------------

Midstream -
Pipelines (*) Total
---------------------------------------
($ millions) 2002 2001 2002 2001
--------------------------------------------------------------------
Revenues $ 212 $ - $ 1,666 $ 4,085
--------------------------------------------------------------------
Expenses
Operating 78 - 78 -
Purchased product - - 1,465 3,983
Administrative - - 35 43
Interest, net 30 - 30 -
Foreign exchange (gain) (3) - (3) -
Depreciation, depletion
and amortization 27 - 27 4
Loss on discontinuance - - 30 -
--------------------------------------------------------------------
132 - 1,662 4,030
--------------------------------------------------------------------
Net (Loss) Earnings
Before Income Tax 80 - 4 55
Income tax expense
(recovery) 32 - 5 22
--------------------------------------------------------------------
Net (Loss) Earnings from
Discontinued Operations $ 48 $ - $ (1) $ 33
--------------------------------------------------------------------
--------------------------------------------------------------------
(*) Reflects only nine months of earnings as EnCana did not own the
pipelines until April 5, 2002.

(xx) Upon review of additional information related to 2001 sales and
purchases of natural gas by the U.S. marketing subsidiary, the
Company has determined certain revenue and expenses should have been
reflected in the financial statements on a net basis rather than
included on a gross basis as Revenue and Expenses - Purchased
product. The amendment had no effect on net earnings or cash flow
but Revenues and Expenses - Purchased product have been reduced by
$1,126 million.


Consolidated Balance Sheet
As at December 31,
----------------------------------------
Midstream -
Merchant Energy Pipelines
----------------------------------------
($ millions) 2002 2001 2002 2001
--------------------------------------------------------------------
Assets
Cash and cash equivalents $ - $ - $ 68 $ -
Accounts receivable and
accrued revenue 632 31 -
Inventories - 70 1 -
--------------------------------------------------------------------
- 702 100 -

Capital assets, net - 9 817 -
Investments and other
assets - 17 374 -
Goodwill - - 191 -
--------------------------------------------------------------------
- 728 1,482 -
--------------------------------------------------------------------
Liabilities
Accounts payable and
accrued liabilities 5 584 40 -
Income tax payable - - 17 -
Current portion of
long-term debt - - 23 -
--------------------------------------------------------------------
5 584 80 -

Long-term debt - - 576 -
Deferred credits and
other liabilities - 2 - -
Future income taxes - - 164 -
--------------------------------------------------------------------
5 586 820 -
-------------------------------------------------------------------
Net Assets of
Discontinued Operations $ (5) $ 142 $ 662 $ -
--------------------------------------------------------------------
--------------------------------------------------------------------

Total
-------------------
($ millions) 2002 2001
--------------------------------------------------------------------
Assets
Cash and cash equivalents $ 68 $ -
Accounts receivable and accrued revenue 31 632
Inventories 1 70
--------------------------------------------------------------------
100 702

Capital assets, net 817 9
Investments and other assets 374 17
Goodwill 191 -
--------------------------------------------------------------------
1,482 728
--------------------------------------------------------------------

Liabilities
Accounts payable and accrued liabilities 45 584
Income tax payable 17 -
Current portion of long-term debt 23 -
--------------------------------------------------------------------
85 584

Long-term debt 576 -
Deferred credits and other liabilities - 2
Future income taxes 164 -
--------------------------------------------------------------------
825 586
--------------------------------------------------------------------
Net Assets of Discontinued Operations $ 657 $ 142
--------------------------------------------------------------------
--------------------------------------------------------------------

The above table does not include any financial information for 2001
related to Midstream - Pipelines as EnCana did not own the pipelines being
discontinued at that time.

6. INCOME TAXES

Three Months Year Ended
Ended December 31 December 31
---------------------------------------
($ millions) 2002 2001 2002 2001
--------------------------------------------------------------------
Provision for Income Taxes
Current
Canada $ (159) $ 50 $ (30) $ 504
United States - (2) (49) (9)
Ecuador 13 - 27 -
United Kingdom (12) (7) - -
Other 1 1 3 2
--------------------------------------------------------------------
(157) 42 (49) 497
Future 396 23 667 134
--------------------------------------------------------------------
$ 239 $ 65 $ 618 $ 631
--------------------------------------------------------------------
--------------------------------------------------------------------


7. SHORT-TERM DEBT

As at December 31,
----------------------
($ millions) 2002 2001
-------------------------------------------------------------------------
Canadian Dollar Denominated Debt
Revolving credit and term loan borrowings $ 438 $ -
-------------------------------------------------------------------------

At December 31, 2002, one of the Company's subsidiaries had in place
short-term debt of $438 million. The borrowing is under a non-revolving credit
facility, which has an expiry date of May 2003 with a provision for an
extension for a further six months at the option of the lender and upon the
request from the subsidiary. This facility was repaid in full subsequent to
year end and then cancelled.

8. LONG-TERM DEBT

As at December 31,
----------------------
($ millions) 2002 2001
-------------------------------------------------------------------------
Canadian Dollar Denominated Debt
Revolving credit and term loan borrowings $ 1,388 $ 37
Unsecured notes and debentures 1,825 125
-------------------------------------------------------------------------
3,213 162
-------------------------------------------------------------------------

U.S. Dollar Denominated Debt
U.S. revolving credit and term loan borrowings 696 -
U.S. unsecured notes and debentures 3,608 2,208
-------------------------------------------------------------------------
4,304 2,208
-------------------------------------------------------------------------
7,517 2,370
Increase in Value of Debt Acquired 90 -
Current Portion of Long-term Debt (212) (160)
-------------------------------------------------------------------------
$ 7,395 $ 2,210
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Certain notes and debentures of the Company were acquired in the business
combination described in Note 3 and are accounted for at their fair value. The
difference between the fair value and the principal amount of the debt
acquired is being amortized over the remaining life of the outstanding debt
acquired, approximately 24 years.
As required by Canadian generally accepted accounting principles, the
Company's U.S. dollar denominated debt is translated into Canadian dollars at
the period end exchange rate. Translation gains and losses are recorded in
income. The $20 million foreign exchange gain for the year ended December 31,
2002, includes a foreign exchange gain of $34 million ($27 million after tax)
related to the translation of U.S. dollar debt. Included in the $4 million
foreign exchange loss for the three months ended December 31, 2002, is a
foreign exchange gain of $13 million ($10 million after tax) related to the
translation of U.S. dollar debt.
On October 16, 2002, the Company announced that it had established
October 22, 2002 as the record date for a meeting of Capital Securities
holders to consider, and if thought advisable to approve, amendments to the
terms of such Capital Securities to provide the Company with the right to call
for the early redemption of the Capital Securities, with a face value of $430
million. On November 26, 2002, the holders approved the amendments and on
December 9, 2002, the Company redeemed the Capital Securities for total
consideration of $495 million, including accrued and unpaid interest of $17
million.
On December 24, 2002, the Company repurchased the US$85 million 7.34%
Notes and the US$113 million 6.78% Notes for total consideration of
approximately US$226 million, including accrued and unpaid interest.


9. SHARE CAPITAL

December 31, 2002 December 31, 2001
(millions) Number Amount Number Amount
-------------------------------------------------------------------------
Common Shares Outstanding,
Beginning of Year 254.9 $ 196 254.8 $ 148
Shares Issued to AEC
Shareholders (Note 3) 218.5 8,397 - -
Shares Issued under
Option Plans 5.5 139 1.9 48
Shares Repurchased - - (0.2) -
Adjustments due to Canadian
Pacific Limited
Reorganization - - (1.6) -
-------------------------------------------------------------------------
Common Shares Outstanding,
End of Year 478.9 $8,732 254.9 $ 196
-------------------------------------------------------------------------
-------------------------------------------------------------------------

The Company has a stock-based compensation plan (EnCana plan) that allows
employees 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 EnCana and Canadian Pacific Limited replacement plans expire 10
years from the date the options were granted.
In conjunction with the business combination transaction described in
Note 3, options to purchase AEC common shares were replaced with options to
purchase common shares of EnCana (AEC replacement plan). The transaction also
resulted in these replacement options, along with all options outstanding
under the EnCana plan, becoming exercisable after the close of business on
April 5, 2002.
The following tables summarize the information about options to purchase
common shares at December 31, 2002:


Weighted
Share Average
Options Exercise
(millions) Price ($)
-------------------------------------------------------------------------
Outstanding, Beginning of Year 10.5 32.31
Granted under EnCana Plan 12.1 48.13
Granted under AEC Replacement Plan 13.1 32.01
Granted under Directors' Plan 0.1 48.04
Exercised (5.5) 25.20
Forfeited (0.7) 43.81
-------------------------------------------------------------------------
Outstanding, End of Year 29.6 39.74
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Exercisable, End of Year 17.7 34.10
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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 3.5 1.3 18.75 3.5 18.75
20.00 to 24.99 2.1 2.3 22.25 2.1 22.25
25.00 to 29.99 3.2 2.3 26.58 3.2 26.58
30.00 to 43.99 1.9 3.1 38.56 1.7 38.11
44.00 to 53.00 18.9 3.9 47.91 7.2 47.42
-------------------------------------------------------------------------
29.6 3.0 39.74 17.7 34.10
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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:

Year Ended
December 31
-------------------
($ millions, except per share amounts) 2002 2001
-------------------------------------------------------------------------

Compensation Costs 80 39

Net Earnings
As reported 1,224 1,287
Pro forma 1,144 1,248

Net Earnings per Common Share
Basic
As reported 2.92 5.02
Pro forma 2.73 4.87
Diluted
As reported 2.87 4.90
Pro forma 2.68 4.75
-------------------------------------------------------------------------

As described above, the acquisition of AEC resulted in all outstanding
options at April 5, 2002 becoming fully exercisable. As the stock option
expense is normally recognized over the expected life, the early vesting of
outstanding options resulted in an acceleration of the compensation cost. As
such, a $33 million expense relating to options outstanding at April 5, 2002
was included in the 2002 pro forma earnings above.
The fair value of each option granted is estimated on the date of grant
using the Black-Scholes option-pricing model with weighted average assumptions
for grants as follows:

Year Ended
December 31
-------------------
2002 2001
-------------------------------------------------------------------------
Weighted Average Fair Value of Options Granted $13.31 $13.53
Risk Free Interest Rate 4.29% 4.24%
Expected Lives (years) 3.00 3.00
Expected Volatility 0.35 0.35
Annual Dividend per Share $0.40 $0.40
-------------------------------------------------------------------------
-------------------------------------------------------------------------

10. PER SHARE AMOUNTS

The following table summarizes the common shares used in calculating net
earnings and cash flow per common share.

Three Months Ended Year Ended
--------------------------------------------------------
March 31 June 30 September 30 December 31 December 31
2002 2002 2002 2002 2001 2002 2001
-------------------------------------------------------------------------
Weighted Average
Common Shares
Outstanding
- Basic 255.3 461.1 476.8 477.9 254.8 417.8 255.6
-------------------------------------------------------------------------
Effect of
Dilutive
Securities 5.7 8.9 5.4 7.3 5.8 7.3 6.2
-------------------------------------------------------------------------
Weighted Average
Common Shares
Outstanding
- Diluted 261.0 470.0 482.2 485.2 260.6 425.1 261.8
-------------------------------------------------------------------------

The net earnings per common share calculations include the effect of the
Distributions on Preferred Securities, net of tax for the three months of $1
million (2001 - $1 million) and for the year to date $3 million (2001 -
$4 million).


11. RISK MANAGEMENT

Unrecognized gains (losses) on risk management activities:

($ millions) December 31, 2002
-------------------------------------------------------------------------
Natural gas 302
Crude oil (122)
Gas storage (43)
Natural gas liquids (3)
Power (3)
Foreign currency (90)
Interest rates 62
-------------------------------------------------------------------------
103
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Information with respect to contracts in place at December 31, 2001, is
disclosed in Note 17 to the PanCanadian annual audited Consolidated Financial
Statements and Note 15 to the AEC annual audited Consolidated Financial
Statements.

12. SUBSEQUENT EVENTS

Amalgamation with Alberta Energy Company Ltd.

On January 2, 2003, the Company announced that it had completed its
vertical short-form amalgamation with its wholly owned subsidiary AEC
effective January 1, 2003. EnCana Corporation is now the successor issuer in
respect of AEC's previously issued debt securities, including the Preferred
Securities, and will be responsible for all AEC's contractual obligations.

Sale of interests in Cold Lake and Express Pipeline Systems

On January 2, 2003 and January 9, 2003, the Company announced that it had
completed its previously announced sales of its interests in the Cold Lake and
Express Pipeline Systems for estimated total proceeds of approximately
$1.6 billion, including assumption of related long-term debt. Both sales are
subject to closing and post-closing adjustments.

Sale of interest in Syncrude Joint Venture

On February 3, 2003, the Company announced it had reached agreement with
Canadian Oil Sands Limited to sell a 10 percent interest in the Syncrude Joint
Venture for approximately $1.07 billion. The Company has also granted Canadian
Oil Sands Limited an option, which expires December 31, 2003, to purchase its
remaining 3.75% interest in Syncrude and a gross overriding royalty. If
exercised, the option would generate approximately $417 million in additional
proceeds.

13. RECLASSIFICATION

Certain information provided for prior periods has been reclassified to
conform to the presentation adopted in 2002.


EnCana Corporation
Pro Forma Consolidated
Financial Statements
(Unaudited)
For the Year Ended December 31, 2002


Pro Forma
Consolidated Statement of Earnings
(Unaudited)
-------------------------------------------------------------------------
($ millions, except AEC
per share amounts) EnCana 3 Months
Year Ended Ended Pro Forma EnCana
December 31 March 31, Adjustments Pro Forma
2002 2002 Note 1 Consolidated
-------------------------------------------------------------------------
Revenues, Net of
Royalties and
Production Taxes
Upstream $ 5,864 $ 844 $ (141) $ 6,567
Midstream and Marketing 4,133 358 141 4,632
Other 14 - - 14
-------------------------------------------------------------------------
10,011 1,202 - 11,213
Expenses
Transportation and selling 574 103 - 677
Operating 1,438 202 - 1,640
Purchased product 3,448 406 - 3,854
Administrative 187 24 - 211
Interest, net 419 61 9 489
Foreign exchange (gain) (20) (1) - (21)
Depreciation, depletion and
amortization 2,153 302 45 2,500
Gain on corporate
disposition (51) - - (51)
-------------------------------------------------------------------------
Earnings Before
the Undernoted 1,863 105 (54) 1,914
Income tax
expense (recovery) 618 39 (23) 634
Distributions on
subsidiary preferred
securities, net of tax 20 16 (5) 31
-------------------------------------------------------------------------
Net Earnings from
Continuing Operations 1,225 50 (26) 1,249
Net Earnings from
Discontinued Operations (1) 6 - 5
-------------------------------------------------- -----------------------
Net Earnings 1,224 56 (26) 1,254
Distributions on
preferred securities, net
of tax 3 - - 3
-------------------------------------------------------------------------
Net Earnings
Attributable to
Common Shareholders $ 1,221 $ 56 $ (26) $ 1,251
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Net Earnings from
Continuing Operations
per Common Share
Basic $ 2.63
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Diluted $ 2.58
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Earnings per Common Share
Basic $ 2.64
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Diluted $ 2.59
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Pro Forma
Consolidated Statement of Cash Flow
(Unaudited)
($ millions, except per share amounts)
-------------------------------------------------------------------------
($ millions, except AEC
per share amounts) EnCana 3 Months
Year Ended Ended Pro Forma EnCana
December 31 March 31, Adjustments Pro Forma
2002 2002 Note 1 Consolidated
-------------------------------------------------------------------------
Operating Activities
Net earnings from
continuing operations $ 1,225 $ 50 $ (26) $ 1,249
Depreciation, depletion
and amortization 2,153 302 45 2,500
Future income taxes 667 13 (19) 661
Other (266) 9 - (257)
-------------------------------------------------------------------------
Cash Flow from
Continuing Operations 3,779 374 - 4,153
Cash Flow from
Discontinued Operations 42 16 - 58
-------------------------------------------------------------------------
Cash Flow 3,821 390 - 4,211
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Cash Flow from Continuing
Operations per Common Share
Basic $ 8.77
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Diluted $ 8.59
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash Flow per Common Share
Basic $ 8.89
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Diluted $ 8.71
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>


EnCana Corporation
Notes to Pro Forma Consolidated Financial Statements
December 31, 2002
(Unaudited)


1. Basis of Presentation

The unaudited Pro Forma Consolidated Statement of Earnings and
Consolidated Statement of Cash Flow have been prepared for information
purposes using information contained in the following:

(a) EnCana's unaudited Consolidated Financial Statements for the year
ended December 31, 2002
(b) AEC's unaudited Consolidated Financial Statements for the three
months ended March 31, 2002.

The pro forma adjustments include adjustments for financial statement
presentation of segmented financial information. To be consistent with
EnCana's segmented presentation, revenues associated with AEC's purchased gas
activity have been reclassified from Upstream revenue.
All pro forma adjustments related to the purchase price allocation have
been based upon the Business Combination information disclosed in Note 3 of
the December 31, 2002 unaudited Consolidated Financial Statements of EnCana
and assume that the transaction occurred on January 1, 2002.
Pro forma adjustments made in the unaudited Pro Forma Consolidated
Statement of Earnings and unaudited Pro Forma Consolidated Statement of Cash
Flow relate to (i) the recording of interest expense on the Capital Securities
of AEC, (ii) the recording of Depreciation, depletion and amortization on the
increase in the carrying value of Capital Assets resulting from the
acquisition which has been allocated to capital assets that are subject to
depreciation, depletion and amortization and (iii) the recording of the future
income tax benefits related to these additional expenses.
These unaudited Pro Forma Consolidated Financial Statements may not be
indicative of the results that actually would have occurred if the events
reflected therein had been in effect on the dates indicated or of the results
that may be obtained in the future.

For further information: 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 $14.27 Can 0

NYSE $11.11 USD 0

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