EnCana earns $186 million and generates $765 million of cash flow on a pro forma basis in the first quarter of 2002

Pro forma natural gas sales up 21 percent, exploration success continues, high-quality gas reserves addition in U.S. Rockies 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, April 25 /CNW/ - EnCana Corporation (TSE & NYSE: ECA), created
April 5, 2002 by the merger of Alberta Energy Company Ltd. (AEC) and
PanCanadian Energy Corporation (PanCanadian), today reported $186 million of
earnings and $765 million of cash flow on a pro forma basis during the first
quarter of 2002.
All references to earnings, cash flow, production, sales, proceeds of
asset sales and other information not specifically contained in the EnCana
(formerly PanCanadian) and AEC Management's Discussion and Analysis and
interim unaudited consolidated financial statements that are attached to this
press release are presented on a pro forma basis as if the merger of
PanCanadian and AEC had occurred effective January 1, 2002.

Strong pro forma operating results
Oil and gas sales increased by 12 percent to 700,846 barrels of oil
equivalent per day in the first quarter of 2002, compared to the first quarter
of 2001. Natural gas sales averaged 2.7 billion cubic feet per day, up
21 percent over the same period in 2001. Oil and natural gas liquids sales
averaged 246,846 barrels per day, down approximately 1 percent. Operating and
general and administrative costs averaged $4.61 per barrel of oil equivalent
in the quarter.
"These strong operating results are a testament to the employees of
EnCana who, throughout the demanding merger process, remained focussed on
their jobs, enabling the Company to grow production and maintain cost
control," said Gwyn Morgan, EnCana's President & Chief Executive Officer. "In
the quarter, we were also able to advance a number of important growth
initiatives: a significant discovery at our Tahiti prospect in the deepwater
Gulf of Mexico, promising appraisal wells at the Buzzard discovery in the U.K.
central North Sea, filing of the regulatory applications for development of
the Deep Panuke gas field off Nova Scotia, continued development success at
the Ladyfern field in northeast British Columbia and Canada's first reported
sales of coalbed methane production. Adding to this outstanding internal
progress, we made a timely acquisition that will strengthen our position in
one of our key growth platforms - the U.S. Rockies. Last week, we announced a
proposed acquisition of approximately 500 billion cubic feet of long life,
natural gas equivalent reserves in northwest Colorado," Morgan said.
"The EnCana team used every one of the sixty-eight days that it took to
complete the merger to get EnCana ready to hit the ground running. The key
integration decisions have already been made and our new teams are working
together. Our production numbers are on target and we're making progress
towards achieving our targeted annual synergies of one-quarter billion dollars
in operating and general and administrative expenses and one-quarter billion
dollars in capital investment," Morgan said.

Pro forma financial results impacted by price declines
Lower commodity prices, particularly natural gas prices, impacted first
quarter financial results. The average industry natural gas price at AECO for
the first quarter of 2002 was $3.49 per thousand cubic feet, compared to
$11.37 per thousand cubic feet in the same period a year earlier. The average
West Texas Intermediate crude oil benchmark price was US$21.64 per barrel,
down 25 percent from the same quarter in 2001. Heavy oil differentials
improved as a result of lower industry heavy oil production levels and an
improved Gulf Coast heavy oil market. Since the end of 2001, oil and gas
prices have strengthened due to indications of an improving North American
economy, OPEC restraint and political factors such as tensions in the Middle
East.
For the three months ended March 31, 2002, EnCana's pro forma highlights
include:
- Net income of $186 million; net income attributable to common
shareholders of $175 million, or $0.36 per common share diluted;
- Cash flow of $765 million, or $1.58 per common share diluted;
- Natural gas sales of 2,724 million cubic feet per day, up 21 percent
from the first quarter of 2001, with the average realized price
declining 64 percent to $3.31 per thousand cubic feet;
- Crude oil and natural gas liquids sales of 246,846 barrels per day,
down 1 percent from the first quarter of 2001, with the average
realized price declining 10 percent to $25.37 per barrel;
- Capital investment, net of proceeds on asset sales, of $1,306 million;
and
- A strong financial position with debt to capitalization of 39 percent
(preferred securities included as debt).

"During the first quarter, every one of our six growth platforms, from
Western Canada to the U.K. North Sea, either achieved strong production growth
or completed important objectives towards the development of long-term,
high-impact growth initiatives. By 2005, EnCana is targeting production growth
of about 55 percent to more than 1.1 million barrels of oil equivalent per
day," Morgan said. "EnCana possesses the scope, scale and reach, plus the
financial strength, to deliver enhanced value for shareholders, and our teams
are focussed on doing just that."

Important Notice: Readers are cautioned that 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.

<<
EnCana pro forma
Financial Highlights EnCana
(as at and for the three months ending March 31, 2002) Pro Forma
($ millions, except per share amounts)
--------------------------------------------------------------------
Revenues, net of royalties and production taxes 2,080

Cash Flow from operations 765
Per share - diluted 1.58

Net earnings 186
Per share - diluted 0.36

Capital investment, excluding dispositions 1,345

Total assets 28,946
Long-term debt, including current portion 7,704
Preferred securities 586
Shareholders' equity 13,033

Debt-to-capitalization ratio 39%
(adjusted for working capital and including
preferred securities as debt)

--------------------------------------------------------------------
Common shares
Outstanding March 31, 2002 (millions) 474.1
Weighted average diluted (millions) 483.5
--------------------------------------------------------------------


--------------------------------------------------------------------
Operating Highlights Q1 Q1
2002 2001
--------------------------------------------------------------------
Sales
Total barrels of oil equivalent per day 700,846 624,124

Natural gas (million cubic feet per day) 2,724 2,250

Total liquids (barrels per day) 246,846 249,124
North America
Conventional oil and NGLs 163,635 154,211
Syncrude 31,548 32,319
International 51,663 62,594
Prices
North American gas price
($ per thousand cubic feet) 3.31 9.07

North American conventional oil price
($ per barrel)
Light/medium 26.48 29.71
Heavy 21.63 15.61
Syncrude ($ per barrel) 34.86 43.17
International crude oil ($ per barrel)
Ecuador 22.07 24.71
U.K. 30.85 41.26
Natural gas liquids ($ per barrel) 22.45 40.06
Total liquids ($ per barrel) 25.37 28.17
--------------------------------------------------------------------
>>
EnCana corporate developments

EnCana Corporation created in less than 10 weeks
In separate meetings on April 4, 2002, AEC common shareholders and
optionholders and PanCanadian common shareholders voted strongly in favour of
the merger - 91 percent and 81 percent, respectively, of the votes cast. At
the PanCanadian meeting, 84 percent of the PanCanadian common shareholders
voting cast votes in favour of the name change to EnCana Corporation. On
April 5, the morning after the meetings, the Court of Queen's Bench of Alberta
approved the transaction and the historic merger was completed later that day,
68 days after the two companies announced their intention to merge.
EnCana's transition teams have made considerable progress in integrating
the two companies. The new organizational structure, staffing decisions and
assignments have largely been implemented.

Dividends
PanCanadian common shareholders of record as of March 15, 2002 were paid
a quarterly dividend of 10 cents per share on March 29, 2002. Recognizing that
AEC's annual dividend of 60 cents per share would normally be payable in June,
after the expected completion of the merger, AEC's Board of Directors declared
a dividend of 45 cents per share which was paid on March 28, 2002 to AEC
common shareholders of record as of March 7, 2002.
The Board of Directors of EnCana has declared a quarterly dividend of ten
cents (10 cents) per share payable on June 28, 2002 to common shareholders of
record as of June 14, 2002.

Energy Services
As part of EnCana's strategic review of its operations, the Company has
decided to exit its Houston-based merchant energy operations which are
included in the Company's Midstream and Marketing segment of its business.
Various exit alternatives are being evaluated with a view to maximizing the
value to EnCana. As a result of this strategic decision, the Houston-based
merchant energy operations are being accounted for as discontinued operations
in the Company's interim financial statements. The Company will honour all
existing contracts and commitments to the Company's customers.
Unrelated to the decision to discontinue its Houston-based merchant
energy operations, the Company has also determined, in respect of certain
sales and purchases of natural gas in its U.S. marketing subsidiary recorded
in 2001, that it is appropriate to treat revenue and expenses in respect of
those contracts on a "net" basis, rather than on a gross basis as Revenue and
Expenses-Direct. This treatment has no effect on the previously reported net
income or cash flow of the Company and its balance sheet remains unchanged.
For further details on both of these developments, see Note 3 of the
EnCana interim unaudited consolidated financial statements for the period
ended March 31, 2002.

EnCana operational highlights

Onshore North America

Strong organic growth in natural gas
EnCana's sales of produced natural gas in North America during the first
quarter, which includes the impact of 161 million cubic feet per day of gas
withdrawals from storage, increased to 2,713 million cubic feet per day, up
21 percent on a pro forma basis over the same period last year. The increase
in sales came primarily from the U.S. Rockies and the Ladyfern and Greater
Sierra regions of northeast British Columbia. The Onshore North America
division drilled more than 1,000 net wells during the first quarter.

High-quality natural gas assets addition in the U.S. Rockies
On April 17, EnCana announced that its U.S. subsidiaries had entered into
an acquisition agreement, for approximately C$461 million (US$292 million),
which expands production, reserves and land holdings in the U.S. Rockies. The
Company has agreed to purchase approximately 500 billion cubic feet of
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. The acquisition also includes a gathering system and a gas plant.
These properties are currently producing an average of 38 million cubic feet
of gas equivalent per day. EnCana plans to drill about 50 wells on the
acquired lands and increase daily production to about 55 million cubic feet of
gas equivalent by the end of 2002. EnCana has achieved great success applying
its tight gas development expertise to multi-zone formations of this nature
and expects to triple production from these properties in the next three
years. The transaction is subject to regulatory approvals and certain other
conditions, and is expected to close at the end of May 2002.

Greater Sierra production rising
In the Greater Sierra area of northeast B.C., EnCana drilled 45 wells
during its winter program. The Company expects daily production to average
about 150 million cubic feet of gas this year. EnCana has clearly identified
substantial growth from its extensive lands in the region and is forecasting
production to more than double by 2005.

Ladyfern gas development
At the Ladyfern gas field, located in northeast British Columbia, the
Company successfully drilled seven wells, including six development wells and
one step out well. Current production from this area is approximately
140 million cubic feet per day. Results of two additional exploration wells
are under evaluation.

EnCana's coalbed methane pilot projects both showing promise
In January 2002, the EnCana and MGV Energy Inc. joint venture, operating
on the Palliser Block in southern Alberta, initiated the first significant
coalbed methane gas sales reported in Canada. Six wells are producing at
stable flow rates ranging from 30,000 to 250,000 cubic feet of natural gas per
day per well. Long-term production tests are in progress to verify reserve
estimates and stabilize production rates. Initial test results to date
indicate that net recoverable reserves on the joint venture lands within the
Palliser Block could be approximately one to two billion cubic feet of natural
gas per section, with upside from a completion-optimization program now
underway. The Company anticipates being in a position to make decisions
regarding commercial development by mid 2002.
In southeastern B.C., EnCana continued testing and evaluating the coalbed
methane potential in the Elk Valley. The first pilot project has had 10 wells
on test, dewatering coals since late 2001, with encouraging results to date. A
decision on advancing to an extended pilot project or commercial scale project
is expected before year-end.

Oil and natural gas liquids production and sales rise
EnCana's sales of oil and natural gas liquids, which includes
conventional crude oil, Syncrude production and natural gas liquids, averaged
195,183 barrels per day from the Onshore North America division. On a
comparative basis, the average daily sales volume of liquids was up 5 percent
from the first quarter of 2001.

SAGD production ramping up
First quarter daily production from the Foster Creek steam-assisted
gravity drainage oil project averaged 11,100 barrels and is currently about
15,000 barrels per day. Production is expected to reach 20,000 barrels per day
in the second quarter of 2002. EnCana's Christina Lake Phase 1 project is
currently being commissioned. Steam injection will begin at Christina Lake in
May 2002, with first production expected in the third quarter of 2002.

Weyburn production exceeds expectations
First quarter production averaged 13,200 barrels per day, up 22 percent
from the first quarter of 2001. Incremental production from this Saskatchewan
enhanced oil recovery project now amounts to approximately 2,900 barrels per
day of the Weyburn Unit oil production. In early February, the first of two
gas recycle compressors started re-injecting produced CO(2) gas into the
reservoir.

Syncrude cost performance improves
EnCana's share of Syncrude production for the first quarter of 2002
averaged 31,548 barrels per day, down 2 percent from the same period last year
due primarily to unplanned maintenance. Unit operating costs were down by
$2.75 per barrel, or 13 percent, to average $17.73 per barrel in the first
quarter of 2002. This was due largely to a reduction in natural gas prices in
the past year.

Offshore & International Operations

Ecuador
Oil production from Ecuador averaged 50,351 barrels per day in the first
quarter of 2002, down 7 percent due primarily to reduction of the effective
allowable on the SOTE pipeline in the quarter. Daily crude oil sales averaged
38,774 barrels, down from 51,512 barrels in the first quarter of 2001, due to
the scheduling of tanker shipments leaving port. The first quarter production
that remained in inventory at quarter end will be sold during the second
quarter. Ecuador volumes are constrained by available pipeline transportation.
EnCana plans to double its Ecuador production to 100,000 barrels per day in
mid 2003 following completion of the OCP Pipeline, which is one-third
complete.

East Coast of Canada - development of Deep Panuke advanced
In March 2002, regulatory applications were filed with the Canada-Nova
Scotia Offshore Petroleum Board and the National Energy Board for development
of the Company's $1.1 billion Deep Panuke natural gas project off the coast of
Nova Scotia. Regulatory hearings for the project are expected to begin in the
fall of 2002, with a decision in the first quarter of 2003. EnCana will decide
whether to proceed with construction of Deep Panuke facilities once regulatory
approval is received. The project 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. Based on current assumptions, commercial
production could begin in 2005. The project is estimated to recover reserves
of natural gas approaching one trillion cubic feet over an expected 11-year
production life of the field.

Offshore & New Ventures Exploration

Gulf of Mexico - promising discovery
In early April 2002, EnCana and its partners announced a significant
discovery at the Tahiti prospect located in Green Canyon Block 640,
approximately 190 miles southwest of New Orleans in the deepwater Gulf of
Mexico. The Tahiti No. 1 well is situated in approximately 4,000 feet of water
and was drilled to a measured depth of 28,411 feet. Results from the
exploratory well indicate the presence of high-quality reservoir sand with
total net pay of more than 400 feet. EnCana has a 25-percent working interest
with ChevronTexaco as the operator. 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 prolific Mississippi Fanfold Belt in the
Gulf of Mexico. Completion of the four-well program is expected by early 2003.

U.K. North Sea - positive results from appraisal wells
In April 2002, EnCana reported the results of two appraisal wells, which
verified the anticipated extensions of the Buzzard oil discovery, located in
the U.K. central North Sea. Additional appraisal drilling is underway on
Buzzard. Results from these two wells are expected in May.

Scotian Shelf deep water exploration
In the first quarter of 2002, the Company participated in the drilling of
the Annapolis B-24 deepwater exploratory well, located 350 kilometres south of
Halifax, Nova Scotia in 1,740 metres of water. Drilling of the well was
suspended in late March due to a gas influx that occurred at an intermediate
well depth of 3,500 metres. Following a detailed analysis of the event and the
condition of the well bore, the participants plugged and abandoned the well
for mechanical reasons. The participants have started to redrill the Annapolis
prospect from a location that is about 500 metres northeast of the original
wellbore.

Midstream and Marketing

Express Pipeline System
During the first quarter, Express pipeline shipments increased 2 percent
over the first quarter of 2001, averaging 155,600 barrels of oil per day to
U.S. Rocky Mountain and Midwest markets. EnCana continues to evaluate
expansion opportunities, which will be linked to market demand for shipping
Canadian crude oil to the U.S.

Financial Strength
On a pro forma basis, EnCana possesses a strong financial position. The
Company's debt-to-capitalization ratio was 39:61 (preferred securities
included as debt). Total first quarter capital investment was $1,345 million,
excluding dispositions. Dispositions were $39 million, bringing net capital
investment to $1,306 million. EnCana recently received its first long-term
debt rating, following the merger, in Canada by Dominion Bond Rating Service.
The rating of A(low) confirms EnCana's position as a strong investment grade
issuer in the Canadian market.

-----------------------------------------------------------------------
IMPORTANT NOTICE
This news release includes three attachments, which are included in the
newswire version and available on the EnCana Web site: www.encana.com.

The attachments are:
- Attachment 1
EnCana Corporation
Pro Forma Consolidated Financial Statements, Q1, 2002
- Attachment 2
EnCana Corporation (formerly PanCanadian Energy Corporation)
Interim Unaudited Consolidated Financial Statements
and Management's Discussion and Analysis, Q1, 2002
- Attachment 3
Alberta Energy Company Ltd.
Interim Unaudited Consolidated Financial Statements
and Management's Discussion and Analysis, Q1, 2002

All of these documents are filed on Sedar and posted on www.sedar.com
-----------------------------------------------------------------------



-----------------------------------------------------------------------

CONFERENCE CALL TODAY

EnCana Corporation will host a conference call today, Thursday, April 25,
2002 starting at 11 a.m., Mountain Time (1 p.m. Eastern Time) to discuss
EnCana's pro forma first quarter 2002 financial and operating results.

To participate in this call, please dial 416-640-1907 approximately 10
minutes prior to the conference call. An archived recording of the call
will be available from about midnight April 25, 2002 until May 2, 2002 by
dialling 416-640-1917 and entering pass code 184780 followed by the pound
key.

A live audio Web cast of the conference call also will be available at
EnCana's Web site, www.encana.com, under Investor Relations.
-----------------------------------------------------------------------

EnCana is the largest North American based independent oil and gas
company with an enterprise value of approximately C$30 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-of-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 the assets being acquired under the
proposed acquisition of assets in the U.S. Rockies; the anticipated date by
which EnCana will have exited its Houston-based merchant energy operations;
projected increases in daily production of oil, natural gas and natural gas
liquids to 2005; plans to drill additional wells to increase production;
potential exploration, the anticipated closing date of the proposed
transaction to acquire the assets in the U.S. Rockies that are described in
this press release, the potential success of certain projects such as the
coalbed methane projects and the other exploratory wells in the Gulf of Mexico
and the 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 businesses of AEC and PanCanadian
will not be successfully integrated and that the anticipated synergies 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.

FOR FURTHER INFORMATION:

Investor contact: Media contact:
Sheila McIntosh Alan Boras
Senior Vice-President, Investor Relations (403) 266-8300
(403) 290-2194
Greg Kist
(403) 266-8495


EnCana Corporation
Selected Financial and Operating Information

The following table sets out certain unaudited financial and operating
information for AEC and PanCanadian, as well as unaudited pro forma financial
information for EnCana after giving effect to the Merger and certain other
adjustments, as at and for the three months ended March 31, 2002. The
following information should be read in conjunction with the unaudited Pro
Forma Consolidated Financial Statements of EnCana as at and for the periods
ended March 31, 2002 and December 31, 2001.

EnCana
AEC PanCanadian Pro Forma
---------- ----------- ----------
Financial Information ($ millions, except per share amounts)

Revenue, net of royalties and
production taxes $ 1,226 $ 1,062 $ 2,080

Net Earnings 72 133 186
Per Share - Diluted 0.37 0.51 0.36

Cash Flow 406 389 765
Per Share - Diluted 2.58 1.48 1.58

Common Shares
Outstanding March 31, 2002 148.3 255.7 474.1
Weighted Average Diluted 157.5 261.1 483.5

Total Assets 14,700 9,920 28,946
Long-term Debt,
including Current Portion 4,895 2,288 7,704
Preferred Securities 855 126 586
Shareholders' Equity 5,948 4,105 13,033

Capital Expenditures, excluding
acquisitions and dispositions
Upstream 852 478 1,330
Midstream 11 4 15
---------- ---------- ----------
Total 863 482 1,345

Debt-to-Capitalization 52% 37% 39%
(adjusted for working capital and including preferred
securities as debt)
EnCana 2001
AEC PanCanadian Pro Forma Pro Forma
---------- ----------- --------- ---------
Operating Information

Sales Volumes

Natural Gas (mmcf/d)
North America
Western Canada 1,346 1,002 2,348 2,012
US Rockies 293 72 365 230
---------- ---------- ---------- ----------
1,639 1,074 2,713 2,242

International - U.K. - 11 11 8
---------- ---------- ---------- ----------
Total produced gas sales 1,639 1,085 2,724 2,250
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------

Oil and Natural Gas Liquids (bbls/d)
North America
Conventional
Light and Medium Oil 4,339 68,216 72,555 73,395
Heavy Oil 46,765 22,081 68,846 62,368
Natural Gas Liquids 8,559 13,675 22,234 18,448
---------- ---------- ---------- ----------
59,663 103,972 163,635 154,211
Syncrude 31,548 - 31,548 32,319
---------- ---------- ---------- ----------
91,211 103,972 195,183 186,530
---------- ---------- ---------- ----------
International
Ecuador 38,774 - 38,774 51,512
U.K. - 12,889 12,889 11,012
Other - - - 70
---------- ---------- ---------- ----------
38,774 12,889 51,663 62,594
---------- ---------- ---------- ----------
Total 129,985 116,861 246,846 249,124
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------

Total BOE/D 403,152 297,694 700,846 624,124
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------

Average Realized Sales Prices
Natural Gas (per
thousand cubic feet) 3.23 3.44 3.31 9.07
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------

Oil (per barrel)
North America
Conventional
Light/medium 31.09 26.19 26.48 29.71
Heavy 22.05 20.74 21.63 15.61
Syncrude 34.86 - 34.86 43.17
International
Ecuador 22.07 - 22.07 24.71
U.K. - 30.85 30.85 41.26
Natural Gas Liquids
(per barrel) 27.49 19.17 22.45 40.06
Total Liquids
(per barrel) 25.82 24.85 25.37 28.17

Operating Costs +
G&A per BOE 4.54 4.70 4.61
(excluding Syncrude)



Attachment 1

EnCana Corporation
(formerly PanCanadian Energy Corporation)
Pro Forma Consolidated Financial Statements
(Unaudited)
March 31, 2002


EnCana Corporation

Pro Forma
Consolidated Statement of Earnings
(Unaudited)

-------------------------------------------------------------------------
($ millions, except per share amounts)

PanCanadian AEC
3 Months 3 Months
Ended Ended Pro Forma EnCana
March 31, March 31, Adjustments Pro Forma
2002 2002 Note 3 Note 4 Consolidated
-------------------------------------------------------------------------
Revenues, net of
royalties and
production taxes
Upstream $ 532 $ 835 $ (141)(b)(i) $ - $ 1,248
22 (b)(ii)
Midstream and
Marketing 520 391 (238)(a) - 836
141 (b)(i)
22 (b)(ii)
Other 10 - (4)(b)(iv) - (4)
(10)(b)(v)
-------------------------------------------------------------------------
1,062 1,226 (208) - 2,080
Expenses
Transportation
and selling - 79 73 (b)(ii) - 152
Direct 577 - (577)(b)(iii) - -
Operating - 216 165 (b)(iii) - 381
Cost of product
purchased - 406 (213)(a) - 576
(29)(b)(ii)
412 (b)(iii)
General and
administrative 26 24 - - 50
Interest, net 32 72 (4)(b)(iv) 9 (e) 109
Foreign exchange - - (10)(b)(v) - (10)
Depreciation,
depletion and
amortization 214 315 - - 529
-------------------------------------------------------------------------
Earnings Before
the Undernoted 213 114 (25) (9) 293
Income tax expense
(recovery) 82 42 (11)(a) (4)(e) 109
-------------------------------------------------------------------------
Net Earnings from
Continuing
Operations 131 72 (14) (5) 184
Net Earnings from
Discontinued
Operations 2 - - - 2
-------------------------------------------------------------------------
Net Earnings 133 72 (14) (5) 186
Distributions on
preferred
securities,
net of tax - 16 - (5)(e) 11
-------------------------------------------------------------------------
Net Earnings
Attributable to
Common
Shareholders $ 133 $ 56 $ (14) $ - $ 175
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Earnings per
Common Share
Continuing Operations
Basic $ 0.51 $ 0.38 $ 0.37
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Diluted $ 0.51 $ 0.37 $ 0.36
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Net Earnings
Basic $ 0.52 $ 0.38 $ 0.37
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Diluted $ 0.51 $ 0.37 $ 0.36
-------------------------------------------------------------------------
-------------------------------------------------------------------------

EnCana Corporation
Pro Forma
Consolidated Balance Sheet
(Unaudited)

-------------------------------------------------------------------------
($ millions) PanCanadian AEC
As at As at Pro Forma EnCana
March 31, March 31, Adjustments Pro Forma
2002 2002 Note 3 Note 4 Consolidated
-------------------------------------------------------------------------
Assets
Current Assets
Cash and cash
equivalents $ 519 $ 86 $ - $ - $ 605
Accounts receivable
and accrued
revenue, net 443 1,051 - - 1,494
Risk management
assets 97 - 169(a) - 266
Inventories 81 368 50(a) - 499
-------------------------------------------------------------------------
1,140 1,505 219 - 2,864
Capital Assets,
net 8,448 12,389 - 1,382 (a) 22,219
Investments and
Other Assets 242 806 - - 1,048
Net assets of
Discontinued
Operations 90 - - - 90
Goodwill - - - 2,725 (a) 2,725
-------------------------------------------------------------------------
$9,920 $14,700 $ 219 $4,107 $28,946
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Liabilities and
Shareholders' Equity
Current Liabilities
Accounts payable
and accrued
liabilities $ 473 $ 1,226 $ - $ 150 (a) $ 1,849
Income taxes
payable 509 32 - - 541
Risk management
liabilities 91 - 159 (a) - 250
Current portion
of other
liabilities 33 - - - 33
Current portion
of long-term debt 193 24 - - 217
-------------------------------------------------------------------------
1,299 1,282 159 150 2,890
Long-Term Debt 2,095 4,290 - 61 (a) 6,895
449 (e)
Project Financing
Debt - 581 - 11 (a) 592
Other Liabilities 320 193 - - 513
Future Income
Taxes 2,101 2,406 26 (a) 490 (a) 5,023
-------------------------------------------------------------------------
5,815 8,752 185 1,161 15,913
-------------------------------------------------------------------------
Shareholders' Equity
Preferred
securities 126 855 - 54 (a) 586
(449)(e)
Share capital 214 3,074 - (3,074)(a) 8,682
8,468 (a)
Paid in surplus 27 - - 27
Retained
earnings 3,738 1,762 34 (a) (1,796)(a) 3,738
Foreign currency
translation
adjustment - 257 - (257)(a) -
-------------------------------------------------------------------------
4,105 5,948 34 2,946 13,033
-------------------------------------------------------------------------
$9,920 $14,700 $ 219 $ 4,107 $28,946
-------------------------------------------------------------------------
-------------------------------------------------------------------------

EnCana Corporation
Pro Forma
Consolidated Statement of Cash Flow from Operations
(Unaudited)

-------------------------------------------------------------------------
($ millions, except per share amounts)

PanCanadian AEC
3 Months 3 Months
Ended Ended Pro Forma EnCana
March 31, March 31, Adjustments Pro Forma
2002 2002 Note 3 Note 4 Consolidated
-------------------------------------------------------------------------

Operating Activities
Net earnings
from continuing
operations $ 131 $ 72 $ (14) $ (5)(e) $ 184
Depreciation,
depletion and
amortization 214 315 - 529
Future income
taxes 42 16 (11)(a) - 47
Other - 3 - - 3
-------------------------------------------------------------------------
Cash Flow from
Continuing
Operations 387 406 (25) (5) 763
Cash Flow from
Discontinued
Operations 2 - - - 2
-------------------------------------------------------------------------
Cash Flow 389 406 (25) (5) 765
Net change in non-cash
working capital
from continuing
operations (268) (244) (60)(a) 150 (a) (422)
Net change in non-cash
working capital
from discontinued
operations 53 - - - 53
-------------------------------------------------------------------------
174 162 (85) 145 396
-------------------------------------------------------------------------
Cash Flow per Common
Share - Continuing
Operations
Basic $ 1.52 $ 2.75 $ 1.61
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Diluted $ 1.48 $ 2.58 $ 1.58
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Cash Flow per
Common Share
Basic $ 1.52 $ 2.75 $ 1.61
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Diluted $ 1.48 $ 2.58 $ 1.58
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>

EnCana Corporation
(formerly PanCanadian Energy Corporation)
Notes to Pro Forma Consolidated Financial Statements
March 31, 2002
(Unaudited)

1. Basis of Presentation

These unaudited Pro Forma Consolidated Financial Statements have been
prepared for information purposes and are prepared on a basis consistent with
the Pro Forma Consolidated Financial Statements included in the Joint
Information Circular concerning the merger of Alberta Energy Company Ltd.
(AEC) and PanCanadian Energy Corporation (PanCanadian). All pro forma
adjustments related to the preliminary purchase price allocation have been
based upon the estimated fair values determined in preparing the December 31,
2001 Pro Forma Consolidated Financial Statements with no update to March 31,
2002. All pro forma adjustments are consistent with the adjustments made to
the December 31, 2001 Pro Forma Consolidated Financial Statements, unless no
longer applicable.
These unaudited Pro Forma Consolidated Financial Statements have been
prepared from:

(a) PanCanadian's unaudited consolidated financial statements for the
three months ended March 31, 2002

(b) AEC's unaudited consolidated financial statements for the three
months ended March 31, 2002.

The unaudited Pro Forma Consolidated Balance Sheet gives effect to the
transaction described in Note 4 as if it had occurred on March 31, 2002. The
unaudited Pro Forma Consolidated Statements of Earnings and Cash Flow from
Operations give effect to the transaction as if it occurred on January 1,
2002.
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.
These unaudited Pro Forma Consolidated Financial Statements should be
read in conjunction with the consolidated financial statements of PanCanadian
and AEC.

2. Principles of Consolidation

These unaudited Pro Forma Consolidated Financial Statements have been
prepared on the basis that PanCanadian will account for the transaction as a
purchase of AEC using the purchase method of accounting. Accordingly, the
assets and liabilities of AEC will be recorded at their estimated fair value.
In completing the transaction, PanCanadian will issue 1.472 Common Shares
for each issued and outstanding Common Share of AEC.

3. Pro Forma Accounting and Presentation Adjustments and Assumptions

PanCanadian and AEC prepare their consolidated financial statements using
similar accounting policies and presentation with the exception of the items
noted below. The following accounting policy and financial statement
presentation adjustments have been made to match PanCanadian and AEC.

(a) Mark-to-Market Accounting for Midstream and Marketing Activities.
PanCanadian accounts for its Midstream and Marketing activities using
mark-to-market accounting. Certain of AEC's activities related to
Midstream and Marketing, specifically purchased gas marketing and gas
storage optimization activities, have been restated to a mark-to-
market basis of accounting.

(b) Financial Statement Presentation Adjustments

(i) To be consistent with PanCanadian's presentation, revenues
associated with AEC's purchased gas activity have been
reclassified from Upstream revenue.

(ii) To be consistent with AEC's presentation, PanCanadian's
Transportation and selling expenses have been reclassified from
Upstream and Midstream and Marketing revenues.

(iii) To be consistent with AEC's presentation of expenses,
PanCanadian's Operating expenses and Cost of product purchased
have been reclassified from Direct expenses.

(iv) To be consistent with AEC's presentation, PanCanadian's
interest revenue has been reclassified from Other revenue

(v) To be consistent with AEC's presentation, PanCanadian's net
foreign exchange gain has been reclassified from Other revenue.

4. Pro Forma Acquisition Adjustments and Assumptions

(a) The purchase of AEC for aggregate consideration of $8,618 million
comprising 218.4 million Common Shares of PanCanadian based on the
exchange ratio of 1.472 PanCanadian Common Shares for each AEC Common
Share. The estimated fair values are as at December 31, 2001 unless
otherwise stated.
<<
Calculation and preliminary allocation of purchase price:
$ Million
PanCanadian Common Shares issued to AEC
shareholders (million) 218.4
Price of PanCanadian Common Shares
($ per Common Share) 38.43
Value of PanCanadian Common Shares issued $ 8,391
Fair value of AEC Share Options exchanged for Share Options
of EnCana Corporation 77
Transaction costs 150
-------
Total Purchase Price 8,618
Plus: Fair value of liabilities assumed by PanCanadian
Current liabilities 1,441
Long-term debt 4,351
Project financing debt 592
Preferred securities 423
Capital securities 486
Other non-current liabilities 193
Future income taxes 2,922
-------
Total Purchase Price and Liabilities assumed $19,026
-------
-------

Fair value of assets acquired:
Current assets $ 1,724
Capital assets 13,771
Other non-current assets 806
Goodwill 2,725
-------
Total fair value of assets acquired $19,026
>> -------

(b) The number of issued and outstanding AEC Common Shares on the date of
the transaction has been assumed to be 148.3 million, taking into
account common shares issued or purchased between December 31, 2001
and March 31, 2002. This assumes that none of the outstanding options
to purchase AEC Common Shares at March 31, 2002 are exercised and
converted to AEC Common Shares prior to the transaction.

(c) The number of issued and outstanding options to purchase AEC Common
Shares on the date of the transaction has been assumed to be 9.0
million, updated to take into account options exercised between
December 31, 2001 and March 31, 2002. The fair value of these options
has been included in the calculation of the purchase price. The fair
value of these options was estimated at December 31, 2001 using the
Black-Scholes option pricing model with the same assumptions as
disclosed in Note 13 of the Notes to the AEC 2001 Consolidated
Financial Statements. The fair value of these options was calculated
to be $77 million, adjusted to reflect options exercised to March 31,
2002.

(d) The total purchase price includes the value of the PanCanadian Common
Shares to be issued to the AEC shareholders plus the cash costs of
completing the transaction. These costs, estimated to be $150
million, include investment advisor fees, legal and accounting fees,
printing and mailing costs and other transaction related costs. These
costs have been added to accounts payable on the unaudited Pro Forma
Consolidated Balance Sheet.

(e) Included in AEC's Preferred Securities are $430 million principal
amount of Capital Securities which are convertible, at the option of
the holder, into Common Shares of AEC. AEC also has the option to
repay both interest and principal through the issuance of Common
Shares. As a result, these securities are treated as equity for
accounting purposes and distributions in respect of these
securities, net of income tax, are charged directly to Retained
Earnings. Immediately prior to the closing of the transaction, AEC
supplemented the Trust Indenture covering these securities to remove
AEC's option to pay interest and principal through the issuance of
Common Shares. With the removal of this option, these securities are
treated as long-term debt and distributions in respect of these
securities are recorded as interest expense in the unaudited Pro
Forma Consolidated Statement of Earnings.

(f) Future income tax expense has been adjusted for the impact of the
items noted above that affect current year net earnings.

(g) No adjustment has been made to reflect operating synergies that may
be realized as a result of the transaction.

(h) The increase in the carrying value of Capital Assets relates to
unproved properties and therefore no adjustment has been made to
Depreciation, depletion and amortization.

The purchase price allocation is preliminary and may change as a result
of several factors, including:

- changes in the fair values of AEC's assets and liabilities at the
closing of the transaction;

- actual number of AEC Common Shares and options to acquire AEC Common
Shares outstanding at the date of the closing;

- actual transaction costs incurred.

However, Management does not believe that the final purchase price
allocation will differ materially from that presented in the unaudited Pro
Forma Consolidated Financial Statements.

5. Goodwill

The preliminary purchase price allocation includes approximately
$2.7 billion of Goodwill. As required under Canadian generally accepted
accounting principles, goodwill will not be amortized into income. However,
goodwill will be subject to an annual impairment review and should there be an
impairment, that amount would be charged to income.
As outlined in Note 4, the allocation of the purchase price presented is
preliminary. The Company will finalize the purchase price allocation after
closing the transaction. Prior to that time, Management may determine that
there are intangible assets acquired in the transaction, separate and apart
from goodwill. To the extent that such intangibles, if any, have definite
useful lives, the value assigned to them in the purchase equation will be
amortized into income over those useful lives. Although the amount allocated
to such intangibles, if any, will not be known until after the closing of the
transaction, Management does not believe that any such value, or the related
amortization expense, would have a material effect on the unaudited Pro Forma
Consolidated Financial Statements presented.




Attachment 2

EnCana Corporation
(formerly PanCanadian Energy Corporation)

Management's Discussion and Analysis
March 31, 2002


SPECIAL NOTE REGARDING FORWARD-LOOKING INFORMATION

In the interest of providing EnCana Corporation, formerly PanCanadian
Energy Corporation ("EnCana" or the "Company") shareholders and potential
investors with information regarding the Company, certain statements
throughout this Interim Management Discussion and Analysis (the "MD&A")
constitutes forward-looking statements within the meaning of the United States
Private Securities Litigation Reform Act of 1995. Forward-looking statements
are typically identified by words such as "anticipate," "believe," "expect,"
"plan," "intend," or similar words suggesting future outcomes or statements
regarding an outlook. Forward-looking statements in this MD&A include, but are
not limited to, statements with respect to: the Company's operating costs, the
Company's seismic and drilling plans, oil and gas prices, per unit netbacks,
the Company's oil, liquids and gas sales, the Company's cash flow from
operations and net earnings, the Company's production levels, development
plans with respect to the Company's Deep Panuke and Buzzard projects, the
impact of hedges on the Company's revenue, capital investment levels, the
sources of funding for capital investments, the successful integration of the
Company's personnel and businesses with those of Alberta Energy Company Ltd.
("AEC") and the timing thereof, and future operating results and various
components thereof.
Readers are cautioned not to place undue reliance on forward-looking
information, as there can be no assurance that the plans, intentions or
expectations upon which it is based will occur. By its nature, forward-looking
information involves 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. Although the Company 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. Some of the risks
and other factors which could cause results to differ materially from those
expressed in the forward-looking statements contained in this MD&A include,
but are not limited to: volatility of crude oil and natural gas prices,
fluctuations in currency and interest rates, product supply and demand, market
competition, risks inherent in the Company's North American and foreign oil
and gas and midstream operations, risks inherent in the Company's marketing
operations, imprecision of reserves estimates, the Company's ability to
replace and expand oil and gas reserves, the Company's ability to either
generate sufficient cash flow from operations to meet its current and future
obligations or obtain external sources of debt and equity capital, general
economic and business conditions, the Company's ability to enter into or renew
leases, the timing and costs of well construction, the Company's ability to
make capital investments and the amounts of capital investments, imprecision
in estimating the timing, costs and levels of production and drilling, the
results of exploration, development and drilling, imprecision in estimates of
future production capacity, the Company's ability to secure adequate product
transportation, uncertainty in the amounts and timing of royalty payments,
imprecision in estimates of product sales, changes in environmental and other
regulations, political and economic conditions in the countries in which the
Company operates, and such other risks and uncertainties described from time
to time in the Company's reports and filings with the Canadian securities
authorities and the United States Securities and Exchange Commission (the
"SEC"). Accordingly, the Company cautions that events or circumstances could
cause actual results to differ materially from those predicted. Statements
relating to "reserves" or "resources" are deemed to be forward-looking
statements, as they involve the implied assessment, based on certain estimates
and assumptions, that the resources and reserves described can be profitably
produced in the future. Readers are cautioned that the foregoing list of
important factors is not exhaustive. Readers are further cautioned not to
place undue reliance on forward-looking statements contained in this MD&A,
which is as of the date hereof, and the Company undertakes no obligation to
update publicly or revise any forward-looking information, whether as a result
of new information, future events or otherwise. The forward-looking statements
contained in this MD&A are expressly qualified by this cautionary statement.


ENCANA CORPORATION
(formerly PANCANADIAN ENERGY CORPORATION)
MANAGEMENT'S DISCUSSION AND ANALYSIS

This Management's Discussion and Analysis ("MD&A") for EnCana
Corporation, formerly PanCanadian Energy Corporation, ("PanCanadian" or the
"Company"), should be read in conjunction with the unaudited interim
consolidated financial statements for the three months ended March 31, 2002
and March 31, 2001 and the audited consolidated financial statements and MD&A
for the year ended December 31, 2001.

CONSOLIDATED OVERVIEW

In the three months ended March 31, 2002, net income was $133 million, or
52 cents per common share, down from $463 million, or $1.81 per common share,
in the same period of 2001. Cash flow of $389 million, or $1.52 per common
share, compared with $738 million, or $2.89 per common share, in the first
quarter of 2001. Weaker market prices for natural gas and crude oil were only
partially offset by higher natural gas production and a decline in the pricing
differential between lighter and heavier crude oils.
The Company's financial position remained strong. Cash flow in the
quarter provided a significant portion of the funding for investing activities
of $527 million. At March 31, 2002, debt amounted to $2,288 million and
represented 36 percent of debt plus equity. Cash on hand was $519 million and
net debt to trailing 12-month cash flow was 90 percent.
During the first quarter of 2002, the Company adopted, on a retroactive
basis, the amended Canadian standard on accounting for foreign currency
translation. The amendment eliminates the deferral and amortization of foreign
exchange gains or losses on long-term monetary items. As a result, there was
an increase in reported net income of $8 million in the first quarter of 2002
and a decrease of $31 million in the same quarter last year.
Early in April 2002, PanCanadian and Alberta Energy Company (AEC)
combined their two companies - creating EnCana Corporation. The companies
satisfied all closing conditions, including receiving approvals on April 4
from shareholders of PanCanadian and shareholders and option holders of AEC
and on April 5 from The Court of Queen's Bench of Alberta. PanCanadian
shareholders also approved renaming of the Company to EnCana Corporation. The
merger of equals was effected through the exchange of 1.472 PanCanadian
(EnCana after the name change) shares for each AEC share. EnCana shares
started trading on the Toronto and New York stock exchanges on April 8 under
the symbol ECA.
On April 24, 2002, the Company adopted formal plans to dispose of the
Houston-based merchant energy operation, which is included in the Marketing
and Midstream segment. Exit alternatives are being evaluated to maximize the
value of the disposition. Accordingly, these operations have been accounted
for as discontinued operations and the financial statements have been restated
as described in Note 3 to the Consolidated Financial Statements.

BUSINESS ENVIRONMENT
<<
Three Months Ended
March 31
------------------
2002 2001
---------------------------------------------------------------------

Average AECO Price ($ per thousand
cubic feet) 3.49 11.37

Average NYMEX Price (US$ per million
British thermal unit) 2.32 7.09

Average WTI (US$ per barrel) 21.63 28.67

WTI Bow River Differential (US$ per
barrel) 5.22 11.87

US/Canadian dollar exchange rate (US$) 0.627 0.654
>>
High natural gas storage levels continued to have a dampening effect on
natural gas prices. Evidence that demand is benefiting from a milder and
briefer than expected economic recession, coupled with the prospects of
limited new supply due to reduced drilling activity in the U.S., was of little
benefit to prices. The AECO index price averaged $3.49 per thousand cubic feet
in the first quarter of 2002, compared with $3.44 per thousand cubic feet in
the fourth quarter of 2001 and $11.37 per thousand cubic feet in the first
quarter of 2001.
Averaging US$21.63 per barrel in the first quarter of 2002, the West
Texas Intermediate (WTI) crude oil price was up five percent from an average
of US$20.53 per barrel in the fourth quarter of 2001. Prospects for stronger
than expected demand growth, co-ordinated cutbacks in OPEC production and an
uncertain situation in Iraq and the Middle East combined to build support for
firmer crude oil prices. However, the WTI price remained below its average of
US$28.67 per barrel in the first quarter of 2001.
There was a significant narrowing in the differential between heavier and
lighter crude oil prices as the supply/demand balance for heavy oil improved.
The WTI-Bow River differential averaged US$5.22 per barrel in the first three
months of 2002, compared with US$9.52 per barrel and US$11.87 per barrel in
the last and first quarters of 2001, respectively. Market fundamentals for
heavy oil are expected to further benefit from the scheduled resumption in the
second quarter of operations at the CITGO refinery in Illinois, which was
closed for several months after it suffered a fire, and from the approaching
start of the summer asphalt season.

RESULTS OF OPERATIONS

Upstream
<<
Three Months Ended March 31
---------------------------------------
2002
---------------------------------------
Natural Crude Field NGL
Financial Results ($ millions) gas oil & other Total
-------------------------------------------------------------------------
Revenues
Production $ 335 $ 235 $ 30 $ 600
Royalties and similar payments (34) (33) (1) (68)
-------------------------------------------------------------------------
301 202 29 532

Expenses
Direct operating(*) 49 55 - 104
Administrative - - - 22
Depletion, depreciation
and amortization - - - 206
-------------------------------------------------------------------------

Upstream income $ 252 $ 147 $ 29 $ 200
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Capital expenditures (excludes
net acquisitions / dispositions) $ 478
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Three Months Ended March 31
---------------------------------------
2001
---------------------------------------
Natural Crude Field NGL
Financial Results ($ millions) gas oil & other Total
-------------------------------------------------------------------------

Revenues
Production $ 811 $ 249 $ 47 $1,107
Royalties and similar payments (67) (25) (2) (94)
-------------------------------------------------------------------------
744 224 45 1,013

Expenses
Direct operating(*) 39 64 - 103
Administrative - - - 20
Depletion, depreciation
and amortization - - - 170
-------------------------------------------------------------------------

Upstream income $ 705 $ 160 $ 45 $ 720
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Capital expenditures (excludes
net acquisitions / dispositions) $ 351
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(*) Direct operating expenses for field NGL are commingled with natural
gas expenses.


Three Months Ended March 31
Revenue Variances for 2002 --------------------------------
Compared to 2001 ($ millions) Price Volume Total
-------------------------------------------------------------------------

Natural gas $ (520) $ 44 $ (476)
Crude oil (10) (4) (14)
Field NGL and other (26) 9 (17)
-------------------------------------------------------------------------
Total production revenue $ (556) $ 49 $ (507)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
In the first quarter of 2002, Upstream production revenues of $600
million were down $507 million, or 46 percent, from the same quarter of 2001.
The Company's realized natural gas price was $3.44 per thousand cubic
feet, a decrease of 61 percent from $8.76 per thousand cubic feet in the first
three months of 2001. Hedging activities resulted in a gain of $29 million, or
30 cents per thousand cubic feet, versus a cost of $113 million, or $1.22 per
thousand cubic feet, in first quarter of 2001. There was a five-percent
increase in average daily natural gas production to 1,085 million cubic feet
due chiefly to a successful drilling program.
Compared with the first quarter of 2001, a decline in market prices for
lighter crude oils was largely offset by a narrowing in the differential
between heavier and premium-priced lighter crude oils. The realized price on
the Company's mix of crude oil products of $25.55 per barrel in the first
quarter of 2002 was down just four percent, while the benchmark WTI crude oil
price declined 25 percent. Hedging activities had unfavourable effects of
$8 million, or 82 cents per barrel, in the first quarter of 2002 and
$11 million, or $1.14 per barrel, in the same quarter of 2001. Production of
crude oil was down two percent, averaging 102,000 barrels per day in the first
quarter of 2002. The decline reflects the sale of non-core, crude oil
producing properties, as well as the Company's focus on growing its natural
gas business.
Excluding the impact of commodity and currency hedging, royalties and
similar payments were approximately 12 percent of revenues, compared with
eight percent in the first quarter of 2001. The higher rate in 2002 reflected
an under-accrual of freehold mineral taxes at year-end 2001.
<<
Three Months Ended
March 31
Unit Direct Operating Expenses ------------------
($ per unit) 2002 2001
-------------------------------------------------------------------------

Natural gas and field liquids (per
thousand cubic feet)(*) $ 0.50 $ 0.42

Crude oil (per barrel) 6.60 7.75

Per barrel of oil equivalent(xx) 4.24 4.41

(*) Field liquids converted to natural gas at 1 barrel equals 6 thousand
cubic feet.
(xx) Natural gas converted to barrel of oil equivalent at 6 thousand
cubic feet equals 1 barrel of oil equivalent.
>>
Direct operating expenses in the Upstream division amounted to
$104 million in the first quarter of 2002, compared with $103 million in the
corresponding quarter of 2001. For natural gas and field liquids, unit
operating costs on working interest production rose eight cents to 50 cents
per thousand cubic feet equivalent as higher processing and maintenance costs
more than offset the benefit of lower electricity charges. Costs associated
with working interest production of crude oil decreased $1.15 to $6.60 per
barrel. The improvement in unit operating expenses for crude oil was due
chiefly to lower electricity costs.
Administrative expenses in the Upstream division were $22 million in the
first quarter of 2002, up $2 million from the same period last year. On a
barrel of oil equivalent basis, administrative expenses were 82 cents, or up
six percent.
Depletion, depreciation and amortization charges amounted to $206 million
and compared with $170 million in the first quarter last year. On a barrel of
oil equivalent basis, depletion, depreciation and amortization expenses were
up 17 percent to $7.69 per barrel due to higher levels of capital spending.
Capital expenditures in the Upstream division were $478 million, up
$127 million from the first quarter of 2001. The majority, approximately
72 percent, of this investment in 2002 was directed towards natural gas and
crude oil exploration and development in the Western Basin. Approximately
28 percent was targeted to high impact exploration and other activities
internationally and offshore the East Coast of Canada. The Company drilled 571
wells in the first quarter of 2002, 92 percent of which were successful.

Marketing and Midstream
<<
Three Months Ended
March 31
------------------
Financial Results ($ millions) 2002 2001
-------------------------------------------------------------------------

Revenues
Marketing(*) $ 976 $ 1,644
Midstream 85 115
-------------------------------------------------------------------------
1,061 1,759
-------------------------------------------------------------------------

Direct expenses
Marketing(*) 953 1,616
Midstream 61 102
-------------------------------------------------------------------------
1,014 1,718
-------------------------------------------------------------------------

Margin 47 41
Administrative 9 5
Depreciation and amortization 8 5
-------------------------------------------------------------------------

Marketing and Midstream income $ 30 $ 31
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Capital expenditures (excludes net
acquisitions / dispositions) $ 4 $ 26
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(*) Marketing and Midstream segment results for the first quarter of 2002
include inter-segment sales of $541 million (2001 - $1,115 million),
as disclosed in Note 2 to the unaudited financial statements.

Marketing


Three Months Ended
Marketed Volumes(*) March 31
------------------
2002 2001
-------------------------------------------------------------------------

Natural gas (million cubic feet per day) 1,347 1,158
Crude oil (thousand barrels per day) 194 167
Natural gas liquids (thousand barrels per day) 70 62
Electricity (thousand megawatt hours) 137 -
Total (thousand MMBTUs per day)(xx) 2,936 2,532

(*) Included in the marketed volume totals are amounts related to
PanCanadian production.
(xx) Conversion assumed at: 1 million cubic feet equals 1 thousand MMBTU;
1 thousand barrels equals 6 thousand MMBTU; 1 thousand megawatt
hours equals 10 thousand MMBTU.
>>
Marketing revenues were down 41 percent to $976 million from $1,644
million in the first three months of 2001. The Marketing margin declined to
$23 million from $28 million. Lower natural gas prices were the main factor
underlying the decline. The margin increased to 2.4 from 1.7 percent of
revenues even with lower volatility than in the prior year.

Midstream
<<

Three Months Ended
Midstream Production March 31
------------------
2002 2001
-------------------------------------------------------------------------

Natural gas liquids (thousand barrels per day) 34 25



PanCanadian
Midstream Electricity Megawatt Megawatt Ownership Megawatt
Capacity (as at March 31, 2002) Capacity (%) Capacity
-------------------------------------------------------------------------


Kingston 108 25 27
Cavalier 85 100 85
Balzac 85 50 43
-------------------------------------------------------------------------
155
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
Midstream revenues were down $30 million, or 26 percent, to $85 million
in the three months ended March 31, 2002. However, the associated margin
nearly doubled, increasing to $24 million from $13 million in the same quarter
of 2001. Natural gas liquids (NGL) production improved 36 percent to 34,000
barrels per day. During the first quarter of last year, the Company reduced
production of extracted NGL in order to realize incremental value through the
sale of natural gas, which would have otherwise been consumed in the
production process. In the first quarter of 2002, product prices declined from
the same period last year; however, significantly lower input costs of natural
gas more than offset the price decline and the midstream margin improved
substantially.
In the first quarter of 2002, Midstream revenue included approximately
$7 million from the two new 106-megawatt electricity generation plants. The
Midstream unit commenced operations of the Cavalier plant at 80 percent of
capacity in the third quarter of 2001 and the Balzac plant, which is
50 percent owned by PanCanadian, commenced operations in December 2001 at
80 percent of capacity.
Marketing and Midstream administrative expenses were $9 million in the
first quarter of 2002, up from $5 million in the corresponding quarter of
2001. The increase principally reflected higher staffing levels that stemmed
from an expanded Marketing and Midstream asset and activity base.
Depreciation and amortization expenses in Marketing and Midstream
increased to $8 million from $5 million in the first quarter of 2001 largely
because of the depreciation charges on the two new electricity generation
plants.
Compared with the first quarter of 2001, capital expenditures decreased
$22 million to $4 million due mainly to the completion of construction on the
two new electricity generation plants.

Corporate

The Company's foreign exchange position contributed revenue of
$10 million in the first quarter of 2002, which contrasted with a charge of
$24 million in 2001. In the first quarter of 2002, the Company adopted, on a
retroactive basis, the amended Canadian standard on accounting for foreign
currency translation. This amendment eliminates the deferral and amortization
of foreign exchange gains or losses on long-term monetary items. The effect of
the change is disclosed in Note 1 to the unaudited consolidated financial
statements.
Corporate administrative expenses in the first quarter of 2002 included a
one-time benefit of $5 million. The benefit stemmed from an over-accrual in
2001 of charges associated with the reorganization of Canadian Pacific
Limited.
Compared to the first quarter last year, interest expense was up
$12 million to $32 million, principally reflecting a higher borrowing level.
The provision for income taxes decreased $189 million to $82 million in
the first quarter of 2002 because of the lower operating income. The effective
tax rate was 38 percent, unchanged from the first quarter of 2001.

LIQUIDITY, CAPITAL RESOURCES AND RISK MANAGEMENT

Cash flow from continuing operations of $387 million in the first three
months of 2002 decreased from $712 million in the same period of 2001. The
decline stemmed chiefly from weaker market prices. In addition, cash from
operating activities was adversely affected by changes in non-cash working
capital, which used $243 million in the first quarter of 2002 compared with a
source of $142 million in 2001. The variance in working capital changes
principally reflected the timing of payments for current income taxes.
The Company's net investing activities in the first quarter of 2002 were
up $223 million to $527 million, including Upstream capital spending of
$478 million and Marketing and Midstream expenditures of $4 million.
Acquisition and disposition activities resulted in net proceeds of $3 million
in the first quarter of 2002 and $152 million in the same period of 2001 when
dispositions included the sale of the Pelican Lake property.
In the first quarter of 2002, $80 million, or US$50 million, of medium
term notes matured and were retired. The consolidated debt position, including
the current portion, was $2,288 million at March 31, 2002 compared with
$2,370 million at December 31, 2001. Debt to debt plus equity was 36 percent,
essentially unchanged from 37 percent at year-end 2001. At the end of the
first quarter, interest coverage on a trailing 12-month basis was 24.5 times,
cash on hand was $519 million and net debt to trailing 12-month cash flow was
90 percent.
The Company's financial strength and flexibility is supplemented by a
$1.1 billion syndicated credit facility, other bank facilities of $550 million
and a $300 million commercial paper program. PanCanadian has US$650 million
available under its US$1.5 billion shelf prospectus that was established in
the fourth quarter of 2001 for a two-year term. During the third quarter of
2001, the Company renewed a $1 billion Canadian medium-term note shelf for a
two-year term. At March 31, 2002, no issuances were outstanding and the total
authorized amounts were available for use.
Risk management assets and liabilities recorded on the balance sheet
result from the application of mark-to-market accounting for the physical and
financial derivative positions in the marketing business, representing
primarily current year values. These assets and liabilities are managed
strictly in accordance with the Company's prescribed risk limits, and all
transactions are executed in accordance with the approved processes and
controls set out in the risk management and credit policies. There were no new
significant credit provisions taken in 2001 or 2002.

OUTLOOK

The outlook that follows excludes the effect of the merger of PanCanadian
and AEC completed early in April 2002.
The Company expects to post a solid performance in 2002. Its growing
production should benefit from firming energy prices as the North American
economy recovers.
As of March 31, 2002, PanCanadian had the following hedges in place:

- approximately 205 million cubic feet per day of natural gas at an
average AECO equivalent of $5.97 per thousand cubic feet from April 1,
2002 to October 31, 2002; and

- 10,000 barrels per day of crude oil sold forward for the period April
2002 to June 2002 at an average WTI price of US$23.57.


EnCana Corporation
(formerly PanCanadian Energy Corporation)


Consolidated Financial Statements
March 31, 2002

<<

EnCana Corporation (formerly PanCanadian Energy Corporation)

CONSOLIDATED STATEMENT OF INCOME

Three Months Ended
March 31
(unaudited) ($ millions, ------------------
except per share amounts) 2002 2001
-------------------------------------------------------------------------

Revenues (note 2) $ 1,062 $ 1,641

Expenses (note 2)
Direct 577 706
Administrative 26 25
Interest on long-term debt 32 20
Depletion, depreciation and amortization 214 175
-------------------------------------------------------------------------
849 926
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Income before Income Taxes 213 715
-------------------------------------------------------------------------

Provision for Income Taxes
Current 40 195
Future 42 76
-------------------------------------------------------------------------
82 271
-------------------------------------------------------------------------
Income from continuing operations 131 444
Discontinued operations (note 3) 2 19
-------------------------------------------------------------------------
Net Income $ 133 $ 463
-------------------------------------------------------------------------
Distributions on Preferred Securities,
Net of Tax - (1)
-------------------------------------------------------------------------
Net Income Attributable to Common Shareholders $ 133 $ 462
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Net Income Attributable per Common Share
Basic
Income from continuing operations $ 0.51 $ 1.74
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income $ 0.52 $ 1.81
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Diluted
Income from continuing operations $ 0.51 $ 1.70
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income $ 0.51 $ 1.77
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Weighted Average Number of Shares
Outstanding (millions) 255.3 255.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------



CONSOLIDATED STATEMENT OF RETAINED INCOME

Three Months Ended
March 31
------------------
(unaudited) ($ millions) 2002 2001
-------------------------------------------------------------------------

Retained income at beginning of period
As previously reported $ 3,689 $ 3,721
Prior period adjustment (note 1) (59) (42)
-------------------------------------------------------------------------
As restated 3,630 3,679
Net income 133 463
Dividends (25) (26)
Distributions on preferred securities, net of tax - (1)
-------------------------------------------------------------------------
Retained income at end of period $ 3,738 $ 4,115
-------------------------------------------------------------------------
-------------------------------------------------------------------------

See selected notes to consolidated financial statements.


EnCana Corporation (formerly PanCanadian Energy Corporation)

CONSOLIDATED STATEMENT OF CASH FLOWS

Three Months Ended
March 31
------------------
(unaudited) ($ millions) 2002 2001
-------------------------------------------------------------------------

Operating Activities
Income from continuing operations $ 131 $ 444
Depletion, depreciation and amortization 214 175
Future income taxes 42 76
Other - 17
-------------------------------------------------------------------------
Cash flow from continuing operations 387 712
Cash flow from discontinued operations 2 26
-------------------------------------------------------------------------
Cash flow 389 738
Net change in non-cash working capital from
continuing operations (268) 142
Net change in non-cash working capital from
discontinued operations 53 113
-------------------------------------------------------------------------
174 993
-------------------------------------------------------------------------
Financing Activities
Repayment of short-term financing - (250)
Issuance of long-term debt - 94
Repayment of long-term debt (80) (155)
Issuance of common shares 18 24
Dividends on common shares (25) (26)
Distribution on preferred securities - (2)
Net change in non-cash working capital (2) (2)
-------------------------------------------------------------------------
(89) (317)
-------------------------------------------------------------------------
Investing Activities
Petroleum and natural gas properties (356) (249)
Plant, production and other equipment (122) (102)
-------------------------------------------------------------------------
Upstream (478) (351)
Midstream (4) (26)
-------------------------------------------------------------------------
(482) (377)
Net (acquisitions) dispositions 3 152
Net change in other assets (17) (7)
Net change in non-cash working capital (31) (75)
Discontinued operations - 3
-------------------------------------------------------------------------
(527) (304)
-------------------------------------------------------------------------

Foreign Exchange Gain (Loss) on Cash
held in Foreign Currency (2) 22
-------------------------------------------------------------------------

Increase (Decrease) in Cash (444) 394

Cash at Beginning of Period 963 197
-------------------------------------------------------------------------
Cash at End of Period $ 519 $ 591
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Supplementary Disclosure of Cash Flow Information
Interest paid $ 11 $ 19
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Income taxes paid $ 191 $ 14
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See selected notes to consolidated financial statements.

EnCana Corporation (formerly PanCanadian Energy Corporation)

CONSOLIDATED BALANCE SHEET

As at As at
March 31 December 31
-------- -----------
($ millions) 2002 2001
-------------------------------------------------------------------------
(unaudited) (audited)

Assets
Current assets
Cash $ 519 $ 963
Accounts receivable 443 518
Risk management assets 97 105
Inventories 81 87
-------------------------------------------------------------------------
1,140 1,673
-------------------------------------------------------------------------
Property, plant and equipment, at cost 15,208 14,738
Less accumulated depletion, depreciation
and amortization (6,760) (6,576)
-------------------------------------------------------------------------
8,448 8,162

Deferred charges and other assets (note 1) 242 237
Net assets of discontinued operations (note 3) 90 142
-------------------------------------------------------------------------
$ 9,920 $ 10,214
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Liabilities and Shareholders' Equity
Current liabilities
Accounts payable and accrued liabilities $ 473 $ 684
Income taxes payable 509 656
Risk management liabilities 91 100
Current portion of deferred credits and liabilities 33 40
Current portion of long-term debt 193 160
-------------------------------------------------------------------------
1,299 1,640
-------------------------------------------------------------------------
Long-term debt 2,095 2,210
Deferred credits and liabilities (note 1) 320 325
Future income taxes 2,101 2,060

Shareholders' equity
Preferred securities 126 126
Common shares (note 4) 214 196
Paid in surplus 27 27
Retained income (note 1) 3,738 3,630
-------------------------------------------------------------------------
4,105 3,979
-------------------------------------------------------------------------
$ 9,920 $ 10,214
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See selected notes to consolidated financial statements.
>>

EnCana Corporation (formerly PanCanadian Energy Corporation)

SELECTED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Three months ended March 31, 2002 (unaudited)

The interim consolidated financial statements include the accounts of
EnCana Corporation (formerly PanCanadian Energy Corporation) and its
subsidiaries (the "Company"), and are presented in accordance with Canadian
generally accepted accounting principles. The interim consolidated financial
statements have been prepared following the same accounting policies and
methods of computation as the consolidated financial statements for the year
ended December 31, 2001, except as described below. The disclosures provided
below are incremental to those included with the annual audited consolidated
financial statements. The interim consolidated financial statements should be
read in conjunction with the annual audited consolidated financial statements
and the notes thereto for the year ended December 31, 2001.

Note 1. Changes in Accounting Policies

Foreign Currency Translation
Effective 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 or losses were deferred and
amortized over the remaining life of the monetary item. Prior periods have
been restated for the change in accounting policy. The change results in an
increase to net income of $8 million for 2002 (2001 - decrease of
$31 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 income of $59 million.

EnCana Corporation (formerly PanCanadian Energy Corporation)
SELECTED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Three months ended March 31, 2002 (unaudited)

Note 2. Segmented Information
<<
Three Months Ended
March 31
------------------
Statement of Income ($ millions) 2002 2001
-------------------------------------------------------------------------

Upstream
Revenues
Gas $ 335 $ 811
Oil - Light/medium 193 222
Oil - Heavy 42 27
Field liquids 25 43
Processing and other income 5 4
Royalties and similar payments (68) (94)
-------------------------------------------------------------------------
532 1,013
-------------------------------------------------------------------------
Expenses
Direct
Gas and related products 47 37
Oil - Light/medium 39 45
Oil - Heavy 16 19
Gas processing - royalty interest 2 2
-------------------------------------------------------------------------
104 103
Administrative 22 20
Depletion, depreciation and amortization 206 170
-------------------------------------------------------------------------
332 293
-------------------------------------------------------------------------
Upstream income 200 720
-------------------------------------------------------------------------

Marketing and Midstream
Revenues
Marketing 976 1,644
Midstream 85 115
-------------------------------------------------------------------------
1,061 1,759
-------------------------------------------------------------------------
Expenses
Direct
Marketing 953 1,616
Midstream 61 102
-------------------------------------------------------------------------
1,014 1,718
Administrative 9 5
Depreciation and amortization 8 5
-------------------------------------------------------------------------
1,031 1,728
-------------------------------------------------------------------------
Marketing and Midstream income 30 31
-------------------------------------------------------------------------

Income before corporate activities 230 751
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Foreign exchange gain (loss) 10 (24)
Interest and other revenues - 8
Interest expense on long term debt (32) (20)
Corporate administrative expenses (*) 5 -
-------------------------------------------------------------------------
Income before income taxes 213 715
Provision for income taxes 82 271
-------------------------------------------------------------------------

Income from continuing operations 131 444
Discontinued operations (note 3) 2 19
-------------------------------------------------------------------------

Consolidated net income $ 133 $ 463
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(*) 2002 corporate administrative expenses include a $5 million recovery
for costs associated with the reorganization of CPL.


EnCana Corporation (formerly PanCanadian Energy Corporation)
SELECTED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Three months ended March 31, 2002 (unaudited)

Note 2. Segmented Information (continued)


Reconciliation of Segment Results
to the Consolidated Income Statement


For the three months ended Marketing &
March 31, 2002 ($ millions) Upstream Midstream Corporate
-------------------------------------------------------------------------

Revenues $ 532 $ 1,061 $ 10
Expenses
Direct 104 1,014 -
Administrative 22 9 (5)
Interest on long-term debt - - 32
Depletion, depreciation and
amortization 206 8 -
-------------------------------------------------------------------------

Income before income taxes $ 200 $ 30 $ (17)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

For the three months ended
March 31, 2001 ($ millions)
-------------------------------------------------------------------------

Revenues $ 1,013 $ 1,759 $ (16)
Expenses
Direct 103 1,718 -
Administrative 20 5 -
Interest on long-term debt - - 20
Depletion, depreciation and
amortization 170 5 -
-------------------------------------------------------------------------

Income before income taxes $ 720 $ 31 $ (36)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


For the three months ended Inter-segment Consolidated
March 31, 2002 ($ millions) Eliminations(*) Total
-------------------------------------------------------------------------

Revenues $ (541) $ 1,062
Expenses
Direct (541) 577
Administrative - 26
Interest on long-term debt - 32
Depletion, depreciation and
amortization - 214
-------------------------------------------------------------------------

Income before income taxes $ - $ 213
-------------------------------------------------------------------------
-------------------------------------------------------------------------

For the three months ended
March 31, 2001 ($ millions)
-------------------------------------------------------------------------

Revenues $ (1,115) $ 1,641
Expenses
Direct (1,115) 706
Administrative - 25
Interest on long-term debt - 20
Depletion, depreciation and
amortization - 175
-------------------------------------------------------------------------

Income before income taxes $ - $ 715
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) Inter-segment eliminations represent the sales of natural gas, crude
oil and NGL from the Upstream segment to the Marketing and Midstream
segment.





Three Months Ended
March 31
------------------
Net additions to capital assets ($ millions) 2002 2001
-------------------------------------------------------------------------

Upstream $ 476 $ 114
Marketing and Midstream 4 21
-------------------------------------------------------------------------
$ 480 $ 135
-------------------------------------------------------------------------
-------------------------------------------------------------------------


EnCana Corporation (formerly PanCanadian Energy Corporation)
SELECTED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Three months ended March 31, 2002 (unaudited)

Note 2. Segmented Information (continued)


Selected Balance Sheet Disclosure

As at March 31, 2002 Marketing & Corporate &
($ millions) Upstream Midstream Eliminations
-------------------------------------------------------------------------

Cash(*) $ - $ - $ 519
Non-cash current assets 525 449 (353)
Property, plant and
equipment, net 7,975 473 -
Other assets and deferred
charges 182 8 52
-------------------------------------------------------------------------
Total identifiable assets $ 8,682 $ 930 $ 218
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Current liabilities(*) $ (381) $ (329) $ (396)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


As at March 31, 2002 Discontinued Consolidated
($ millions) Operations Total
-------------------------------------------------------------------------

Cash(*) $ - $ 519
Non-cash current assets 519 1,140
Property, plant and equipment, net 9 8,457
Other assets and deferred charges 17 259
-------------------------------------------------------------------------
Total identifiable assets $ 545 $ 10,375
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Current liabilities(*) $ 454 $ (1,560)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


As at December 31, 2001 Marketing & Corporate &
($ millions) Upstream Midstream Eliminations
-------------------------------------------------------------------------

Cash(*) $ - $ - $ 963
Non-cash current assets 447 588 (325)
Property, plant and
equipment, net 7,687 475 -
Other assets and deferred
charges 187 6 44
-------------------------------------------------------------------------
Total identifiable assets $ 8,321 $ 1,069 $ 682
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Current liabilities(*) $ (489) $ (456) $ (535)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


As at December 31, 2001 Discontinued Consolidated
($ millions) Operations Total
-------------------------------------------------------------------------

Cash(*) $ - $ 963
Non-cash current assets 702 1,412
Property, plant and equipment, net 9 8,171
Other assets and deferred charges 17 254
-------------------------------------------------------------------------
Total identifiable assets $ 728 $ 10,800
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Current liabilities(*) $ (584) $ (2,064)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


As at March 31, 2001 Marketing & Corporate &
($ millions) Upstream Midstream Eliminations
-------------------------------------------------------------------------

Cash(*) $ - $ - $ 591
Non-cash current assets 808 704 (715)
Property, plant and
equipment, net 6,717 356 -
Other assets and deferred
charges 194 13 41
-------------------------------------------------------------------------
Total identifiable assets $ 7,719 $ 1,073 $ (83)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Current liabilities(*) $ (357) $ (669) $ 64
-------------------------------------------------------------------------
-------------------------------------------------------------------------


As at March 31, 2001 Discontinued Consolidated
($ millions) Operations Total
-------------------------------------------------------------------------

Cash(*) $ - $ 591
Non-cash current assets 742 1,539
Property, plant and equipment, net 5 7,078
Other assets and deferred charges 27 275
-------------------------------------------------------------------------
Total identifiable assets $ 774 $ 9,483
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Current liabilities(*) $ (785) $ (1,747)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) Current liabilities excludes short-term financing and current portion
of long-term debt. Cash and income taxes payable have been included
in the Corporate and Elimination balances.


EnCana Corporation (formerly PanCanadian Energy Corporation)
SELECTED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Three months ended March 31, 2002 (unaudited)

Note 3. Discontinued Operations

On April 24, 2002, the Company adopted formal plans to dispose of the
Houston-based merchant energy operation, which is included in the Marketing
and Midstream segment. Accordingly, these operations have been accounted for
as discontinued operations.
The following tables present the effect of the discontinued operations on
the Consolidated Financial Statements as at March 31.


Consolidated Statement of Income
($ millions) 2002 2001
-------------------------------------------------------------------------

Revenues $ 746 $ 1,522
-------------------------------------------------------------------------
Expenses
Direct 733 1,483
Administrative 10 7
Depletion, depreciation and amortization - 1
-------------------------------------------------------------------------
743 1,491
-------------------------------------------------------------------------
Income before income taxes 3 31
Income taxes 1 12
-------------------------------------------------------------------------
Net income from discontinued operations $ 2 $ 19
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Consolidated Balance Sheet ($ millions) 2002 2001
-------------------------------------------------------------------------

Accounts receivable $ 359 $ 507
Risk management assets 138 227
Inventories 22 8
-------------------------------------------------------------------------
519 742
-------------------------------------------------------------------------

Property, plant and equipment, at cost 13 8
Less accumulated depletion, depreciation
and amortization (4) (3)
-------------------------------------------------------------------------
9 5
Deferred charges and other assets 17 27
-------------------------------------------------------------------------
545 774
-------------------------------------------------------------------------

Accounts payable and accrued liabilities 339 568
Risk management liabilities 115 217
-------------------------------------------------------------------------
454 785
Deferred credits and liabilities 1 2
-------------------------------------------------------------------------
455 787
-------------------------------------------------------------------------
Net assets of discontinued operations $ 90 $ (13)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


EnCana Corporation (formerly PanCanadian Energy Corporation)
SELECTED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Three months ended March 31, 2002 (unaudited)

Note 3. Discontinued Operations (continued)

For comparative purposes, the following tables present the effect of the
Discontinued Operations on the Consolidated Financial Statements for the years
ended December 31.

Consolidated Statement of Income
($ millions) 2001 2000 1999
-------------------------------------------------------------------------

Revenues $ 4,085(*) $ 3,025 $ 1,612
-------------------------------------------------------------------------
Expenses
Direct 3,983(*) 2,961 1,623
Administrative 43 26 20
Depletion, depreciation and
amortization 4 3 3
-------------------------------------------------------------------------
4,030 2,990 1,646
-------------------------------------------------------------------------
Income before income taxes 55 35 (34)
Income taxes 22 13 (14)
-------------------------------------------------------------------------
Net income from discontinued
operations $ 33 $ 22 $ (20)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


(*) Upon review of additional information related to 2001 sales and
purchases of natural gas by the US 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-Direct. The
amendment had no effect on net income or cash flow but Revenues and
Expenses - Direct have been reduced by $1,126 million.



Consolidated Balance Sheet ($ millions) 2001 2000
-------------------------------------------------------------------------

Accounts receivable $ 323 $ 699
Risk management assets 309 -
Inventories 70 2
-------------------------------------------------------------------------
702 701
-------------------------------------------------------------------------

Property, plant and equipment, at cost 13 5
Less accumulated depletion, depreciation
and amortization (4) (2)
-------------------------------------------------------------------------
9 3
Deferred charges and other assets 17 32
-------------------------------------------------------------------------
728 736
-------------------------------------------------------------------------

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
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Consolidated Statement of Cash flows
($ millions) 2001 2000 1999
-------------------------------------------------------------------------

Operating Activities
Cash flow 47 26 (21)
Net change in non-cash working
capital (48) (2) (44)
-------------------------------------------------------------------------
Cash from operating activities
- discontinued operations (1) 24 (65)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) Upon review of additional information related to 2001 sales and
purchases of natural gas by the US 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-Direct. The
amendment had no effect on net income or cash flow but Revenues and
Expenses - Direct have been reduced by $1,126 million.


EnCana Corporation (formerly PanCanadian Energy Corporation)
SELECTED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Three months ended March 31, 2002 (unaudited)

Note 4. Common Shares

The Company's authorized share capital consists of an unlimited number of
common shares.

Number of
Issued and Outstanding Shares ($ millions)
-------------------------------------------------------------------------

Balance at January 1, 2002 254,939,851 $ 196
Issued under stock option plan 750,036 18
-------------------------------------------------------------------------
Balance at March 31, 2002 255,689,887 $ 214
-------------------------------------------------------------------------
-------------------------------------------------------------------------

The Company has a stock-based compensation plan (PanCanadian plan) that
allows certain key employees to purchase common shares of the Company. Option
exercise prices approximate the market price for the common shares on the date
the options are 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 plans expire 10 years from the date the options
were granted. As a result of the transaction as described in Note 5, all
options outstanding under the PanCanadian plan became exercisable after the
close of business on April 5, 2002.
As part of the Canadian Pacific Limited (CPL) reorganization in 2001, CPL
stock options were replaced with stock options granted by the Company (CPL
replacement plan) in a manner that was consistent with the provisions of the
CPL stock option plan. Under CPL's stock option plan, options were granted to
certain key employees to purchase common shares of CPL at a price not less
than the market value of the shares at the grant date. The options expire 10
years after the grant date and, as a result of the reorganization are all
fully vested and exercisable.

Weighted
Number of Average
Continuity of Stock Options Options Exercise Price
-------------------------------------------------------------------------
Outstanding at January 1, 2002 10,511,178 $ 32.31
Granted under PanCanadian plan 31,000 43.69
Exercised (750,036) 24.26
Cancelled (71,650) 29.81
-------------------------------------------------------------------------
Outstanding at March 31, 2002 9,720,492 $ 33.00
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Exercisable at March 31, 2002 2,692,150 $ 22.39
-------------------------------------------------------------------------
-------------------------------------------------------------------------

The Company accounts for its stock-based compensation plans using the
intrinsic-value method. Under the intrinsic-value method, compensation costs
are not recognized in the financial statements for share options granted to
employees and directors when issued at market value.
Effective January 1, 2002, Canadian accounting standards require
disclosure of the impact on net income of using the fair value method for
stock options issued on or after January 1, 2002. If the fair-value method had
been used, the effect on the Company's 2002 net income and net income per
share would have been immaterial based on the number of stock options granted
in this period.

EnCana Corporation (formerly PanCanadian Energy Corporation)
SELECTED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Three months ended March 31, 2002 (unaudited)

Note 5. Financial Instruments

Unrecognized gains (losses) on risk management activities:

($ millions) March 31, 2002
-------------------------------------------------------------------------

Natural gas $ 50
Crude oil (4)
Foreign currency (167)
Interest rates 47
Preferred securities 4
-------------------------------------------------------------------------
$ (70)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Information with respect to crude oil, currency, and interest rate hedge
contracts at December 31, 2001, is disclosed in Note 17 to the annual audited
consolidated financial statements. No new material hedging contracts have been
entered into subsequent to this disclosure.

Note 6. Subsequent Event

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 of PanCanadian and of the common
shareholders and optionholders of AEC, 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"). On completion of the transaction, former PanCanadian shareholders
own approximately 54% and former AEC shareholders own approximately 46% of
EnCana.

Note 7. Reclassification

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


EnCana Corporation (formerly PanCanadian Energy Corporation)
SELECTED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Three months ended March 31, 2002 (unaudited)

Note 8. Consolidated Financial Ratios

The following ratios, based on the consolidated financial statements, are
provided in connection with the Company's continuous offering of medium term
notes and debt securities and are for the twelve-month period then ended.

March 31
-------------------
2002 2001
-------------------------------------------------------------------------
Interest coverage on long-term debt:

Net income excluding carrying charges of
preferred securities 16.3 25.6
Net income including carrying charges of
preferred securities 15.5 23.2

Cash flow excluding carrying charges of
preferred securities 26.1 35.0
Cash flow including carrying charges of
preferred securities 24.7 31.7
>>

Attachment 3

AEC
2002 FIRST QUARTER MD&A

Management's Discussion and Analysis of Financial Condition

SPECIAL NOTE REGARDING FORWARD-LOOKING INFORMATION
In the interest of providing Alberta Energy Company Ltd. ("AEC" or the
"Company") shareholders and potential investors with information regarding the
Company, certain statements throughout this Management's Discussion and
Analysis (the "MD&A") contains certain forward-looking statements within the
meaning of the United States Private Securities Litigation Reform Act of 1995.
Forward-looking statements are typically identified by words such as
"anticipate," "believe," "expect," "plan," "intend," or similar words
suggesting future outcomes or statements regarding an outlook. Forward-looking
statements in this MD&A include, but are not limited to, statements with
respect to: the Company's operating costs, the Company's seismic and drilling
plans, oil and gas prices, per unit netbacks, the Company's oil, liquids and
gas sales, the Company's cash flow from operations and net earnings, the
Company's production levels, the Company's share of Syncrude production,
development plans with respect to the Company's Foster Creek SAGD commercial
project, the timing of the closing of the sale of the Company's Colombian
assets, the impact of hedges on the Company's revenue in a low price
environment, capital investment levels, the sources of funding for capital
investments, the successful integration of the Company's personnel and
businesses with those of PanCanadian Energy Corporation ("PanCanadian") and
the timing thereof, and future operating results and various components
thereof.
Readers are cautioned not to place undue reliance on forward-looking
information, as there can be no assurance that the plans, intentions or
expectations upon which it is based will occur. By its nature, forward-looking
information involves 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. Although AEC 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. Some of the risks
and other factors which could cause results to differ materially from those
expressed in the forward-looking statements contained in this MD&A include,
but are not limited to: volatility of crude oil and natural gas prices,
fluctuations in currency and interest rates, product supply and demand, market
competition, risks inherent in the Company's North American and foreign oil
and gas and midstream operations, risks inherent in the Company's marketing
operations, imprecision of reserves estimates, the Company's ability to
replace and expand oil and gas reserves, the Company's ability to either
generate sufficient cash flow from operations to meet its current and future
obligations or obtain external sources of debt and equity capital, general
economic and business conditions, the Company's ability to enter into or renew
leases, the timing and costs of well and pipeline construction, the Company's
ability to make capital investments and the amounts of capital investments,
imprecision in estimating the timing, costs and levels of production and
drilling, the results of exploration, development and drilling, imprecision in
estimates of future production capacity, the Company's ability to secure
adequate product transportation, uncertainty in the amounts and timing of
royalty payments, imprecision in estimates of product sales, changes in
environmental and other regulations, political and economic conditions in the
countries in which the Company operates including Ecuador, and such other
risks and uncertainties described from time to time in the Company's reports
and filings with the Canadian securities authorities and the United States
Securities and Exchange Commission (the "SEC"). Accordingly, the Company
cautions that events or circumstances could cause actual results to differ
materially from those predicted. Statements relating to "reserves" or
"resources" are deemed to be forward-looking statements, as they involve the
implied assessment, based on certain estimates and assumptions, that the
resources and reserves described can be profitably produced in the future.
Readers are cautioned that the foregoing list of important factors is not
exhaustive. Readers are further cautioned not to place undue reliance on
forward-looking statements contained in this MD&A, which is as of the date
hereof, and the Company undertakes no obligation to update publicly or revise
any forward-looking information, whether as a result of new information,
future events or otherwise. The forward-looking statements contained in this
MD&A are expressly qualified by this cautionary statement.
Management's discussion and analysis of the financial condition and
results of operations is to be read in conjunction with the Interim Unaudited
Consolidated Financial Statements at and for the three months ended March 31,
2002 and Management's Discussion and Analysis and Audited Consolidated
Financial Statements at and for the year ended December 31, 2001.

SUBSEQUENT EVENT
On April 5, 2002, AEC and PanCanadian announced the completed merger of
their two companies, creating EnCana Corporation ("EnCana"). The Court of
Queen's Bench of Alberta approved the plan of arrangement involving AEC, one
day after shareholders and optionholders of AEC and shareholders of
PanCanadian voted 91% and 81%, respectively, in favor of the transaction.
PanCanadian shareholders also approved changing PanCanadian's name to EnCana
Corporation. Under the terms of the merger, AEC shareholders received 1.472
PanCanadian (EnCana after the name change) common shares for each AEC common
share they owned.

CONSOLIDATED SUMMARY
Consolidated Net Earnings for the three months ended March 31, 2002
amounted to $72.0 million, a 78% decrease, or $0.37 per share, diluted ("per
share") compared to $332.6 million, or $2.03 per share, in 2001 (2000 -
$118.8 million; $0.79 per share).
Consolidated Cash Flow from Operations decreased 50% to $405.8 million
for the first three months of 2002, or $2.58 per share, from $809.3 million,
or $5.13 per share, in 2001 (2000 - $367.2 million; $2.56 per share).
Consolidated Revenues, net of royalties and production taxes, totaled
$1,226.3 million in the first quarter of 2002, compared to $2,088.8 million in
2001, a 41% decrease (2000 - $1,019.0 million).

<<
Consolidated Financial Summary First Quarter
---------------------------------------------------------------------
($ million) 2002 2001 2000
---------------------------------------------------------------------

Net Earnings 72.0 332.6 118.8
Cash Flow from Operations 405.8 809.3 367.2
Revenues, net of royalties and
production taxes 1,226.3 2,088.8 1,019.0

Diluted per Share ($ per share)
---------------------------------------------------------------------
Net Earnings 0.37 2.03 0.79
Cash Flow from Operations 2.58 5.13 2.56
---------------------------------------------------------------------
>>

Consolidated Net Revenues decreased primarily as a result of lower
natural gas prices and lower Purchased Gas sales in the first quarter of 2002
compared to the same period in 2001. This decrease was partially offset by
higher produced natural gas volumes sold. Cash Flow from Operations reflects
lower produced gas netbacks, partially offset by lower cash Income Taxes. Net
Earnings includes the impact of higher Deprecation, Depletion and Amortization
as a result of the higher produced natural gas and crude oil volumes sold and
lower future Income Taxes. Interest, net, increased due to higher average long
term debt levels.
Contributions for the past eight quarters are as noted in the following
table:
<<
Quarterly Information
----------------------------------------------------------------------
($ million except per share amounts)
----------------------------------------------------------------------
Year 2002 2001 2001 2001 2001
Quarter Q1 Q4 Q3 Q2 Q1
----------------------------------------------------------------------

Revenues, net of royalties
and production taxes 1,226.3 1,206.4 1,339.2 1,637.9 2,088.8

Net Earnings 72.0 79.8 144.2 267.2 332.6
- per share basic 0.38 0.47 0.90 1.70 2.15
- per share diluted 0.37 0.46 0.87 1.62 2.03

Cash Flow from Operations 405.8 219.3 436.1 557.9 809.3
- per share basic 2.75 1.48 2.96 3.70 5.38
- per share diluted 2.58 1.38 2.66 3.32 5.13

Produced Gas Sales (MMcf/d) 1,639 1,432 1,395 1,241 1,221
Oil and NGL Sales (bbls/d) 129,985 137,125 136,140 135,910 133,118
----------------------------------------------------------------------


Quarterly Information
----------------------------------------------------------------------
($ million except per share amounts
----------------------------------------------------------------------
Year 2000 2000 2000
Quarter Q4 Q3 Q2
----------------------------------------------------------------------

Revenues, net of royalties
and production taxes 2,067.2 1,364.7 1,072.8

Net Earnings 468.8 222.8 111.6
- per share basic 3.12 1.51 0.75
- per share diluted 2.97 1.48 0.73

Cash Flow from Operations 924.9 565.6 377.7
- per share basic 6.32 3.95 2.66
- per share diluted 6.04 3.75 2.54

Produced Gas Sales (MMcf/d) 1,301 1,099 917

Oil and NGL Sales (bbls/d) 128,863 120,220 115,922
----------------------------------------------------------------------
>>
RESULTS OF OPERATIONS: UPSTREAM
For the three months ended March 31, 2002, Upstream revenues, net of
Royalties and production taxes and Transportation and selling expenses,
decreased 49% or $726.9 million, to $756.2 million. This compares to an
increase in 2001 of 105% or $761.1 million, to $1,483.1 million. The
accompanying table shows the details of these changes by product:
<<
Changes in Oil and Natural Gas Revenues
------------------------------------------------------------------------
($ million) 2002 Compared to 2001
------------------------------------------------------------------------
Price Royalties
Factor: Price Hedge Volume & Other Total
------------------------------------------------------------------------
North America
Natural Gas
and NGLs (922.0) 10.6 359.8 134.7 (416.9)

Oil
Conventional 15.3 3.4 13.9 1.0 33.6
Syncrude (25.9) 2.3 (3.0) 12.1 (14.5)

Purchased Gas
Sales (60.4) 29.5 (272.8) - (303.7)

International (9.4) 0.2 (28.8) 12.6 (25.4)
------------------------------------------------------------------------
Total (1,002.4) 46.0 69.1 160.4 (726.9)
------------------------------------------------------------------------


Changes in Oil and Natural Gas Revenues
------------------------------------------------------------------------
($ million) 2001 Compared to 2000
------------------------------------------------------------------------
Price Royalties
Factor: Price Hedge Volume & Other Total
------------------------------------------------------------------------
North America
Natural Gas
and NGLs 686.3 10.9 73.3 (191.0) 579.5

Oil
Conventional (53.5) - 21.4 3.3 (28.8)
Syncrude 6.2 - 28.1 (0.2) 34.1

Purchased Gas
Sales 296.6 (108.4) 7.4 - 195.6

International (62.4) - 28.2 14.9 (19.3)
------------------------------------------------------------------------
Total 873.2 (97.5) 158.4 (173.0) 761.1
------------------------------------------------------------------------
>>
In 2002, the $29.5 million Price Hedge represents payments made by
financial intermediaries for Purchased Gas Sales under floating to fixed price
swap agreements implemented as a part of the Company's risk management
strategy when, at the time of settlement, the market price exceeded the fixed
price contract amount. Contemporaneously, similar quantities of gas were
forward purchased under fixed price agreements, which, upon settlement, were
below market prices in the amount of $1.3 million. For 2002, this strategy
resulted in a net benefit of $15.3 million, net of transportation and selling
expenses of $15.5 million.
In 2001, the Company made $(108.4) million in Price Hedge payments under
floating to fixed price swap agreements. Related fixed price gas purchase
agreements were at below market prices in the amount of $161.6 million and
resulted in a net benefit of $11.6 million, net of transportation and selling
expenses of $41.6 million.

Product Netbacks
The following table summarizes the average net revenue received after
deducting transportation, royalties, production taxes and operating costs
("Netback"), by product, for the last eight quarters:
<<
Year 2002 2001
------------------------------------------------------------------
Quarter Q1 Q4 Q3 Q2 Q1
------------------------------------------------------------------

------------------------------------------------------------------
Canada produced gas
($/Mcf) 2.00 1.84 2.02 4.07 6.79
U.S. produced gas
($/Mcf) 2.15 2.23 2.58 4.54 6.20
North America conventional
oil ($/bbl) 15.79 16.60 17.27 12.69 10.99
North America NGLs
($/bbl) 20.03 17.12 25.35 28.28 30.04
Syncrude ($/bbl) 17.49 26.02 15.23 18.47 18.93
Ecuador oil ($/bbl) 9.24 13.07 13.63 13.77 12.13


Year 2000
--------------------------------------------------------------------
Quarter Q4 Q3 Q2
--------------------------------------------------------------------

--------------------------------------------------------------------
Canada produced gas
($/Mcf) 6.27 3.77 2.84
U.S. produced gas
($/Mcf) 5.45 4.43 4.60
North America conventional
oil ($/bbl) 15.23 25.91 23.26
North America NGLs 34.44 28.39 23.55
($/bbl) 20.82 21.11 18.91
Syncrude ($/bbl) 14.05 18.51 15.70

- Includes hedge impact where applicable
>>

North America Results of Operations
The first quarter North America average produced gas price realized, net
of transportation and selling expense, was $3.23/Mcf, down 65% from $9.33/Mcf
in 2001. A slowing North American economy and warmer than average winter
temperatures resulted in lower demand from virtually all sectors and led to
above average storage inventories contributing to the decline in natural gas
prices. Natural gas liquids prices decreased 36% to $27.49/bbl from $42.96/bbl
in 2001.
North America natural gas production increased to 1,478 MMcf/d, up 21%
from the 2001 total of 1,222 MMcf/d in the first quarter. An additional
161 MMcf/d was withdrawn from inventory, bringing total produced gas sales to
1,639 MMcf/d in 2002 compared to 1,221 MMcf/d in 2001, up 34%.
Benchmark West Texas Intermediate oil prices ("WTI") averaged
US$21.64/bbl in 2002 for the first three months, compared to the 2001 average
of US$28.73/bbl. Light-heavy oil price differentials decreased, returning to
more traditional levels, averaging $7.25/bbl compared to $17.31/bbl in 2001.
During the first quarter of 2002 WTI strengthened from US$19.73/bbl in January
to US$24.44/bbl in March in response to improving supply demand fundamentals
resulting from OPEC production restraint and an improved economic outlook in
North America. Similarly light heavy differentials narrowed over the first
quarter from $9.05/bbl in January to $5.73/bbl in March. This combination has
resulted in significantly improved heavy oil prices.
Total North America liquids sales increased 12% to 91,211 bbls/d in the
first three months of 2002 compared to 81,536 bbls/d in 2001, primarily as a
result of increased conventional crude production in Canada from the Company's
SAGD project at Foster Creek.
During the first quarter of 2002, net capital of $661.6 million was
invested in North America upstream activities, of which $532.4 million was
directed to Canadian operations and $129.2 million to the U.S. operations.

Western Canada
Natural gas prices in Canada averaged $3.20/Mcf, net of transportation
and selling expense, in the first three months, down 66% from $9.37/Mcf in
2001 (2000 - $3.00/Mcf). Natural gas production increased 14% to 1,185 MMcf/d
from 1,044 Mmcf/d in 2001 due to production from the Ladyfern area and
increases in the Greater Sierra area in northeast British Columbia (2000 -
930 MMcf/d). Sales of produced natural gas, which includes the impact of gas
injections and withdrawals from gas storage, increased to 1,346 MMcf/d, up 29%
from 1,043 MMcf/d in the same period of 2001 (2000 - 965 MMcf/d).
Prices for Canadian conventional crude oil averaged $22.81/bbl, net of
transportation and selling expense, and including the impact of price hedges,
a 22% increase from the $18.75/bbl averaged in the first three months of 2001
(2000 - $32.41/bbl). This increase was principally as a result of the decrease
in light-heavy oil price differentials and the benefit from crude oil hedges
which offset a decrease in the WTI average price in the quarter. Prices for
Syncrude oil, net of transportation and selling expense and including the
impact of price hedges, averaged $34.86/bbl compared to $43.17/bbl in 2001, a
19% decrease compared to the 25% decrease in the WTI benchmark price (2000 -
$40.97/bbl). Natural gas liquids prices in Canada decreased to $24.05/bbl from
$43.11/bbl in 2001 (2000 - $34.11/bbl).
In the first three months of 2002, the Company produced an average of
51,104 bbls/d of conventional oil in Canada, compared to 42,856 bbls/d
produced in 2001, an increase of 19% (2000 - 35,372 bbls/d) primarily as a
result of increases from the Foster Creek SAGD project. AEC Syncrude sales
averaged 31,548 bbls/d, a decrease of 2% from the 32,319 bbls/d sold in 2001
(2000 - 24,497 bbls/d). Natural gas liquids volumes in Canada increased to
5,406 bbls/d year to date, from 4,805 bbls/d in 2001 (2000 - 4,808 bbls/d).
Operating costs in Canada increased to $143.6 million for the first three
months of 2002, compared to $135.2 million in 2001 (2000 - $99.7 million).
Higher production volumes resulted in the increase, partially offset by lower
natural gas fuel costs at Syncrude.
Year to date sales of purchased gas decreased to 242 MMcf/d in 2002 from
690 MMcf/d in 2001, (2000 - 878 MMcf/d). Revenue from the sale of purchased
gas, net of transportation and selling expense, amounted to $116.1 million,
down from $419.8 million in 2001 as a result of lower volumes sold and lower
average unit sales prices (2000 - $224.3 million). At March 31, 2002, the
Company had contracts in place to purchase 84.8 Bcf of natural gas over an
eighteen month period. Contracts were also in place to deliver 69.2 Bcf during
the same time frame.
Capital investment focused on exploration and development activities in
the Greater Sierra and Ladyfern areas in northeast British Columbia, and
further development at Suffield, Caribou and Pelican Lake.

U.S. Rockies
Year to date, U.S. natural gas prices, net of transportation and selling
expense, averaged $3.35/Mcf compared to $9.04/Mcf in 2001 which included
$0.73/Mcf related to a mark to market adjustment on acquired fixed priced
contracts. Natural gas sales increased to 293 MMcf/d from 178 MMcf/d in 2001,
reflecting successful ongoing drilling programs, capacity expansion and the
addition of production from Mamm Creek. Natural gas liquids volumes increased
to 3,153 bbls/d at an average price of $33.38/bbl, up from 1,556 bbls/d at
$42.51/bbl in 2001.
Operating costs in the U.S. Rockies increased to $7.8 million for the
first three months of 2002, compared to $5.7 million in 2001. Higher
production volumes and the addition of Mamm Creek contributed to the increase.
Capital investment in the U.S. Rockies amounted to $129.2 million, year
to date, relating to continuing exploration and development of the Jonah and
Mamm Creek fields and the acquisition and evaluation of exploratory lands.

Ecuador Results of Operations
Production from Ecuador averaged 50,351 bbls/d in the first quarter of
2002, down 7%, compared to 53,894 bbls/d in 2001, (2000 - 41,703 bbls/d).
Sales of crude from Ecuador declined to 38,774 bbls/d from 51,512 bbls/d in
2001 primarily as a result of the timing of tanker shipments leaving port.
Ecuador sales volumes remain constrained by available pipeline
transportation which is allocated among shippers based upon the shippers'
productive capacity and the quality of crude oil. The completion of the OCP
pipeline will remove current transportation constraints.
The Ecuador oil price, net of transportation costs, declined in the first
quarter of 2002 to an average of $22.07/bbl, including the impact of allocated
price hedges, compared to $24.71/bbl in 2001 as a result of a lower WTI price
partially offset by narrower light to heavy differentials and allocated price
hedges (2000 - $37.97/bbl). Operating costs in Ecuador increased from
$4.53/bbl in the first quarter of 2001 to $5.78/bbl due to lower sales volumes
and higher personnel costs.
Capital investments in Ecuador amounted to $132.6 million in the first
three months compared to $81.0 million in 2001 and related to continuing
exploration and development operations on the Tarapoa Block and Block 15 in
preparation for substantially increasing production when the OCP pipeline is
completed in 2003.

New Ventures Exploration
Investments in New Ventures Exploration amounted to $22.8 million in the
first three months of 2002 compared to $47.3 million in 2001. The Company has
ongoing exploration in the Gulf of Mexico, Mackenzie Delta, Alaska, the
northwest shelf of Australia and offshore Azerbaijan. During the first quarter
the Company participated in exploration wells in Australia and the Gulf of
Mexico, neither of which yielded commercial quantities of crude oil and both
of which were abandoned. The Company is assessing further drilling in each of
these areas.
During the first quarter of 2002, the Company has also entered into
exploration commitments in Bahrain, Qatar, and Chad, totaling $140 million
over three years.

RESULTS OF OPERATIONS: MIDSTREAM
Midstream revenues decreased 28% to $391.1 million year to date 2002,
compared to $542.5 million in 2001 (2000 - $253.3 million), primarily due to
the impact of lower natural gas prices on sales related to the Gas storage
facility optimization program. Operating Cash Flow decreased 52% from
$104.1 million year to date 2001 to $49.9 million in 2002, as a result of
lower optimization margins realized and to pipeline dispositions in late 2001.

Midstream Capital
Capital investment in Midstream amounted to $10.7 million in the first
three months of 2002, primarily related to ongoing improvements to pipelines
facilities.
Construction of the 450,000 bbls/d OCP pipeline in Ecuador continues with
completion targeted for the second quarter of 2003. To date, $26.5 million has
been invested related to the Company's 31.4% equity interest.

LIQUIDITY AND CAPITAL RESOURCES
Consolidated Cash Flow from Operations totaled $405.8 million in the
first quarter of 2002, (2001 - $809.3 million), of which $386.3 million, or
95% of the total, originated in the Upstream division (2001 - $746.9 million)
and $19.5 million, was provided by the Midstream division (2001 - $62.4
million). Produced natural gas and natural gas liquids sales provided
$256.8 million or 63% of the consolidated total (2001 - $607.8 million), and
crude oil added $117.0 million or 29% (2001 - $137.2 million), including
allocated corporate costs.
Consolidated cash capital investment totaled $714.5 million in 2002, year
to date, in existing core areas (2001 - $963.5 million). An additional
$100.8 million cash was invested in corporate and property acquisitions (2001 -
$482.8 million), while non-core property dispositions amounted to
$35.7 million (2001 - $24.5 million). Total cash net capital investment of
$815.3 million exceeded Cash Flow from Operations by $373.8 million. The
Company utilized long-term debt to fund the difference.
On a consolidated basis, long-term debt held by the Company, which
excludes project financing debt related to the Express System, was
$4,290.6 million at March 31, 2002, up $632.6 million from the December 31,
2001 amount of $3,658.0 million. Total long-term debt, including the project
financing debt of $580.5 million, is $4,871.1 million (2001 -
$4,242.1 million). The Company's unutilized bank credit facilities total
$1.6 billion.
Under its Normal Course Issuer Bid, AEC purchased approximately 431,400
shares, for $24.4 million, at an average price of $56.63 in the first quarter
of 2002.
Also in the first quarter, the Company declared and paid a special Common
Share dividend of forty five ($0.45) cents per Common Share.

RISK MANAGEMENT
The Company's results are influenced by factors such as product prices,
interest and foreign exchange rates, royalties, taxes, operations, and credit
risk.
The Company has entered into various commodity pricing agreements as a
means of managing price volatility. In the first quarter the Company sold
forward an additional 400 MMcf/d of natural gas at fixed prices, bringing the
total volume subject to fixed price contracts to an average of 1 Bcf/d for the
period January to September, 2002. At March 31, 2002 these contracts had an
unrealized mark to market loss of $133 million in Canada and US$27 million on
the U.S. Rockies contracts.
The Company has entered into various financial instruments to manage
price volatility related to its gas storage optimization program, including
futures, fixed-for-floating swaps and basis swaps. On a combined basis, these
instruments had a net unrealized mark to market loss of $23.3 million
partially offset by a net unrealized mark to market gain of $21.4 million on
physical inventory in storage at March 31, 2002.
Foreign exchange contracts in the amount of US$171.2 million have been
entered into to limit U.S. to Canadian exchange rate fluctuations on the
Company's natural gas purchase and sale agreements. At March 31, 2002 these
contracts had an unrealized mark to market loss of $25.0 million.
An active program of monitoring and reporting day-to-day operations is
designed to provide assurance that environmental and regulatory standards are
met. Contingency plans are in place for timely response to an event.

OUTLOOK
The Outlook that follows excludes the impact of the merger transaction
completed April 5, 2002, between AEC and PanCanadian.
The Company's sales forecast for 2002 remains at between 1.525 and
1.575 Bcf/d for produced natural gas and between 142,000 and 153,000 bbls/d of
crude oil. While commodity price volatility is expected to continue throughout
2002, there are positive signs, as a result of an improving North American
economy and the anticipated continuing effectiveness of crude oil supply
management by the OPEC producers. The Company's program of natural gas and
crude oil price hedges are expected to reduce the revenue impact of any
downward trend in prices.
The Company continues to expect capital investment in core programs to be
approximately $2.1 billion before dispositions.
AEC and PanCanadian announced on April 05, 2002, all required approvals
for the merger of the two companies had been received. The combined
organization now operates under the name EnCana Corporation.

April 22, 2002
<<
Consolidated Financial Statements
For the three months ended March 31, 2002
Alberta Energy Company Ltd.


Interim Report Alberta Energy Company Ltd.
For the three months ended March 31, 2002

Consolidated Statement of Earnings Unaudited
($ millions, except per share amounts)
Three Months Ended
---------------------------------
2002 2001 2000
----------------------------------------------------------------------
Revenues, net of
royalties and production taxes $ 1,226.3 $ 2,088.8 $ 1,019.0

Expenses
Transportation and selling 79.0 63.2 43.7
Operating costs 216.5 232.8 154.4
Cost of product purchased 405.9 782.1 407.5
General and administrative 24.2 16.1 10.3
Interest, net (Note 4) 71.8 61.3 35.5
Foreign exchange 0.2 85.8 4.9
Depreciation, depletion and
amortization 314.7 264.3 189.5
----------------------------------------------------------------------
Earnings Before the Undernoted 114.0 583.2 173.2
Minority interest, AEC
Pipelines, L.P. - - 4.7
Income taxes (Note 5) 42.0 250.6 49.7
----------------------------------------------------------------------
Net Earnings 72.0 332.6 118.8
Preferred securities charges,
net of tax 16.0 10.3 5.2
----------------------------------------------------------------------
Net Earnings Attributable to Common
Shareholders $ 56.0 $ 322.3 $ 113.6
----------------------------------------------------------------------
----------------------------------------------------------------------

Earnings per Common Share
Basic $ 0.38 $ 2.15 $ 0.81
Diluted $ 0.37 $ 2.03 $ 0.79
----------------------------------------------------------------------
----------------------------------------------------------------------

Consolidated Statement of Retained Earnings Unaudited
($ millions)
----------------------------------------------------------------------
Balance, Beginning of Year, as
Previously Reported $ 1,788.1 $ 1,264.3 $ 744.7
Retroactive Adjustment for Change in
Accounting Policy (Note 2) - (24.3) 4.3
----------------------------------------------------------------------
Balance, Beginning of Year, as Restated 1,788.1 1,240.0 749.0

Adjustment for Change in
Accounting Policy (Note 2) - - (341.3)
Charges for Normal Course Issuer Bid (15.5) - (3.7)
Net Earnings 72.0 332.6 118.8
----------------------------------------------------------------------
1,844.6 1,572.6 522.8
Common Share Dividends (66.5) - -
Preferred Securities Charges,
Net of Tax (16.0) (10.3) (5.2)
----------------------------------------------------------------------
Balance, End of Period $ 1,762.1 $ 1,562.3 $ 517.6
----------------------------------------------------------------------
----------------------------------------------------------------------


Interim Report Alberta Energy Company Ltd.
For the three months ended March 31, 2002

Consolidated Balance Sheet Unaudited
($ millions)

As at March 31, 2002 As at
------------------------------ December 31,
Upstream Midstream Total 2001
-------------------------------------------------------------------------
Assets
Current Assets
Cash and cash
equivalents $ 21.4 $ 64.5 $ 85.9 $ 104.4
Accounts receivable and
accrued revenue, net 638.4 413.2 1,051.6 983.5
Inventories 159.4 208.5 367.9 320.8
-------------------------------------------------------------------------
819.2 686.2 1,505.4 1,408.7
Capital Assets 11,100.1 1,289.0 12,389.1 11,866.8
Investments and Other Assets 131.3 674.4 805.7 822.0
-------------------------------------------------------------------------
$12,050.6 $ 2,649.6 $14,700.2 $14,097.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Liabilities and Shareholders' Equity
Current Liabilities
Accounts payable and
accrued liabilities $ 877.6 $ 348.0 $ 1,225.6 $ 1,042.8
Income taxes payable 24.5 7.7 32.2 241.6
Current portion of
long-term debt - 24.4 24.4 49.4
-------------------------------------------------------------------------
902.1 380.1 1,282.2 1,333.8
Long-Term Debt (Note 6) 3,583.7 706.9 4,290.6 3,658.0
Project Financing Debt
(Note 7) - 580.5 580.5 584.1
Other Liabilities 157.0 35.9 192.9 204.5
Future Income Taxes 2,102.2 304.1 2,406.3 2,360.5
-------------------------------------------------------------------------
6,745.0 2,007.5 8,752.5 8,140.9
Shareholders' Equity
Preferred securities 854.4 858.8
Share capital (Note 8) 3,073.8 3,052.3
Retained earnings 1,762.1 1,788.1
Foreign currency
translation adjustment 257.4 257.4
-------------------------------------------------------------------------
5,305.6 642.1 5,947.7 5,956.6
-------------------------------------------------------------------------
$12,050.6 $ 2,649.6 $14,700.2 $14,097.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Interim Report
For the three months ended March 31, 2002

Consolidated Statement of Cash Flows Unaudited
($ millions, except per share amounts)
Three Months Ended
---------------------------------
2001 2000 1999
----------------------------------------------------------------------
Operating Activities
Net earnings $ 72.0 $ 332.6 $ 118.8
Depreciation, depletion and
amortization 314.7 264.3 189.5
Future income taxes 15.8 134.5 46.8
Minority interest, AEC Pipelines, L.P. - - 4.7
Other 3.3 77.9 7.4
----------------------------------------------------------------------
Cash Flow from operations 405.8 809.3 367.2
Net change in non-cash
working capital (244.0) 317.4 (24.5)
----------------------------------------------------------------------
161.8 1,126.7 342.7
----------------------------------------------------------------------
Investing Activities
Corporate acquisitions (Note 3) - (435.0) -
Capital investment (815.3) (984.8) (367.5)
Equity investments - (26.5) -
Proceeds on disposal of assets 35.7 24.5 6.0
Investments and other (13.4) 8.3 (0.6)
Net change in non-cash working capital 105.8 240.3 39.2
----------------------------------------------------------------------
(687.2) (1,173.2) (322.9)
----------------------------------------------------------------------
(Decrease) increase in Cash
and Cash Equivalents Before
Financing Activities (525.4) (46.5) 19.8
----------------------------------------------------------------------
Financing Activities
Net issue of long-term debt 603.4 29.6 35.5
Issue of common shares 30.4 20.8 9.1
Purchase of common shares (Note 8) (24.4) - (7.0)
Common share dividends (66.5) - -
Payments to preferred securities
holders (10.7) (10.3) (5.2)
AEC Pipelines, L.P. distributions - - (6.1)
Net change in non-cash working capital (12.3) (8.3) (4.2)
Other (13.0) 32.7 (12.3)
----------------------------------------------------------------------
506.9 64.5 9.8
----------------------------------------------------------------------
(Decrease) increase in Cash
and Cash Equivalents (18.5) 18.0 29.6
Cash and Cash Equivalents,
Beginning of Period 104.4 44.6 68.6
----------------------------------------------------------------------
Cash and Cash Equivalents,
End of Period $ 85.9 $ 62.6 $ 98.2
----------------------------------------------------------------------
----------------------------------------------------------------------

Cash Flow from Operations per Common Share
Basic $ 2.75 $ 5.38 $ 2.60
Diluted $ 2.58 $ 5.13 $ 2.56
----------------------------------------------------------------------
----------------------------------------------------------------------
>>

Interim Report
For the three months ended March 31, 2002

Notes to Consolidated Financial Statements

1. Basis of Presentation
The Company organizes its operations into two business groups. Upstream
includes the Company's North America and International exploration for, and
production of, natural gas and crude oil. Midstream includes both the
Pipelines and Processing operations and the Gas Storage operations. These
interim consolidated financial statements have been prepared on the same basis
as the audited consolidated financial statements as at and for the year ended
December 31, 2001.

2. Change in Accounting Policy
Effective December 31, 2001, the Company adopted the new Canadian
accounting standard for foreign currency translation and, as required by the
standard, all prior periods have been restated. The net earnings impact of
this change is included in foreign exchange and income taxes on the
Consolidated Statement of Earnings.
Effective January 1, 2000, the Company adopted, retroactively without
restating prior periods, the liability method of accounting for income taxes
as recommended by the Canadian Institute of Chartered Accountants ("CICA").
The Company adopted the recommendations by recording additional capital assets
of $273.3 million; a decrease in retained earnings of $341.3 million and an
increase in the future income tax liability of $614.6 million.

3. Corporate Acquisitions
On February 2, 2001, the Company acquired all of the issued and
outstanding shares of Ballard Petroleum, LLC (Ballard) for net cash
consideration of approximately $328.4 million. Ballard is engaged in the
exploration for, and production of, natural gas and operates a natural gas
pipeline in the United States.
In February 2001, the Company acquired a 36% equity interest in Oleoducto
Trasandino (Trasandino) for net cash consideration of US$64.3 million. The
Trasandino system transports crude oil from Argentina to refineries in Chile.

<<
4. Interest, Net For the three months ended March 31
2002 2001 2000
($ millions)
Interest expense - long-term debt 73.5 63.9 38.0
Interest expense - other 4.6 3.0 1.2
Interest income (6.3) (2.1) 0.8
---------------------------------
71.8 64.8 40.0
Less: Capitalized interest - 3.5 4.5
---------------------------------
Interest, net 71.8 61.3 35.5
---------------------------------
---------------------------------

5. Income Taxes For the three months ended March 31
The provision for income
taxes is as follows: 2002 2001 2000
Current ($ millions)
Canada 24.9 104.3 2.4
United States - 7.0 -
Ecuador 1.3 4.4 0.5
Other - 0.4 -
---------------------------------
26.2 116.1 2.9
Future 15.8 134.5 46.8
---------------------------------
Income taxes 42.0 250.6 49.7
---------------------------------
---------------------------------

6. Long-Term Debt March 31, December 31,
2002 2001
Upstream ($ millions)
Canadian Dollar debt 1,560.1 1,165.2
US Dollar debt (US$1,269.9) 2,023.6 1,907.9
------------------------
3,583.7 3,073.1
Midstream
Canadian Dollar debt 706.9 584.9
------------------------
4,290.6 3,658.0
------------------------
------------------------

>>
7. Project Financing Debt
The Express Pipeline System has outstanding US$132.7 million aggregate
principal amount of senior secured notes due 2013 bearing interest at 6.47%
and US$246.9 million aggregate principal amount of subordinated secured notes
due 2019 bearing interest at 7.39% which are non-recourse to the Company. The
notes are secured by the assignment of the accounts receivable of Express
Pipeline System and a floating charge over the assets of the Canadian portion
of the Express System.

<<
8. Share Capital (millions) March 31, 2002 December 31, 2001
Number Amount Number Amount
------ ------ ------ ------
Common shares outstanding,
beginning of period 147.9 $3,052.3 149.9 $3,077.4
Shares repurchased (0.5) (8.9) (3.6) (73.2)
Employee share option plan 0.9 29.0 1.5 45.9
Shareholder Investment Plan - 1.4 0.1 2.2
------ -------- ------ --------
Common shares outstanding,
end of period 148.3 $3,073.8 147.9 $3,052.3
------ -------- ------ --------
>>
During the period, the Company has purchased approximately 0.5 million of
its Common Shares for total consideration of $24.4 million, resulting in a
reduction of share capital of $8.9 million and a charge to retained earnings
of $15.5 million.
The following table summarizes the information about options to purchase
Common Shares:

<<
March 31, 2002 December 31, 2001
Weighted Weighted
Average Average
Share Exercise Share Exercise
Options Price ($) Options Price ($)
------- --------- ------- ---------
Outstanding,
beginning of period 9.9 45.60 8.7 35.21
Granted - 58.20 3.1 66.82
Exercised (0.9) 32.61 (1.5) 29.88
Forfeited - 49.48 (0.4) 44.76
------- -------
Outstanding, end of period 9.0 46.96 9.9 45.60
------- -------
>>
The Company accounts for its stock-based compensation plans using the
intrinsic-value method whereby no costs have been recognized in the financial
statements for share options granted to employees and directors. As now
required by Canadian Generally Accepted Accounting Principles, the impact on
compensation costs of using the fair value method, whereby compensation costs
had been recorded in net earnings, must be disclosed. 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:
<<
2002 2001 2000
---- ---- ----
Compensation Costs 7.7 6.3 5.9

Net Earnings:
As reported 72.0 332.6 118.8
Pro forma 64.3 326.3 112.9

Net Earnings per Common Share:
Basic
As reported 0.38 2.15 0.81
Pro forma 0.33 2.10 0.76
Diluted
As reported 0.37 2.03 0.79
Pro forma 0.32 1.99 0.75

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:

Risk free interest rate 3.53% 3.53% 6.02%
Expected lives (years) 4.00 4.00 4.00
Expected volatility 0.32 0.38 0.41
Dividend per share $ 0.60 $ 0.60 $ 0.40


9. Segmented Information ($ millions)

(a) Results of Operations Western Canada
------------------------------------------
2002 2001 2000
-------------------------------------------------------------------
Gross Revenues $ 783.1 $ 1,566.0 $ 741.1
Royalties 90.5 225.7 79.6
Production Taxes - - -
-------------------------------------------------------------------
Net Revenues 692.6 1,340.3 661.5
Transportation and Selling 60.2 44.1 36.5
Operating Costs 143.6 135.2 99.7
Cost of Product Purchased 99.8 405.1 222.5
-------------------------------------------------------------------
Operating Cash Flow 389.0 755.9 302.8
DD&A 195.7 151.0 122.3
DD&A - Acquisitions 22.7 21.9 22.7
-------------------------------------------------------------------
Segment Income $ 170.6 $ 583.0 $ 157.8
-------------------------------------------------------------------
-------------------------------------------------------------------

Capital Assets - Canada
(including New Ventures) $ 7,179.7 $ 6,342.1 $ 4,955.2
-------------------------------------------------------------------


(a) Results of Operations U.S. Rockies
------------------------------------------
2002 2001 2000
-------------------------------------------------------------------
Gross Revenues $ 104.7 $ 154.8 $ -
Royalties 18.9 28.4 -
Production Taxes 7.6 13.2 -
-------------------------------------------------------------------
Net Revenues 78.2 113.2 -
Transportation and Selling 6.8 4.1 -
Operating Costs 7.8 5.7 -
Cost of Product Purchased - - -
-------------------------------------------------------------------
Operating Cash Flow 63.6 103.4 -
DD&A 16.6 9.0 -
DD&A - Acquisitions 24.5 20.5 -
-------------------------------------------------------------------
$ 22.5 $ 73.9 $ -
-------------------------------------------------------------------
-------------------------------------------------------------------
Capital Assets - United States
(including New Ventures) $ 1,913.3 $ 1,569.5 $ 8.4
-------------------------------------------------------------------
-------------------------------------------------------------------

North America Total
------------------------------------------
2002 2001 2000
-------------------------------------------------------------------
Gross Revenues $ 887.8 $ 1,720.8 $ 741.1
Royalties 109.4 254.1 79.6
Production Taxes 7.6 13.2 -
-------------------------------------------------------------------
Net Revenues 770.8 1,453.5 661.5
Transportation and Selling 67.0 48.2 36.5
Operating Costs 151.4 140.9 99.7
Cost of Product Purchased 99.8 405.1 222.5
-------------------------------------------------------------------
Operating Cash Flow 452.6 859.3 302.8
DD&A 212.3 160.0 122.3
DD&A - Acquisitions 47.2 42.4 22.7
-------------------------------------------------------------------
Segment Income $ 193.1 $ 656.9 $ 157.8
-------------------------------------------------------------------
-------------------------------------------------------------------

-------------------------------------------------------------------
Capital Assets - Canada
(including New Ventures) $ 7,179.7 $ 6,342.1 $ 4,955.2
- United States
(including New Ventures) $ 1,913.3 $ 1,569.5 $ 8.4
-------------------------------------------------------------------
-------------------------------------------------------------------


Ecuador - Crude Oil
------------------------------------------
2002 2001 2000
-------------------------------------------------------------------
Gross Revenues $ 89.0 $ 129.5 $ 151.2
Royalties 24.6 37.3 51.6
Production Taxes - - -
-------------------------------------------------------------------
Net Revenues 64.4 92.2 99.6
Transportation and Selling 12.0 15.0 7.2
Operating Costs 20.1 21.0 12.2
Cost of Product Purchased - - -
-------------------------------------------------------------------
Operating Cash Flow 32.3 56.2 80.2
DD&A 21.9 25.4 18.6
DD&A - Acquisitions 11.4 13.5 10.0
-------------------------------------------------------------------
Segment Income $ (1.0) $ 17.3 $ 51.6
-------------------------------------------------------------------
-------------------------------------------------------------------

-------------------------------------------------------------------
Capital Assets $ 1,829.8 $ 1,476.5 $ 1,124.4
-------------------------------------------------------------------
-------------------------------------------------------------------


International New Ventures
------------------------------------------
2002 2001 2000
-------------------------------------------------------------------
Gross Revenues $ - $ 0.7 $ 5.2
Royalties - 0.1 0.6
Production Taxes - - -
-------------------------------------------------------------------
Net Revenues - 0.6 4.6
Transportation and Selling - - -
Operating Costs 9.9 9.5 8.9
Cost of Product Purchased - - -
-------------------------------------------------------------------
Operating Cash Flow (9.9) (8.9) (4.3)
DD&A 0.8 0.7 1.6
DD&A - Acquisitions - - -
-------------------------------------------------------------------
Segment Income $ (10.7) $ (9.6) $ (5.9)
-------------------------------------------------------------------
-------------------------------------------------------------------

-------------------------------------------------------------------
Capital Assets $ 177.3 $ 169.1 $ 148.1
-------------------------------------------------------------------
-------------------------------------------------------------------


International Total
------------------------------------------
2002 2001 2000
-------------------------------------------------------------------
Gross Revenues $ 89.0 $ 130.2 $ 156.4
Royalties 24.6 37.4 52.2
Production Taxes - - -
-------------------------------------------------------------------
Net Revenues 64.4 92.8 104.2
Transportation and Selling 12.0 15.0 7.2
Operating Costs 30.0 30.5 21.1
Cost of Product Purchased - - -
-------------------------------------------------------------------
Operating Cash Flow 22.4 47.3 75.9
DD&A 22.7 26.1 20.2
DD&A - Acquisitions 11.4 13.5 10.0
-------------------------------------------------------------------
Segment Income $ (11.7) $ 7.7 $ 45.7
-------------------------------------------------------------------
-------------------------------------------------------------------

-------------------------------------------------------------------
Capital Assets $ 2,007.1 $ 1,645.6 $ 1,272.5
-------------------------------------------------------------------
-------------------------------------------------------------------

Upstream Total
------------------------------------------
2002 2001 2000
-------------------------------------------------------------------
Gross Revenues $ 976.8 $ 1,851.0 $ 897.5
Royalties 134.0 291.5 131.8
Production Taxes 7.6 13.2 -
-------------------------------------------------------------------
Net Revenues 835.2 1,546.3 765.7
Transportation and Selling 79.0 63.2 43.7
Operating Costs 181.4 171.4 120.8
Cost of Product Purchased 99.8 405.1 222.5
-------------------------------------------------------------------
Operating Cash Flow 475.0 906.6 378.7
DD&A 235.0 186.1 142.5
DD&A - Acquisitions 58.6 55.9 32.7
-------------------------------------------------------------------
Segment Income 181.4 664.6 203.5
Less: Corporate Costs
General and administrative 20.6 11.4 8.3
Corporate DD&A 2.6 2.7 2.6
Interest, net 44.9 32.8 27.8
Foreign exchange 0.4 54.9 3.7
Income taxes 41.5 239.7 46.9
-------------------------------------------------------------------
Net Earnings $ 71.4 $ 323.1 $ 114.2
-------------------------------------------------------------------
-------------------------------------------------------------------

-------------------------------------------------------------------
Capital Assets $11,100.1 $ 9,557.2 $ 6,236.1
-------------------------------------------------------------------
-------------------------------------------------------------------




Pipelines and Processing
------------------------------------------
2002 2001 2000
-------------------------------------------------------------------
Gross Revenues $ 279.3 $ 286.1 $ 162.8
Royalties - - -
Production Taxes - - -
-------------------------------------------------------------------
Net Revenues 279.3 286.1 162.8
Transportation and Selling - - -
Operating Costs 25.2 51.2 27.9
Cost of Product Purchased 216.8 184.7 109.1
-------------------------------------------------------------------
Operating Cash Flow 37.3 50.2 25.8
DD&A 12.7 14.8 9.1
DD&A - Acquisitions 1.9 1.9 -
-------------------------------------------------------------------
Segment Income $ 22.7 $ 33.5 $ 16.7
-------------------------------------------------------------------
-------------------------------------------------------------------

-------------------------------------------------------------------
Capital Assets - Canada $ 335.1 $ 973.2 $ 443.1
- United
States $ 679.1 $ 1,039.1 $ 370.3
-------------------------------------------------------------------
-------------------------------------------------------------------


Gas Storage
------------------------------------------
2002 2001 2000
-------------------------------------------------------------------
Gross Revenues $ 111.8 $ 256.4 $ 90.5
Royalties - - -
Production Taxes - - -
-------------------------------------------------------------------
Net Revenues 111.8 256.4 90.5
Transportation and Selling - - -
Operating Costs 9.9 10.2 5.7
Cost of Product Purchased 89.3 192.3 75.9
-------------------------------------------------------------------
Operating Cash Flow 12.6 53.9 8.9
DD&A 3.4 2.7 2.4
DD&A - Acquisitions - - -
-------------------------------------------------------------------
Segment Income $ 9.2 $ 51.2 $ 6.5
-------------------------------------------------------------------
-------------------------------------------------------------------

-------------------------------------------------------------------
Capital Assets - Canada $ 139.9 $ 134.3 $ 129.6
- United
States $ 134.9 $ 132.5 $ 63.2
-------------------------------------------------------------------
-------------------------------------------------------------------



Midstream Total
------------------------------------------
2002 2001 2000
-------------------------------------------------------------------
Gross Revenues $ 391.1 $ 542.5 $ 253.3
Royalties - - -
Production Taxes - - -
-------------------------------------------------------------------
Net Revenues 391.1 542.5 253.3
Transportation and Selling - - -
Operating Costs 35.1 61.4 33.6
Cost of Product Purchased 306.1 377.0 185.0
-------------------------------------------------------------------
Operating Cash Flow 49.9 104.1 34.7
DD&A 16.1 17.5 11.5
DD&A - Acquisitions 1.9 1.9 -
-------------------------------------------------------------------
Segment Income 31.9 84.7 23.2
Less: Corporate Costs
General and administrative 3.6 4.7 2.0
Corporate DD&A 0.5 0.2 0.2
Interest, net 26.9 28.5 7.7
Foreign exchange (0.2) 30.9 1.2
Minority Interest - - 4.7
Income taxes 0.5 10.9 2.8
-------------------------------------------------------------------
Net Earnings $ 0.6 $ 9.5 $ 4.6
-------------------------------------------------------------------
-------------------------------------------------------------------

-------------------------------------------------------------------
Capital Assets - Canada $ 475.0 $ 1,107.5 $ 572.7
- United
States $ 814.0 $ 1,171.6 $ 433.5
-------------------------------------------------------------------
-------------------------------------------------------------------


Consolidated Total
------------------------------------------
2002 2001 2000
-------------------------------------------------------------------
Gross Revenues $ 1,367.9 $ 2,393.5 $ 1,150.8
Royalties 134.0 291.5 131.8
Production Taxes 7.6 13.2 -
-------------------------------------------------------------------
Net Revenues 1,226.3 2,088.8 1,019.0
Transportation and Selling 79.0 63.2 43.7
Operating Costs 216.5 232.8 154.4
Cost of Product Purchased 405.9 782.1 407.5
-------------------------------------------------------------------
Operating Cash Flow 524.9 1,010.7 413.4
DD&A 251.1 203.6 154.0
DD&A - Acquisitions 60.5 57.8 32.7
-------------------------------------------------------------------
Segment Income 213.3 749.3 226.7
Less: Corporate Costs
General and administrative 24.2 16.1 10.3
Corporate DD&A 3.1 2.9 2.8
Interest, net 71.8 61.3 35.5
Foreign exchange 0.2 85.8 4.9
Minority Interest - - 4.7
Income taxes 42.0 250.6 49.7
-------------------------------------------------------------------
Net Earnings $ 72.0 $ 332.6 $ 118.8
-------------------------------------------------------------------
-------------------------------------------------------------------


(b) Net Capital Investment(*)

2002 2001 2000
Upstream
North America
Conventional $ 633.0 $ 745.6 $ 301.0
Syncrude 39.6 15.9 19.5
International 138.8 97.3 28.7
Midstream
Pipelines and Processing 8.4 50.2 6.5
Gas Storage 2.3 70.5 3.5
Other 5.6 7.3 2.3
---------------------------------------
Total $ 827.7 $ 986.8 $ 361.5
---------------------------------------
---------------------------------------

(*) excludes corporate acquisitions and corporate dispositions


(c) Geographic and Product Information

The following tables provide additional product and geographic
information for Upstream North America and Midstream not provided
in Note (a) Results of Operations:

Upstream North America Natural Gas and NGLs
---------------------------------------
Western Canada
2002 2001 2000
-------------------------------------------------------------------------
Gross Revenues $ 431.0 $ 926.0 $ 297.7
Royalties 81.3 203.3 54.1
Production Taxes - - -
-------------------------------------------------------------------------
Net Revenues 349.7 722.7 243.6
Transportation and Selling 28.5 22.3 13.6
Operating Costs 70.5 50.5 38.1
Cost of Product Purchased - - -
-------------------------------------------------------------------------
Operating Cash Flow $ 250.7 $ 649.9 $ 191.9
--------------------------------------------------------------------------
--------------------------------------------------------------------------

United States
2002 2001 2000
--------------------------------------------------------------------------
Gross Revenues $ 104.7 $ 154.8 $ -
Royalties 18.9 28.4 -
Production Taxes 7.6 13.2 -
--------------------------------------------------------------------------
Net Revenues 78.2 113.2 -
Transportation and Selling 6.8 4.1 -
Operating Costs 7.8 5.7 -
Cost of Product Purchased - - -
--------------------------------------------------------------------------
Operating Cash Flow $ 63.6 $ 103.4 $ -
--------------------------------------------------------------------------
--------------------------------------------------------------------------

Purchased Gas - Canada
2002 2001 2000
--------------------------------------------------------------------------
Gross Revenues $ 141.4 $ 435.0 $ 242.4
Royalties - - -
Production Taxes - - -
--------------------------------------------------------------------------
Net Revenues 141.4 435.0 242.4
Transportation and Selling 25.3 15.2 18.1
Operating Costs 0.2 6.9 1.9
Cost of Product Purchased 99.8 405.1 222.5
--------------------------------------------------------------------------
Operating Cash Flow $ 16.1 $ 7.8 $ (0.1)
--------------------------------------------------------------------------
--------------------------------------------------------------------------



Crude Oil
---------------------------------------
Western Canada
2002 2001 2000
-------------------------------------------------------------------------
Gross Revenues $ 110.8 $ 77.0 $ 108.2
Royalties 9.9 10.9 14.2
-------------------------------------------------------------------------
Net Revenues 100.9 66.1 94.0
Transportation and Selling 5.9 4.7 3.8
Operating Costs 22.5 19.0 14.4
-------------------------------------------------------------------------
Operating Cash Flow $ 72.5 $ 42.4 $ 75.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Syncrude - Canada
2002 2001 2000
-------------------------------------------------------------------------
Gross Revenues $ 99.9 $ 128.0 $ 92.8
Royalties (0.7) 11.5 11.3
-------------------------------------------------------------------------
Net Revenues 100.6 116.5 81.5
Transportation and Selling 0.5 1.9 1.0
Operating Costs 50.4 58.8 45.3
-------------------------------------------------------------------------
Operating Cash Flow $ 49.7 $ 55.8 $ 35.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Midstream - Pipelines and Processing
Canada
2002 2001 2000
-------------------------------------------------------------------------
Gross Revenues $ 245.4 $ 238.3 $ 139.8
Operating Costs 10.6 29.6 18.1
Cost of Product Purchased 204.7 176.2 99.3
-------------------------------------------------------------------------
Operating Cash Flow $ 30.1 $ 32.5 $ 22.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------

United States
2002 2001 2000
-------------------------------------------------------------------------
Gross Revenues $ 33.9 $ 47.8 $ 23.0
Operating Costs 14.6 21.6 9.8
Cost of Product Purchased 12.1 8.5 9.8
-------------------------------------------------------------------------
Operating Cash Flow $ 7.2 $ 17.7 $ 3.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Midstream - Gas Storage
Canada
2002 2001 2000
-------------------------------------------------------------------------
Gross Revenues $ 47.0 $ 159.3 $ 71.2
Operating Costs 4.0 7.8 3.6
Cost of Product Purchased 38.2 122.0 59.7
-------------------------------------------------------------------------
Operating Cash Flow $ 4.8 $ 29.5 $ 7.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------

United States
2002 2001 2000
-------------------------------------------------------------------------
Gross Revenues $ 64.8 $ 97.1 $ 19.3
Operating Costs 5.9 2.4 2.1
Cost of Product Purchased 51.1 70.3 16.2
-------------------------------------------------------------------------
Operating Cash Flow $ 7.8 $ 24.4 $ 1.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------


(d) Total Assets 2002 2001 2000
---------------------------------------
Upstream
North America
Conventional $ 9,036.7 $ 8,210.9 $ 4,887.0
Syncrude 777.2 650.3 584.0
International 2,236.7 1,844.9 1,468.5
Midstream
Pipelines and Processing 1,951.2 2,534.2 1,195.0
Gas Storage 698.4 318.7 103.5
---------------------------------------
Total $ 14,700.2 $ 13,559.0 $ 8,238.0
---------------------------------------
---------------------------------------

>>
10. Subsequent Event

On January 27, 2002, AEC and PanCanadian Energy Corporation
("PanCanadian") 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 of 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"). On completion of the transaction, former AEC shareholders own
approximately 46% and former PanCanadian shareholders own approximately 54% of
EnCana.
Investor Contact:
EnCana Corporate Development Sheila McIntosh
Senior Vice-President, Investor Relations


(403) 290-2194
investor.relations@EnCana.com

Greg Kist
(403) 266-8495

Media Contact:
Alan Boras
(403) 266-8300

ECA stock price

TSX $14.90 Can -0.220

NYSE $11.65 USD -0.200

As of 2017-11-20 10:09. Minimum 15 minute delay