EnCana earns $458 million during inaugural quarter, generates $938 million of cash flow

Oil and natural gas sales rise 10 percent, offshore exploration success continues, gas production growth on double-digit pace in B.C. and U.S. Rockies

CALGARY, July 25 /CNW/ - EnCana Corporation (TSE & NYSE: ECA) earned
$458 million, or $0.97 per share diluted, and generated $938 million of cash
flow, or $2.00 per share diluted, in the second quarter of 2002. Included in
the second quarter earnings is an unrealized after tax gain of $134 million,
or $0.29 per share diluted, related to foreign exchange gains on EnCana's US
denominated debt. This had no impact on cash flow. Daily oil and gas sales
reached 693,104 barrels of oil equivalent, up more than 10 percent from the
pro forma second quarter results of EnCana's founding companies one year
earlier.
All references to 2001 production and six month 2002 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") and Alberta Energy Company Ltd. ("AEC") had occurred at the
beginning of the respective periods.
"I'm pleased to report that our merger is complete and EnCana is forging
full-speed ahead. We've achieved strong financial results with a growing
production base that is on track to achieve our 2002 sales targets," said Gwyn
Morgan, EnCana's President & Chief Executive Officer. "Our Onshore North
America division is expected to achieve double-digit production growth while
outstanding results in new exploration basins offer exciting future potential.
We've recently announced that our Buzzard discovery, a major light oil find in
the U.K. central North Sea, is moving to development planning. In addition, we
are a 25 percent owner in a significant Gulf of Mexico find at Tahiti that
could contain more than an estimated 400 million barrels of recoverable oil.
"In EnCana's first three months of operations, our board of directors and
executive team have clearly defined an EnCana strategy that's focused, first
and foremost, on core exploration and production ventures in North America and
in select international locations. In keeping with this, we recently announced
plans to sell our interests in two major oil pipelines in order to re-deploy
the capital into our rich inventory of upstream plus natural gas storage
opportunities," Morgan said.

Strong oil and natural gas growth continues in second quarter
EnCana's second quarter natural gas production averaged 2.7 billion cubic
feet per day, up 11 percent over pro forma results in the second quarter of
2001. During the quarter, 118 million cubic feet per day was injected into
storage, yielding second quarter sales of 2.6 billion cubic feet per day. Oil
and natural gas liquids sales averaged 263,076 barrels per day, up about
7 percent. Conventional operating plus administrative costs were approximately
$4.60 per barrel of oil equivalent in the quarter. EnCana drilled 560 net
wells in the second quarter.

For the three months ended June 30, 2002, EnCana's highlights include:
- Net earnings of $458 million, or $0.97 per common share diluted
- Cash flow of $938 million, or $2.00 per common share diluted
- Natural gas sales of 2,580 million cubic feet per day, up 12 percent
from pro forma second quarter of 2001, with the average realized price
declining 38 percent to $4.02 per thousand cubic feet
- Crude oil and natural gas liquids sales of 263,076 barrels per day, up
7 percent from pro forma second quarter of 2001, with the average
realized price up 8 percent to $31.48 per barrel
- Total capital investment, excluding dispositions, of $1,446 million
- A strong financial position with debt to capitalization of 39 percent
(all preferred securities included as debt)

Second quarter financial results strong despite lower gas prices
Despite significantly lower natural gas prices, EnCana achieved strong
financial performance. EnCana's average realized gas price in the second
quarter was $4.02 per thousand cubic feet, compared to $6.46 per thousand
cubic feet for the same period one year earlier. Gas prices improved slightly
in the second quarter from the first three months of 2002.

EnCana forward sales stabilize gas prices until expected recovery by fall
As expected, summer gas prices have now weakened due to the high levels
of North American gas storage and above-normal water levels for hydro electric
generation in the western half of North America. Western Canadian gas prices
have recently been impacted by temporary capacity restrictions on pipelines
out of Alberta. EnCana is well positioned during this current period of lower
prices as it has sold forward approximately 1.4 billion cubic feet of gas per
day until September 30, 2002. Fixed prices include 875 million cubic feet per
day at an effective AECO price of C$4.24 per thousand cubic feet, 333 million
cubic feet per day at an effective Opal, Wyo. price of US$2.61 per thousand
cubic feet and 205 million cubic feet per day at a NYMEX related price of
US$3.33 per thousand cubic feet. Looking to the fourth quarter, EnCana expects
gas prices to strengthen as North American gas production continues to drop
due to reduced drilling and high overall decline rates. EnCana is using its
natural gas storage facilities, combined with increasing field capacity, to
prepare for anticipated strong sales in the fourth quarter.

Heavy oil differentials narrowed significantly
In the second quarter of 2002, the average West Texas Intermediate crude
oil benchmark price was US$26.27 per barrel, down 6 percent from US$27.98 per
barrel for the same quarter in 2001. However, Canadian heavy oil differentials
improved dramatically, narrowing 50 percent to US$5.43 from US$10.94 per
barrel. Heavy oil prices have narrowed the gap on light grades this year due
to tight supply demand fundamentals and the resumption of processing in May at
the CITGO refinery in the U.S. Midwest. The differential for Ecuador oil
improved from a year earlier, dropping to average US$3.78 from US$8.09 per
barrel. Oil prices have continued to strengthen through 2002 due to a number
of factors including the production management agreement between OPEC and
non-OPEC producers, problems with Iraqi crude deliveries, the war on terrorism
and indications that the world economy is improving.

Six months pro forma financial and operating performance
For the first six months of 2002, EnCana earned pro forma $632 million,
or $1.28 per share diluted, and generated $1.7 billion in cash flow, or
$3.57 per share diluted. First half sales averaged 696,969 barrels of oil
equivalent per day, up 10 percent over pro forma sales from one year earlier.
First half daily sales were comprised of 2.7 billion cubic feet of natural
gas, up 16 percent in the past year, and 225,008 barrels of oil and natural
gas liquids, up 3 percent over pro forma sales for the first half of 2001.
EnCana drilled 1,561 net wells in the first half.
These pro forma six-month results represent EnCana as if it had existed
as a merged company for the periods noted, whereas the attached six-month
financial statements are actuals, reflecting EnCana second quarter results and
PanCanadian first quarter results alone.

2002 capital investment to fund multiple growth opportunities
"Since receiving shareholder approval of the merger in early April, our
new business units have conducted a thorough review of our portfolio of
opportunities. We have identified an even stronger array of multi-year,
organic growth opportunities that are expected to generate rates of return
exceeding 20 percent after tax at current strip prices. While we may be facing
softer natural gas prices in the very short term, the inaugural EnCana capital
program is aimed at building productive capacity for what we believe will soon
be strong gas prices.
"In our three current key producing platforms - Western Canada, the U.S.
Rockies and Ecuador - we have identified profitable organic growth
opportunities that are expected to generate growth of 10 percent plus for the
next several years. Starting in 2005, exciting new exploration discoveries in
three additional platforms - the U.K. North Sea, the Gulf of Mexico and off
Canada's East Coast - are expected to layer more growth on top of that solid
base growth," Morgan said.
To capitalize on these opportunities, EnCana's board of directors has
approved a 2002 gross capital budget of approximately $5 billion. The company
expects to complete upstream asset dispositions this year of approximately
$500 million and dispositions of about $1.5 billion in midstream assets. These
dispositions, combined with about $460 million in recently-completed
acquisitions - including U.S. Rockies natural gas assets, would result in net
capital investment of approximately $3.5 billion.
Of the $5 billion capital budget, $3.5 billion is planned for Onshore
North America projects. This investment is directed about 65 percent to gas
and 35 percent to oil projects. International development of $600 million is
directed to longer term development of production growth in Ecuador, the U.K.
central North Sea and the Gulf of Mexico. EnCana's international and offshore
exploration investment is about $700 million, directed to additional appraisal
on exploration success in the Gulf of Mexico and the North Sea, plus
exploration in other select international locations.

<<
2002 EnCana Capital Budget

Primary Capital Investment (millions)
-----------------------------------------------------------------------
Onshore North America
Natural gas $ 2,240
Syncrude $ 300
SAGD $ 200
Other oil $ 760
-----------------------------------------------------------------------
Total $ 3,500
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Offshore & International Operations $ 600
Offshore & New Ventures Exploration $ 700
Midstream & Marketing $ 250
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Gross Capital Investment $ 5,050
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Acquisitions & Dispositions
-----------------------------------------------------------------------
Acquisitions upstream $ 460
Dispositions upstream (forecast) $ (500)
Dispositions midstream (forecast) $ (1,500)
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Net Capital Investment $ 3,510
-----------------------------------------------------------------------
>>

Sales targets on track for 2002
EnCana's 2002 daily sales target is forecast to grow by about 10 percent
from 2001 pro forma sales. The 2002 forecast is between 2,675 million and
2,745 million cubic feet of gas and 245,000 and 264,000 barrels of oil, for a
total daily sales forecast of between 690,000 and 721,000 barrels of oil
equivalent. Sales in 2003 are forecast to rise about 13 percent above the
midpoint of the 2002 forecast, reaching between 775,000 and 825,000 barrels of
oil equivalent per day.

Important Notice: Readers are cautioned that a portion of the six 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 ending EnCana EnCana
June 30, 2002) 3 months 6 months
($ millions, except per share amounts) Actuals Pro forma
------------------------------------------------------------------------
Revenues, net of royalties and production taxes 2,676 4,915
Cash Flow 938 1,728
Per share - basic 2.03 3.65
Per share - diluted 2.00 3.57
Net earnings 459 638
Per share - basic 0.99 1.31(1)
Per share - diluted 0.97 1.28
Capital investment, excluding dispositions 1,446 2,742
Total assets 29,479 n/a
Long-term debt 7,525 n/a
Preferred securities, including those of AEC 575 n/a
Shareholders' equity 12,960 n/a
Debt-to-capitalization ratio 39% n/a
(adjusted for working capital and including
preferred securities as debt)
------------------------------------------------------------------------
Common shares
Outstanding June 30, 2002 (millions) 476.3 n/a
Weighted average diluted (millions) 470.0 483.5
------------------------------------------------------------------------
>>
1 Impact of including share options in earnings calculations
As required by Canadian generally accepted accounting principles, the
notes in EnCana's second quarter financial statements show that the
inclusion of stock options as compensation expense in the calculations
of earnings would have resulted in a reduction of 14 cents shown in
basic earnings per share in the first half of 2002.

<<
Operating Highlights Q2 2002 Q2 2001 Percent
(for the three months ending June 30) Actuals Pro forma Change
-------------------------------------------------------------------------
Sales
Total barrels of oil equivalent per day 693,104 628,894 +10

Natural gas (million cubic feet per day) 2,580 2,297 +12

Total liquids (barrels per day) 263,076 246,061 + 7
North America
Conventional oil and NGLs 166,951 152,487 + 9
Syncrude 24,295 29,162 -17
International 71,830 64,412 +12
-------------------------------------------------------------------------
Prices
North American gas price
($ per thousand cubic feet) 4.02 6.46 -38

North American conventional oil price
($ per barrel)
Light/medium 33.76 30.38 +11
Heavy 26.09 17.92 +46
Syncrude ($ per barrel) 40.09 42.27 - 5
International crude oil ($ per barrel)
Ecuador 31.69 28.12 +12
U.K. 37.78 36.27 +12
Natural gas liquids ($ per barrel) 29.92 36.83 -19
Total liquids ($ per barrel) 31.48 29.06 + 8
-------------------------------------------------------------------------
>>

EnCana corporate developments

Integration on track after creation of EnCana Corporation on
April 5, 2002
Following overwhelming support at separate meetings on April 4, 2002 of
shareholders and optionholders of AEC and shareholders of PanCanadian, the
Court of Queen's Bench of Alberta approved the merger of the two companies and
EnCana Corporation was created on April 5, 2002. EnCana common shares began
trading on the Toronto and New York stock exchanges on April 8, 2002 under the
symbol ECA. Immediately thereafter, the reorganization of the company into
decentralized, fully accountable business units was implemented. The company
has identified and is moving forward to achieve operating and administrative
synergies of at least $250 million and capital synergies in excess of
$250 million on a yearly pre-tax basis in 2003. An estimated $50 million in
annual administrative synergies have been already achieved.

Dividends
The board of directors of EnCana declared a quarterly dividend of ten
cents (10 cents) per share payable on September 30, 2002 to common
shareholders of record as of September 13, 2002.


EnCana operational highlights

Onshore North America

Continued strong natural gas growth
EnCana's North America natural gas production during the second quarter
increased to 2.7 billion cubic feet per day, up 11 percent compared to pro
forma results of the same period last year. The production increase came
primarily from the U.S. Rockies and northeast British Columbia. The Onshore
North America division drilled more than 540 net wells during the second
quarter.

Acquisition of high-quality U.S. Rockies assets completed
EnCana has completed the acquisition, for C$420 million (US$276 million),
of approximately 500 billion cubic feet equivalent of established, long-life
natural gas and associated natural gas liquids reserves and about 180,000 net
acres of undeveloped land in the Piceance Basin of northwest Colorado. With
this purchase, U.S. Rockies production increased in the month of June to about
490 million cubic feet of natural gas per day.
Since acquiring its first assets in the region in June 2000, EnCana has
grown U.S. Rockies production through drilling and acquisitions by more than
3.5 times. With more than 1.4 million net undeveloped acres in Colorado,
Wyoming, Montana and Utah, the company is a leading producer in the region.
Through the application of technical expertise to the company's inventory of
long-life, multi-zone, tight-gas formations that are prevalent in the region,
EnCana expects to grow U.S. Rockies gas production by more than 15 percent per
year over the next three years.

Greater Sierra staged for long term natural gas growth
Over the past four years, EnCana has identified one of North America's
largest new regional gas plays in the Greater Sierra region of northeast
British Columbia. Major land purchases in the first half of 2002 increased
EnCana's land position to more than 2 million net acres of undeveloped land,
making EnCana the leader in the play. In the first half of 2002, EnCana
completed a successful 45 well program, adding about 150 billion cubic feet of
established reserves. Daily gas production from Greater Sierra, currently
about 150 million cubic feet, is targeted to more than double in the next
three years, and continue to grow after that. EnCana is the leading explorer,
producer and landholder in British Columbia - one of the fastest growing gas
producing regions in North America.

Oil and natural gas liquids production rise
Production of conventional oil and natural gas liquids from its Onshore
North America division averaged 167,000 barrels per day in the second quarter
of 2002, a 9 percent increase from pro forma results of the second quarter of
2001. Growth is due primarily to the start up of EnCana's Foster Creek steam-
assisted gravity drainage (SAGD) project in northeast Alberta, increased
production at Suffield and enhanced oil recovery at the company's Weyburn
CO(2) project in Saskatchewan.

Two SAGD projects underway
EnCana has started steam injection at the company's SAGD project at
Christina Lake, where first production is expected in the third quarter of
2002. Production from the world's first large scale SAGD project - Foster
Creek - averaged 12,000 barrels per day during the second quarter, slightly
below expectations as it has taken longer than expected to bring water
treatment facilities to full operating performance. Foster Creek production is
forecast to reach the full design level of 20,000 barrels per day later this
summer. In combination, EnCana's SAGD projects are expected to generate more
than 120,000 barrels per day of production by 2007.

Syncrude costs and volumes impacted by scheduled maintenance
EnCana's daily production from Syncrude during the second quarter of 2002
averaged 24,295 barrels, down 17 percent from the same period last year. Unit
operating costs rose by $8.93 per barrel to average $30.47 per barrel in the
second quarter of 2002 compared to the same period last year. Volumes were
lower and costs higher because the planned 35-day maintenance of a coker unit
took 52 days to complete due to additional maintenance required on the coker
burner and the heavy gas oil hydrotreater. The work has been completed and
Syncrude is currently operating at full production rates. Syncrude is
currently producing in the range of 34,000 to 35,000 barrels per day, net to
EnCana. The company is expecting operating costs of approximately $18 to $19
per barrel for 2002.


Offshore & International Operations

Ecuador - strong second quarter sales
Oil production in Ecuador, which is constrained by a lack of pipeline
capacity, averaged 52,744 barrels of oil per day in the second quarter. Daily
oil sales averaged 59,864 barrels, up 12 percent from the same period one year
earlier due to the scheduling of tanker shipments leaving port. Construction
of the OCP Pipeline is about 50 percent complete, with first oil shipments
expected in mid 2003. EnCana is targeting to increase its Ecuador production
to between 80,000 and 100,000 barrels per day by late in 2003. Achieving the
upper end of the range requires approval by the Government of Ecuador to move
onto adjacent lands to follow up on exploration success.

U.K. North Sea - Buzzard moves to development planning
Development planning for the EnCana operated Buzzard light oil discovery
is underway following a very successful appraisal drilling program. The eight
appraisal wells and sidetracks drilled to date have confirmed the nature and
extent of the Buzzard field, located in the U.K. central North Sea and
discovered in June 2001. The current estimate of oil-in-place is between
800 million and 1.1 billion barrels. Further study and analysis is underway to
establish estimated potential recoverable reserve figures. A program to
evaluate nearby exploration and satellite development potential has also
begun.

East Coast of Canada - Deep Panuke project in regulatory review
The Canada-Nova Scotia Offshore Petroleum Board and the National Energy
Board are reviewing the development plan for EnCana's Deep Panuke natural gas
project off the coast of Nova Scotia. EnCana continues to work closely with
regulators with the objective of streamlining the regulatory process.
Regulatory hearings for the project were expected to start in the third
quarter of 2002, with a decision in the first quarter of 2003. Based on
current assumptions, commercial production is targeted to begin in 2005,
however the regulatory process has been slower than expected and EnCana will
revisit its schedule once satisfactory regulatory approvals are obtained. Deep
Panuke involves the production and processing of raw gas offshore, the
transport of market-ready gas via sub-sea pipeline to Goldboro, Nova Scotia,
and an interconnection with the Maritimes and Northeast Pipeline main
transmission pipeline. The project is estimated to recover reserves of natural
gas approaching one trillion cubic feet.


Offshore & New Ventures Exploration

U.K. North Sea - Black Horse well encounters hydrocarbons
EnCana and its partner ExxonMobil completed drilling the Black Horse
prospect located about 160 kilometres northeast of Aberdeen, Scotland on
EnCana operated licence P.185. The prospect straddles two licences: P.185
"Black Horse Area", where EnCana owns approximately 57 percent and ExxonMobil
approximately 43 percent, and P.489, which is 100 percent EnCana. During
testing, the well flowed light oil at a rate of 6,274 barrels per day and
natural gas at 3.9 million cubic feet per day on a 24/64-inch choke. The well
has been suspended. Evaluation of test results is underway to determine if the
discovery has commercial potential.
In the recent U.K. 20th Licencing Round, EnCana and its partners were the
successful bidders on five exploration blocks in the company's central North
Sea core area; four of these will be operated by EnCana.

Gulf of Mexico - Tahiti discovery moves to appraisal
The operator of the Tahiti deepwater oil discovery, ChevronTexaco,
recently estimated that the Gulf of Mexico find holds 400 million to
500 million barrels of recoverable oil. EnCana owns a 25 percent interest in
Tahiti, located in Green Canyon Block 640, approximately 190 miles southwest
of New Orleans in the deepwater Gulf of Mexico. Initial results of the Tahiti
No. 1 well, drilled in 4,000 feet of water, indicate a high-quality reservoir
sand with total net pay of more than 400 feet. Tahiti No. 1 is the second well
in EnCana's four-well commitment to earn a 25-percent interest in 71
ChevronTexaco-operated blocks in the Mississippi Fanfold Belt in the Gulf of
Mexico. Completion of the four-well program is expected by early 2003.


Midstream & Marketing

Maximizing value
On July 9, 2002, EnCana announced that it is seeking potential buyers for
its interests in two major oil pipelines - the 100-percent-owned Express
Pipeline System and the 70-percent-owned Cold Lake Pipeline System. Both of
these oil transportation systems deliver Canada's growing oil sands production
to Canadian, U.S. Rocky Mountain and Midwest refineries.
The 1,717-mile Express Pipeline System is comprised of two major
pipelines: Express with a capacity of more than 172,000 barrels per day and
Platte, delivering up to 150,000 barrels per day. The pipelines run from
Alberta's oil transportation hub at Hardisty through Casper, Wyo. to Wood
River, Ill. The Cold Lake Pipeline system is comprised of two delivery legs,
each delivering oil from Cold Lake, Alberta to Edmonton and Hardisty, where it
connects with Express and other intercontinental pipelines. The financial
information related to the Express and Cold Lake pipeline systems has been
presented as Discontinued Operations in the second quarter unaudited
consolidated financial statements.

Midstream focused on gas storage, Wild Goose expansion approved by
California regulator
The key focus of EnCana's Midstream growth will be expansion of North
America's largest independent gas storage network. The California Public
Utilities Commission recently approved EnCana's application to more than
double the size of the Wild Goose gas storage facility in northern California.
Under the proposal, the facility's working gas capacity would expand from 14
billion to 29 billion cubic feet, withdrawal rates would climb from 200
million to 700 million cubic feet per day and injection rates would increase
from 80 million to 450 million cubic feet per day. Construction started this
week and expansion facilities are expected to be in service beginning April
2004. EnCana plans to aggressively pursue new North American gas storage
opportunities in order to expand capacity to supply volumes at peak periods of
demand in the anticipated growing market.

Energy Services
On April 25, the company announced that it was discontinuing the former
PanCanadian Houston-based merchant energy trading operations, a decision that
was made following a strategic review of the merged company's core operations.
The company has recorded a $49 million after tax loss, which is included in
discontinued operations.

Operating cash flow forecast update
EnCana's Midstream & Marketing division achieved $66 million of operating
cash flow in the second quarter. The company is forecasting 2002 operating
cash flow of approximately $200 million from continuing operations and $150
million from discontinued operations. This has been revised downward from the
previous forecast due to a number of factors, including a temporary reduction
in gas price volatility, lower electricity prices than previously forecast in
Alberta and the wind-down of EnCana's Houston-based merchant energy trading
operations.

Financial Strength

EnCana possesses one of the strongest financial positions among upstream
independents. At June 30, 2002, the company's debt-to-capitalization ratio was
39:61 (all preferred securities included as debt). Second quarter core capital
investment and acquisitions were $1,446 million. Dispositions were $240
million, bringing net capital investment to $1,206 million. EnCana maintains
strong investment grade ratings from the major bond rating services: Dominion
Bond Rating Service, A(low), Moody's Investment Service, Baa1, and Standard
and Poor's, A-.
EnCana continues to strive to achieve best in class practices in all
areas of operations, including corporate governance and disclosure.
"Each member of EnCana's executive team has a track record of more than
20 years of respected and credible business performance. The combined business
experience of the 16-member board of directors is more than 450 years. Fifteen
of EnCana's 16 directors are independent. The board maintains several
independent committees - including reserves, compensation, pension,
governance, audit and environment. EnCana's policy is to have 100 percent of
its oil and gas reserves evaluated by external engineers. Integrity has always
been at the core of our business practices as, over more than two decades, we
have, step-by-step, built a world class company," Morgan said.

-------------------------------------------------------------------------
IMPORTANT NOTICE

This press release and Alberta Energy Company Ltd.'s second quarter 2002
financial statements are filed on Sedar and posted on www.sedar.com.

This press release, EnCana's pro forma consolidated six month financial
statements and supplemental information are posted on the company Web
site www.encana.com.
-------------------------------------------------------------------------

-------------------------------------------------------------------------
CONFERENCE CALL TODAY

EnCana Corporation will host a conference call today, Thursday, July 25,
2002 starting at 1:30 p.m., Mountain Time (3:30 p.m. Eastern Time) to
discuss EnCana's second quarter 2002 financial and operating results.

To participate, please dial 416-640-4127 approximately 10 minutes prior
to the conference call. An archived recording of the call will be
available from approximately midnight on July 25, 2002 until August 1,
2002 by dialling 416-640-1917 and entering pass code 198378 (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/encana20020725. The Web cast will be
archived for 60 days.
-------------------------------------------------------------------------

EnCana is the largest North American based independent oil and gas
company with an enterprise value of approximately C$28 billion. It 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: Western Canada, offshore Canada's East Coast, the U.S. Rocky
Mountains and the Gulf of Mexico. 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: Ecuador, where EnCana is the largest private sector oil
producer, and the U.K. central North Sea, where EnCana is the operator of a
very large oil discovery. 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, the U.K. central North Sea and Ecuador; the anticipated oil and
natural gas prices for the remainder of 2002; the sources and deployment of
expected capital in 2002; the timing of regulatory review regarding Deep
Panuke and the projected production date from the Deep Panuke project; the
anticipated timing for the completion of the discontinuance of EnCana's
Houston-based merchant energy operations; projected increases in daily
production of oil, natural gas and natural gas liquids to 2007; potential
exploration; the potential success of certain projects such as SAGD and the
expected rates of returns from projects; the ability to sell the Cold Lake and
Express pipeline interests and the price realized on such sales; and the
potential success of other exploratory wells in the Gulf of Mexico 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.

Interim Report EnCana Corporation
For the period ended June 30, 2002

<<
Consolidated Statement of Earnings
June 30
-----------
Three Months Ended Six Months Ended
(unaudited) ($ millions, ----------------------------------------
except per share amounts) 2002 2001 2002 2001
-------------------------------------------------------------------------
Revenues, Net of Royalties
and Production Taxes (note 4) $ 2,676 $ 1,136 $ 3,737 $ 2,811
-------------------------------------------------------------------------
Expenses (note 4)
Transportation and selling 158 37 207 82
Operating 458 162 629 371
Purchased product 854 164 1,234 641
Administrative 44 21 61 41
Interest, net 103 6 130 19
Foreign exchange (note 7) (170) (26) (180) (3)
Depreciation, depletion
and amortization 580 215 794 389
-------------------------------------------------------------------------
2,027 579 2,875 1,540
-------------------------------------------------------------------------
Net Earnings Before the Undernoted 649 557 862 1,271
Income tax expense (note 6) 155 112 237 383
-------------------------------------------------------------------------
Net Earnings from Continuing
Operations 494 445 625 888
Net Earnings from Discontinued
Operations (note 5) (36) 14 (34) 34
-------------------------------------------------------------------------
Net Earnings 458 459 591 922
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Earnings per Common
Share (note 9)

Net Earnings From Continuing Operations
Basic $ 1.07 $ 1.74 $ 1.74 $ 3.47
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Diluted $ 1.05 $ 1.70 $ 1.71 $ 3.39
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Net Earnings
Basic $ 0.99 $ 1.79 $ 1.65 $ 3.60
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Diluted $ 0.97 $ 1.75 $ 1.62 $ 3.52
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Consolidated Statement of Retained Earnings

Six Months Ended June 30
--------------------------
(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 591 922
Dividends on Common Shares
& Other Distributions,
net of tax (74) (53)
Other adjustments - (50)
-------------------------------------------------------------------------
Retained Earnings, End of Period $ 4,147 $ 4,498
-------------------------------------------------------------------------
-------------------------------------------------------------------------

See accompanying notes to Consolidated Financial Statements


Consolidated Balance Sheet
As at As at
June 30 December 31
-----------------------
(unaudited) ($ millions) 2002 2001
-------------------------------------------------------------------------
Assets
Current Assets
Cash and cash equivalents $ 166 $ 963
Accounts receivable and accrued revenue 1,464 623
Inventories 518 87
-------------------------------------------------------------------------
2,148 1,673
Capital Assets, net (note 4) 22,140 8,162
Investments and Other Assets 441 237
Assets of Discontinued Operations (note 5) 1,673 728
Goodwill (note 3) 3,077 -
-------------------------------------------------------------------------
(note 4) $29,479 $10,800
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Liabilities and Shareholders' Equity
Current Liabilities
Accounts payable $ 1,758 $ 824
Income tax payable 405 656
Current portion of long-term debt (note 7) 108 160
-------------------------------------------------------------------------
2,271 1,640
Long-Term Debt (note 7) 7,525 2,210
Deferred Credits and Other Liabilities 530 325
Future Income Taxes 4,679 2,060
Liabilities of Discontinued Operations (note 5) 1,065 586
Preferred Securities of Subsidiary 449 -
-------------------------------------------------------------------------
16,519 6,821
-------------------------------------------------------------------------
Shareholders' Equity
Preferred securities 126 126
Share capital (note 8) 8,662 196
Fair value of options acquired to
purchase common shares (note 3) 154 -
Paid in surplus 40 27
Retained earnings 4,147 3,630
Foreign currency translation
adjustment (note 2) (169) -
-------------------------------------------------------------------------
12,960 3,979
-------------------------------------------------------------------------
$29,479 $10,800
-------------------------------------------------------------------------
-------------------------------------------------------------------------

See accompanying notes to Consolidated Financial Statements

Consolidated Statement of Cash Flows
June 30
-----------
Three Months Ended Six Months Ended
(unaudited) ($ millions, ----------------------------------------
except per share amounts) 2002 2001 2002 2001
-------------------------------------------------------------------------
Operating Activities
Net earnings $ 494 $ 445 $ 625 $ 888
Depletion, depreciation and
amortization 580 215 794 389
Future income taxes 99 (26) 141 50
Other (257) (33) (257) (14)
-------------------------------------------------------------------------
Cash flow from continuing
operations 916 601 1,303 1,313
Cash flow from discontinued
operations (note 5) 22 21 24 47
-------------------------------------------------------------------------
Cash flow 938 622 1,327 1,360
Net change in non-cash working
capital from continuing operations (200) 216 (468) 358
Net change in non-cash working
capital from discontinued
operations (54) (164) (1) (51)
-------------------------------------------------------------------------
684 674 858 1,667
-------------------------------------------------------------------------

Investing Activities
Business combination (note 3) (128) - (128) -
Capital expenditures (1,446) (454) (1,927) (831)
Proceeds on disposal of assets 240 30 243 182
Net change in investments
and other 4 12 (13) 5
Net change in non-cash working
capital from continuing
operations (219) - (250) (75)
Discontinued operations (12) 6 (12) 9
-------------------------------------------------------------------------
(1,561) (406) (2,087) (710)
-------------------------------------------------------------------------

Financing Activities
Repayment of short-term financing - - - (250)
Issuance of long-term debt 649 - 649 94
Repayment of long-term debt (77) (94) (157) (249)
Issuance of common shares 51 9 69 33
Dividends on common shares (48) (25) (73) (51)
Payments to preferred
securities holders (7) (2) (7) (4)
Net change in non-cash
working capital 2 3 (1) 1
Discontinued operations (5) - (5) -
Other (32) - (32) -
-------------------------------------------------------------------------
533 (109) 443 (426)
-------------------------------------------------------------------------

Foreign Exchange Gain (Loss)
on Cash and Cash Equivalents
held in Foreign Currency (9) (13) (11) 9
-------------------------------------------------------------------------

Increase (Decrease) in Cash
and Cash equivalents (353) 146 (797) 540
Cash and Cash Equivalents,
Beginning of Period 519 591 963 197
-------------------------------------------------------------------------
Cash and Cash Equivalents,
End of Period $ 166 $ 737 $ 166 $ 737
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Cash Flow per Common Share
Basic $ 2.03 $ 2.43 $ 3.70 $ 5.32
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Diluted $ 2.00 $ 2.38 $ 3.64 $ 5.21
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
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"), 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

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. 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 to net earnings of $81 million for 2002 (2001 -
decrease of $2 million). 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 of $92 million, as well as a reduction in deferred charges
and retained earnings of $59 million.
As a result of the business combination described in Note 3, the Company
reviewed its accounting for operations outside of Canada and determined that
all 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 and depletion, which were translated on the
same basis as the related assets.
This change was adopted prospectively beginning April 5, 2002 and results
in a decrease in net earnings of $5 million for the second quarter of 2002.

3. Business Combination

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 preliminary allocation to
assets and liabilities acquired as of April 5, 2002 is shown below. The
purchase price and goodwill allocation is preliminary because certain items
such as the determination of the final tax bases and fair values of the assets
and liabilities as of the acquisition date have not been completed. 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 167
Transaction costs 150
-----------------------------------------------------------------------
Total purchase price 8,714
Plus: Fair value of liabilities assumed
Current liabilities 1,781
Long-term debt 4,393
Project financing debt 604
Preferred securities 458
Capital securities 450
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
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>

4. Segmented Information

Due to the business combination as 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 and crude oil. Offshore & International combines the Offshore
& International Operations Division exploration for, and production of, crude
oil and natural gas in Ecuador, the Canadian East Coast, Gulf of Mexico and
the U.K. North Sea with the Offshore & New Ventures Exploration Division
exploration activity on the Canadian East Coast, the North America frontier
region, the Gulf of Mexico, the U.K. North Sea and Latin America. Midstream &
Marketing includes pipelines, natural gas liquids processing and gas storage
operations as well as, ancillary activities related to the marketing of the
Company's natural gas and crude oil production. All prior periods have been
restated to conform to these definitions. Operations that have been
discontinued are disclosed in Note 5.

<<
($ millions)
RESULTS OF OPERATIONS
(FOR THE THREE MONTHS ENDED)
Onshore Offshore & Midstream &
North America International Marketing
---------------------------------------------------
2002 2001 2002 2001 2002 2001
-------------------------------------------------------------------------
Revenues
Gross revenue $1,620 $ 932 $ 227 $ 41 $1,108 $ 235
Royalties and
production taxes 223 88 59 - - -
-------------------------------------------------------------------------
Revenues, net of
royalties and
production taxes 1,397 844 168 41 1,108 235

Expenses
Transportation and
selling 93 29 15 4 50 4
Operating 274 112 46 2 138 48
Purchased product - - - - 854 164
Depreciation, depletion
and amortization 481 185 62 15 25 4
-------------------------------------------------------------------------
Segment Income 549 518 45 20 41 15
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Corporate Consolidated
--------------------------------
2002 2001 2002 2001
-------------------------------------------------------------------------
Revenues
Gross revenue $ 3 $ 16 $2,958 $1,224
Royalties and production taxes - - 282 88
-------------------------------------------------------------------------
Revenues, net of royalties and
production taxes 3 16 2,676 1,136

Expenses
Transportation and selling - - 158 37
Operating - - 458 162
Purchased product - - 854 164
Depreciation, depletion
and amortization 12 11 580 215
-------------------------------------------------------------------------
Segment Income (9) 5 626 558
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Administrative 44 21 44 21
Interest, net 103 6 103 6
Foreign exchange (170) (26) (170) (26)
-------------------------------------------------------------------------
(23) 1 (23) 1
-------------------------------------------------------------------------
Net Earnings Before Income Tax 14 4 649 557
Income tax expense 155 112 155 112
-------------------------------------------------------------------------
Net Earnings from Continuing Operations (141) (108) 494 445
-------------------------------------------------------------------------
-------------------------------------------------------------------------


GEOGRAPHIC AND PRODUCT INFORMATION (FOR THE THREE MONTHS ENDED)

Onshore North America Produced Gas & NGL's
---------------------------
Canada U.S. Rockies
---------------------------
2002 2001 2002 2001
-------------------------------------------------------------------------
Revenues
Gross revenue $ 956 $ 687 $ 175 $ 24
Royalties and production taxes 132 40 42 10
-------------------------------------------------------------------------
Revenues, net of royalties and
production taxes 824 647 133 14
Expenses
Transportation and selling 57 24 25 -
Operating 107 44 15 3
-------------------------------------------------------------------------
Operating cashflow $ 660 $ 579 $ 93 $ 11
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Conventional Total Onshore
Crude Oil Syncrude North America
-----------------------------------------
2002 2001 2002 2001 2002 2001
-------------------------------------------------------------------------
Revenues
Gross revenue $ 398 $ 221 $ 91 $ - $1,620 $ 932
Royalties and production taxes 48 38 1 - 223 88
-------------------------------------------------------------------------
Revenues, net of royalties
and production taxes 350 183 90 - 1,397 844
Expenses
Transportation and selling 10 5 1 - 93 29
Operating 84 65 68 - 274 112
-------------------------------------------------------------------------
Operating cashflow $ 256 $ 113 $ 21 $ - $1,030 $ 703
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Offshore & International
Total
U.K. Other Offshore &
Ecuador North Sea Countries International
-------------------------------------------------------------------------
2002 2001 2002 2001 2002 2001 2002 2001
Revenues
Gross revenue $ 182 $ - $ 45 $ 41 $ - $ - $ 227 $ 41
Royalties and
production taxes 59 - - - - - 59 -
-------------------------------------------------------------------------
Revenues, net of
royalties and
production taxes 123 - 45 41 - - 168 41
Expenses
Transportation
and selling 10 - 5 4 - - 15 4
Operating 31 - 3 2 12 - 46 2
-------------------------------------------------------------------------
Operating
cashflow $ 82 $ - $ 37 $ 35 $ (12) $ - $ 107 $ 35
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Total Midstream
Midstream & Marketing Midstream Marketing & Marketing
-----------------------------------------
2002 2001 2002 2001 2002 2001
-------------------------------------------------------------------------
Revenues
Gross revenue $ 174 $ 56 $ 934 $ 179 $1,108 $ 235
Expenses
Transportation and selling - - 50 4 50 4
Operating 96 43 42 5 138 48
Purchased product 51 - 803 164 854 164
-------------------------------------------------------------------------
Operating cashflow $ 27 $ 13 $ 39 $ 6 $ 66 $ 19
-------------------------------------------------------------------------
-------------------------------------------------------------------------

($ millions)
RESULTS OF OPERATIONS (FOR THE SIX MONTHS ENDED)
Onshore Offshore & Midstream
North America International & Marketing
---------------------------------------------------
2002 2001 2002 2001 2002 2001
------------------------------------------------------------------------
Revenues
Gross revenue $ 2,217 $ 2,043 $ 271 $ 87 $ 1,600 $ 846
Royalties and
production taxes 291 182 59 - - -
------------------------------------------------------------------------
Revenues, net of
royalties and
production taxes 1,926 1,861 212 87 1,600 846

Expenses
Transportation
and selling 132 64 20 9 55 9
Operating 375 210 49 7 205 154
Purchased product - - - - 1,234 641
Depreciation, depletion
and amortization 671 330 74 33 31 7
------------------------------------------------------------------------
Segment Income $ 748 $ 1,257 $ 69 $ 38 $ 75 $ 35
------------------------------------------------------------------------
------------------------------------------------------------------------

Corporate Consolidated
---------------------------------
2002 2001 2002 2001
------------------------------------------------------------------------
Revenues
Gross revenue $ (1) $ 17 $ 4,087 $ 2,993
Royalties and production taxes - - 350 182
------------------------------------------------------------------------
Revenues, net of royalties
and production taxes (1) 17 3,737 2,811

Expenses
Transportation and selling - - 207 82
Operating - - 629 371
Purchased product - - 1,234 641
Depreciation, depletion
and amortization 18 19 794 389
------------------------------------------------------------------------
Segment Income (19) (2) 873 1,328
------------------------------------------------------------------------
------------------------------------------------------------------------
Administrative 61 41 61 41
Interest, net 130 19 130 19
Foreign exchange (180) (3) (180) (3)
------------------------------------------------------------------------
11 57 11 57
------------------------------------------------------------------------
Net Earnings Before Income Tax (30) (59) 862 1,271
Income tax expense 237 383 237 383
------------------------------------------------------------------------
Net Earnings from
Continuing Operations $ (267) $ (442) $ 625 $ 888
------------------------------------------------------------------------
------------------------------------------------------------------------


GEOGRAPHIC AND PRODUCT INFORMATION (FOR THE SIX MONTH ENDED)

Onshore North America Produced Gas & NGL's
---------------------------------
Canada U.S. Rockies
---------------------------------
2002 2001 2002 2001
------------------------------------------------------------------------
Revenues
Gross revenue $ 1,316 $ 1,539 $ 207 $ 63
Royalties and production taxes 160 94 49 25
------------------------------------------------------------------------
Revenues, net of royalties
and production taxes 1,156 1,445 158 38
Expenses
Transportation and selling 88 51 25 -
Operating 151 80 20 6
------------------------------------------------------------------------
Operating cashflow $ 917 $ 1,314 $ 113 $ 32
------------------------------------------------------------------------
------------------------------------------------------------------------

Conventional Total Onshore
Crude Oil Syncrude North America
---------------------------------------------------
2002 2001 2002 2001 2002 2001
------------------------------------------------------------------------
Revenues
Gross revenue $ 603 $ 441 $ 91 $ - $ 2,217 $ 2,043
Royalties and
production taxes 81 63 1 - 291 182
------------------------------------------------------------------------
Revenues, net of
royalties and
production taxes 522 378 90 - 1,926 1,861
Expenses
Transportation and
selling 18 13 1 - 132 64
Operating 136 124 68 - 375 210
------------------------------------------------------------------------
Operating cashflow $ 368 $ 241 $ 21 $ - $ 1,419 $ 1,587
------------------------------------------------------------------------
------------------------------------------------------------------------

Offshore & International Total
U.K. Other Offshore &
Ecuador North Sea Countries International
-------------------------------------------------------
2002 2001 2002 2001 2002 2001 2002 2001
------------------------------------------------------------------------
Revenues
Gross revenue $ 182 $ - $ 89 $ 87 $ - $ - $ 271 $ 87
Royalties and
production taxes 59 - - - - - 59 -
------------------------------------------------------------------------
Revenues, net of
royalties and
production
taxes 123 - 89 87 - - 212 87
Expenses
Transportation
and selling 10 - 10 9 - - 20 9
Operating 31 - 6 7 12 - 49 7
------------------------------------------------------------------------
Operating
cashflow $ 82 $ - $ 73 $ 71 $ (12) $ - $ 143 $ 71
------------------------------------------------------------------------
------------------------------------------------------------------------

Total Midstream
Midstream & Marketing Midstream Marketing & Marketing
---------------------------------------------------
2002 2001 2002 2001 2002 2001
------------------------------------------------------------------------
Revenues
Gross revenue $ 260 $ 170 $ 1,340 $ 676 $ 1,600 $ 846
Expenses
Transportation
and selling - - 55 9 55 9
Operating 157 145 48 9 205 154
Purchased product 51 - 1,183 641 1,234 641
------------------------------------------------------------------------
Operating cashflow $ 52 $ 25 $ 54 $ 17 $ 106 $ 42
------------------------------------------------------------------------
------------------------------------------------------------------------


CAPITAL EXPENDITURES
Three Months Six Months
Capital Capital
Expenditures Expenditures
---------------------------------
2002 2001 2002 2001
------------------------------------------------------------------------
Onshore North America $ 1,043 $ 302 $ 1,384 $ 606
Offshore & International 276 102 409 136
Midstream & Marketing 120 43 124 69
Corporate 7 7 10 20
------------------------------------------------------------------------
Total $ 1,446 $ 454 $ 1,927 $ 831
------------------------------------------------------------------------
------------------------------------------------------------------------

CAPITAL AND TOTAL ASSETS
As at
------------------------------------------------
Capital Assets Total Assets
------------------------------------------------
June 30, December 31, June 30, December 31,
2002 2001 2002 2001
------------------------------------------------------------------------
Onshore North America $ 18,207 $ 6,552 $ 19,820 $ 7,080
Offshore & International 2,753 1,018 3,016 1,111
Midstream & Marketing 968 426 1,490 817
Corporate (including
unallocated Goodwill) 212 166 3,370 1,064
Assets of Discontinued
Operations - - 1,783 728
------------------------------------------------------------------------
Total $ 22,140 $ 8,162 $ 29,479 $ 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
and Marketing segment. Accordingly, these operations have been accounted for
as discontinued operations.
On July 9, 2002, the Company announced that it plans 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 Express system. The financial results shown
below include tariff revenue of $23 million paid by the Company for services
on Express.
The following tables present the effect of the discontinued operations on
the consolidated financial statements:

<<
For the three months ended June 30
Merchant Midstream -
Energy Pipelines Total
---------------------------------------------------
Consolidated Statement of
Income ($ millions) 2002 2001 2002 2001 2002 2001
------------------------------------------------------------------------
Revenues $ 563 $ 1,045 $ 58 $ - $ 621 $ 1,045
------------------------------------------------------------------------
Expenses
Operating - - 20 - 20 -
Purchased product 580 1,013 - - 580 1,013
Administrative 8 8 - - 8 8
Interest, net - - 11 - 11 -
Foreign exchange - - (10) - (10) -
Depletion, depreciation
and amortization 1 1 11 - 12 1
Loss on
discontinuance 53 - - - 53 -
------------------------------------------------------------------------
642 1,022 32 - 674 1,022
------------------------------------------------------------------------
Net Earnings (Loss)
Before Income Tax (79) 23 26 - (53) 23
Income tax expense
(recovery) (28) 9 11 - (17) 9
------------------------------------------------------------------------
Net Earnings (Loss)
from Discontinued
Operations $ (51) $ 14 $ 15 $ - $ (36) $ 14
------------------------------------------------------------------------
------------------------------------------------------------------------

For the six months ended June 30
Merchant Midstream -
Energy Pipelines(*) Total
---------------------------------------------------
Consolidated Statement of
Income ($ millions) 2002 2001 2002 2001 2002 2001
------------------------------------------------------------------------
Revenues $ 1,309 $ 2,567 $ 58 $ - $ 1,367 $ 2,567
------------------------------------------------------------------------
Expenses
Operating - - 20 - 20 -
Purchased product 1,313 2,495 - - 1,313 2,495
Administrative 18 15 - - 18 15
Interest, net - - 11 - 11 -
Foreign exchange - - (10) - (10) -
Depletion, depreciation
and amortization 1 2 11 - 12 2
Loss on
discontinuance 53 - - - 53 -
------------------------------------------------------------------------
1,385 2,512 32 - 1,417 2,512
------------------------------------------------------------------------
Net Earnings (Loss)
Before Income Tax (76) 55 26 - (50) 55
Income tax expense
(recovery) (27) 21 11 - (16) 21
------------------------------------------------------------------------
Net Earnings from
(Loss) Discontinued
Operations $ (49) $ 34 $ 15 $ - $ (34) $ 34
------------------------------------------------------------------------
------------------------------------------------------------------------
(*) Reflects only three months of earnings as EnCana did not own the
pipelines until April 5, 2002.

As at June 30
Merchant Midstream -
Energy Pipelines Total
---------------------------------------------------
Consolidated Balance
Sheet ($ millions) 2002 2001 2002 2001 2002 2001
------------------------------------------------------------------------
Assets
Cash and cash
equivalents $ - $ - $ 66 $ - $ 66 $ -
Accounts receivable
and accrued revenue 338 1,314 44 - 382 1,314
Inventories - 9 1 - 1 9
------------------------------------------------------------------------
338 1,323 111 - 449 1,323
Capital assets, net - 8 807 - 807 8
Investments and
other assets - 17 417 - 417 17
------------------------------------------------------------------------
338 1,348 1,335 - 1,673 1,348
------------------------------------------------------------------------
Liabilities
Accounts payable and
accrued liabilities 240 1,202 68 - 308 1,202
Income tax payable - - 4 - 4 -
Current portion of
long-term debt - - 23 - 23 -
------------------------------------------------------------------------
240 1,202 95 - 335 1,202
Long-term debt - - 567 - 567 -
Future income taxes - - 163 - 163 -
------------------------------------------------------------------------
240 1,202 825 - 1,065 1,202
------------------------------------------------------------------------
Net Assets of
Discontinued
Operations $ 98 $ 146 $ 510 $ - $ 608 $ 146
------------------------------------------------------------------------
------------------------------------------------------------------------
>>

For comparative purposes, the following tables present the effect of only
the Merchant Energy Discontinued Operations on the Consolidated Financial
Statements for the years ended December 31. It does not include any financial
information related to Midstream - Pipelines as EnCana did not own the
pipelines being discontinued at that time.

<<
Year Ended
December 31
------------------
Consolidated Statement of Income ($ millions) 2001 2000
------------------------------------------------------------------------
Revenues $ 4,085(*) $ 3,025
------------------------------------------------------------------------
Expenses
Purchased product 3,983(*) 2,961
Administrative 43 26
Depletion, depreciation and amortization 4 3
------------------------------------------------------------------------
4,030 2,990
------------------------------------------------------------------------
Net Earnings Before Income Tax 55 35
Income tax expense 22 13
------------------------------------------------------------------------
Net Earnings from Discontinued Operations $ 33 $ 22
------------------------------------------------------------------------
------------------------------------------------------------------------
(*) 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.


As at December 31
------------------
Consolidated Balance Sheet ($ millions) 2001 2000
------------------------------------------------------------------------
Assets
Accounts receivable and accrued revenue $ 323 $ 699
Risk management assets 309 -
Inventories 70 2
------------------------------------------------------------------------
702 701
------------------------------------------------------------------------

Capital assets, net 9 3
Deferred charges and other assets 17 32
------------------------------------------------------------------------
728 736
------------------------------------------------------------------------
Liabilities
Accounts payable and accrued liabilities 306 631
Risk management liabilities 278 -
------------------------------------------------------------------------
584 631
Deferred credits and liabilities 2 3
------------------------------------------------------------------------
586 634
------------------------------------------------------------------------
Net Assets of Discontinued Operations $ 142 $ 102
------------------------------------------------------------------------
------------------------------------------------------------------------

Year Ended
December 31
---------------
Consolidated Statement of Cash Flows ($ millions) 2001 2000
------------------------------------------------------------------------
Operating Activities
Cash flow $ 47 $ 26
Net change in non-cash working capital (48) (2)
------------------------------------------------------------------------
$ (1) $ 24
------------------------------------------------------------------------
------------------------------------------------------------------------


6. Income Taxes
Three Months Six Months
Ended June 30 Ended June 30
---------------------------------
($ millions) 2002 2001 2002 2001
------------------------------------------------------------------------

Provision for Income Taxes:
Current
Canada $ 36 $ 136 $ 73 $ 324
United States 8 - 8 3
Ecuador 7 - 7 -
United Kingdom 5 2 8 5
Other - - - 1
------------------------------------------------------------------------
56 138 96 333
Future 99 (26) 141 50
------------------------------------------------------------------------
$ 155 $ 112 $ 237 $ 383
------------------------------------------------------------------------
------------------------------------------------------------------------


7. Long-Term Debt
As at As at
June 30 December 31
---------------------
($ millions) 2002 2001
------------------------------------------------------------------------

Canadian dollar denominated debt
Revolving credit and term loan borrowings $ 1,560 $ 37
Unsecured debentures, including capital securities 1,830 725
------------------------------------------------------------------------
3,390 762
------------------------------------------------------------------------

U.S. dollar denominated debt
U.S. unsecured senior notes 3,801 1,608
U.S. revolving credit and term loan borrowings 314 -
------------------------------------------------------------------------
4,115 1,608
------------------------------------------------------------------------
7,505 2,370
Increase in value of debt acquired 128 -
Current portion of long-term debt (108) (160)
------------------------------------------------------------------------
$ 7,525 $ 2,210
------------------------------------------------------------------------
------------------------------------------------------------------------
>>

Certain of the 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 these
debts of approximately $128 million is being amortized over the remaining life
of the outstanding debt acquired, approximately 15 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. For the six months ended June 30, 2002, the Company recorded a foreign
exchange gain of $180 million ($142 million after tax) related primarily to
the translation of U.S. dollar debt.

<<
8. Share Capital (millions)

June 30, 2002 December 31, 2001
-----------------------------------
Number Amount Number Amount
------------------------------------------------------------------------
Common shares outstanding,
beginning of period 254.9 $ 196 254.8 $ 148
Shares repurchased - - (0.2) -
Shares issued under option plans 2.9 69 1.9 48
Shares issued to AEC Shareholders
(note 3) 218.5 8,397 - -
Adjustments due to Canadian Pacific
Limited reorganization - - (1.6) -
------------------------------------------------------------------------
Common shares outstanding,
end of period 476.3 $ 8,662 254.9 196
------------------------------------------------------------------------
------------------------------------------------------------------------
>>

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 June 30, 2002:
<<
Weighted
Average
Share Exercise
Options Price ($)
------------------------------------------------------------------------
Outstanding, beginning of period 10.5 32.31
Granted under EnCana plan 10.9 48.33
Granted under AEC replacement plan 13.1 32.01
Granted under Directors' plan 0.1 48.04
Exercised (2.9) 24.26
Forfeited (0.2) 31.84
------------------------------------------------------------------------
Outstanding, end of period 31.5 38.53
------------------------------------------------------------------------
------------------------------------------------------------------------
Exercisable, end of period 20.5 33.32
------------------------------------------------------------------------
------------------------------------------------------------------------


Outstanding Options Exercisable Options
-------------------------------------------------------------
Weighted
Average Weighted Weighted
Range of Number of Remaining Average Number of Average
Exercise Options Contractual Exercise Options Exercise
Price ($) Outstanding Life (years) Price ($) Outstanding Price ($)
-------------------------------------------------------------------------
13.50 to 19.99 4.5 1.3 18.55 4.5 18.55
20.00 to 24.99 2.6 2.7 22.22 2.6 22.22
25.00 to 29.99 3.6 2.9 26.58 3.6 26.58
30.00 to 43.99 2.1 3.5 38.02 2.1 38.02
44.00 to 53.00 18.7 4.0 47.94 7.7 47.40
-------------------------------------------------------------------------
31.5 3.1 38.53 20.5 33.32
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>

The Company does not record compensation expense in the financial
statements for share options granted to employees and directors because there
is no intrinsic value at the date of grant. If the fair-value method had been
used, the Company's net earnings and net earnings per share would approximate
the following pro-forma amounts:
<<
Six Months
Ended June 30
---------------
($ millions, except per share amounts) 2002 2001
------------------------------------------------------------------------
Compensation Costs 50 10

Net Earnings
As reported 591 922
Pro forma 541 912

Net Earnings per Common Share
Basic
As reported 1.65 3.60
Pro forma 1.51 3.56
Diluted
As reported 1.62 3.52
Pro forma 1.48 3.49
------------------------------------------------------------------------
>>

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:
<<
Six Months
Ended June 30
---------------
2002 2001
------------------------------------------------------------------------
Risk free interest rate 4.46% 4.24%
Expected lives (years) 3.00 3.00
Expected volatility 0.35 0.35
Annual dividend per share $0.40 $0.40
------------------------------------------------------------------------


9. Per Share Amounts

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

Three Months Six Months
Ended June 30 Ended June 30
---------------------------------
2002 2001 2002 2001
------------------------------------------------------------------------
Weighted average Common Shares
outstanding - basic 461.1 255.9 358.2 255.6
Effect of dilutive securities 8.9 5.5 6.8 5.4
------------------------------------------------------------------------
Weighted average Common shares
outstanding - diluted 470.0 261.4 365.0 261.0
------------------------------------------------------------------------
------------------------------------------------------------------------

Net earnings per common share calculations include the impact of the
Distributions on Preferred Securities, net of tax for the three months of
$1 million (three months 2001 - $1 million) and for the year to date
$1 million (year to date 2001 - $2 million).


10. Financial Instruments

Unrecognized gains (losses) on risk management activities:

($ millions) June 30, 2002
------------------------------------------------------------------------
Natural gas 194
Crude oil (13)
Gas Storage (2)
Foreign currency (102)
Interest rates 60
Preferred securities 6
------------------------------------------------------------------------
143
------------------------------------------------------------------------
------------------------------------------------------------------------
>>

Information with respect to crude oil, currency and interest rate hedge
contracts 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. 11. Reclassification Certain information provided for prior periods has been reclassified to
conform to the presentation adopted in 2002.

For further information: on EnCana Corporation and Alberta Energy Company Ltd., is available on the company's Web site, www.encana.com, or by contacting: Investor contact: EnCana Corporate Development, Sheila McIntosh, Senior Vice-President, Investor Relations, (403) 290-2194; Greg Kist, Manager, Investor Relations, (403) 645-4737; Media contact: Alan Boras, Manager, Media Relations, (403) 266-8300 or (403) 645-4754

ECA stock price

TSX $15.12 Can 0.200

NYSE $11.85 USD 0.160

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