EnCana's first quarter operating earnings reach US$465 million, net earnings were US$290 million, cash flow nears US$1 billion

Oil and natural gas sales up 14 percent to 717,000 barrels of oil equivalent per day

CALGARY, April 28 /CNW/ - EnCana Corporation's (TSX & NYSE: ECA) first
quarter 2004 operating earnings were US$465 million, or $1.00 per share
diluted, down 9 percent from $510 million in the first quarter of 2003 due
largely to lower realized natural gas and oil prices. First quarter cash flow
was $995 million, or $2.13 per share diluted. Sales of oil, natural gas and
natural gas liquids (NGLs) increased 14 percent in the first quarter to
717,000 barrels of oil equivalent (BOE) per day.
"Our first quarter 2004 operational performance is firmly on plan and our
financial results remain solid. Continued strong gas production growth from
resource plays in Western Canada and the U.S. Rockies, plus strong oil
production increases from Ecuador and our steam-assisted gravity drainage
projects in northeast Alberta, is anchoring our sustained growth and value
creation," said Gwyn Morgan, EnCana's President & Chief Executive Officer.
EnCana's first quarter operating earnings exclude the after-tax impacts
of foreign exchange on translation of U.S. dollar denominated debt issued in
Canada, mark-to-market unrealized losses related to financial derivatives and
the impact of tax changes recently enacted in Alberta. After these accounting
adjustments, net earnings in the first quarter were $290 million, or 62 cents
per share diluted. First quarter earnings were reduced by $252 million,
after-tax, as a result of the adoption of the new accounting standard
governing hedging relationships. The depreciation of the Canadian dollar
versus the U.S. dollar since December 31, 2003 resulted in a further reduction
in earnings of $32 million, after-tax, on translation of U.S. dollar
denominated debt issued in Canada. The effect of recent Alberta income tax
changes increased earnings by $109 million. First quarter cash flow of
$995 million includes a cash tax provision of $232 million, which is
consistent with the company's 2004 guidance. All figures are in U.S. dollars
unless otherwise noted.

Change in accounting policy for unrealized hedging losses impacts
earnings
On January 1, 2004, EnCana was required to adopt the new accounting
standard governing hedging activities. In addition to the first quarter
impact, EnCana expects that this new standard will continue to result in
greater volatility in its reported net earnings. Implementation of this
accounting standard resulted in the company recording an unrealized after-tax
mark-to-market loss of $252 million in the quarter on the portfolio of its
financial derivatives, commonly known as financial price hedges. A complete
discussion of the impact of this new accounting standard is contained in Notes
2 and 13 of the unaudited first quarter consolidated financial statements.

Gas production up 10 percent in past year; oil and NGLs sales up
34 percent
EnCana's first quarter natural gas sales were 2.7 billion cubic feet per
day, up 5 percent compared with the first quarter of 2003 when 120 million
cubic feet per day of previously produced gas was withdrawn from storage. Gas
production was up 10 percent during the period compared to the same period in
2003. Oil and NGLs sales grew 34 percent to 265,000 barrels per day. Operating
costs were $3.53 per BOE, which was slightly higher than forecast due
primarily to the effect of the weaker U.S. dollar on non-U.S. operating costs
and colder weather. For the full year, the company expects operating costs to
be in its forecast range of between $3.30 and $3.50 per BOE. The first quarter
capital program was $1.5 billion. Net divestitures of about $300 million
reduced investment to $1.2 billion of net capital.
"Effective field execution and cooperative winter weather allowed the
company to complete its entire winter drilling program, a substantial
improvement over the previous winter, which was hampered by a late start and
an early break-up. EnCana drilled 1,619 net wells during the first quarter,
about one-third of its full year estimate of 5,000 wells. Production volumes
in April have averaged near the high end of our 2004 sales guidance range,"
Morgan said.

Advancing the focus on long-life resource plays
EnCana continues to focus its North American asset base on low production
cost, low-decline-rate resource plays that have long-term predictable reserve
and production growth potential. The U.S. Rockies is EnCana's fastest growing
region and, with the anticipated acquisition of Tom Brown, Inc., the company's
U.S. production is expected to be about 1 billion cubic feet equivalent per
day, representing close to one-quarter of total production. The combination of
Tom Brown's resource plays and the planned sale of some of EnCana's
non-resource play conventional production is expected to increase resource
play production to about three-quarters of total North American production by
year-end, up from about two-thirds.
"We continue to add to our strong portfolio of predictable, steady-growth
resource plays. Over the past 18 months, we added about 500,000 net acres -
containing huge undeveloped gas potential - with our Cutbank Ridge land
acquisition, expanded our pursuit of coalbed methane resources on our
expansive fee title lands east of Calgary and now plan to add about 2 million
net acres containing major undeveloped resource potential through the Tom
Brown purchase. Given EnCana U.S.A.'s track record on similar properties in
the U.S. Rockies, such as Mamm Creek in Colorado and Jonah in Wyoming, we are
confident that there is substantial growth potential residing in these early-
life resource plays," Morgan said.

2004 guidance confirmed, conventional production divestiture program
stepped up
EnCana is on track to meet its 2004 sales guidance of between 690,000 and
735,000 BOE per day, comprised of between 2.7 billion and 2.85 billion cubic
feet of natural gas per day and between 240,000 and 260,000 barrels of oil and
NGLs per day. Upon the anticipated successful completion of the acquisition of
Tom Brown, production is expected to increase by about 325 million cubic feet
equivalent per day. As a second step in EnCana's advancement of its resource
play strategy, the company plans, over the next 12 months, to sell
conventional assets currently producing between 40,000 and 60,000 BOE per day
for estimated proceeds of $1 billion to $1.5 billion. The net impact of these
transactions is expected to be accretive to production, cash flow and earnings
in 2004 and beyond.

Risk management strategy
EnCana employs a consistent market risk mitigation strategy that is
expected to be approximately revenue neutral over the long term. This
volatility reduction strategy is intended to result in greater predictability
of cash flow and returns on capital investment. The corporation's basic
strategy is to hedge up to 50 percent of current year and up to 25 percent of
the following year's projected sales. In addition, the company enters into
longer term basis and pricing hedges specifically for the purpose of
protecting against high U.S. Rockies gas price basis differentials. EnCana has
about 47 percent of projected 2004 gas sales, after royalties, hedged at an
average effective NYMEX price of about $5.25 per thousand cubic feet. About
half of EnCana's projected 2004 oil sales are hedged with swaps or subject to
costless collars between $20 and $26 per barrel of WTI. The detailed risk
management positions at March 31, 2004 are presented in Note 13 to the
unaudited first quarter consolidated financial statements for the financial
contracts and in management's discussion and analysis for the physical
contracts. In the first quarter, EnCana's financial commodity and currency
risk management measures resulted in gross revenue being lower by
approximately $150 million, comprised of $130 million on oil sales and
$20 million on gas sales.

EnCana's realized natural gas prices down slightly, realized oil prices
down
EnCana's first quarter realized North American natural gas prices were
down about 4 percent from the first quarter of 2003 to $5.26 per thousand
cubic feet. Realized oil and NGLs prices were down about 6 percent from the
first quarter of 2003 to $25.23 per barrel. Canadian heavy oil price
differentials widened to average $9.03 per barrel compared to $7.58 per barrel
one year earlier. Ecuadorian NAPO blend, shipped on the new OCP Pipeline,
experienced a wider price differential from WTI in the first quarter of 2004,
averaging $11.65 per barrel, compared to $8.06 per barrel at year-end 2003.
OCP began full operations in the fourth quarter of 2003.


Consolidated EnCana Highlights
------------------------------
US$ and U.S. protocols
----------------------

-------------------------------------------------------------------------
Financial Highlights
(as at and for the period
ended March 31) %
(US$ millions, except per share amounts) Q1 2004 Q1 2003 Change
-------------------------------------------------------------------------
Revenues, net of royalties 2,850 2,743 + 4

Cash flow 995 1,221 - 19
Per share - basic 2.16 2.54 - 15
Per share - diluted 2.13 2.52 - 15

Operating EBITDA(*) 1,305 1,273 + 3

Cash tax 232 20 n/a

Earnings
Net earnings from continuing operations 290 650 - 55
Per share - basic 0.63 1.35 - 53
Per share - diluted 0.62 1.34 - 54
Add back:
---------
Mark-to-market impact (after-tax) 252 - n/a
Add back:
---------
Foreign exchange translation of U.S.
dollar debt issued in Canada (after-tax) 32 (140) - 123
Less:
-----
Tax rate change (109) - n/a

Operating earnings 465 510 - 9
Per share - basic 1.01 1.06 - 5
Per share - diluted 1.00 1.05 - 5
Net capital investment - continuing operations 1,225 1,120 + 9

Total assets 24,808
Long-term debt 6,031
Shareholders' equity 11,372

Net debt-to-capitalization ratio 37%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Common shares (millions)
Outstanding at March 31 459.8 480.6 - 4
Weighted average (diluted) 467.1 484.3 - 4
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(*) Operating EBITDA is net earnings from continuing operations before
interest, income taxes, depreciation, depletion and amortization
(DD&A), accretion of asset retirement obligation, foreign exchange
loss (gain), gain on disposition and unrealized loss on risk
management ($376 million, before tax).

EnCana financial results in U.S. dollars and operating results according
to U.S. protocols
EnCana reports in U.S. dollars and according to U.S. protocols in order
to facilitate a more direct comparison to other North American upstream oil
and natural gas exploration and development companies. Reserves and production
are reported on an after-royalty basis.


-------------------------------------------------------------------------
Operating Highlights %
(for the period ended Mar. 31) Q1 2004 Q1 2003 Change
-------------------------------------------------------------------------
(After royalties)
Natural Gas (MMcf/d)
Production 2,712 2,469 + 10
Produced gas withdrawn from storage - 120 n/a
-------------------------------------------------------------------------
Total natural gas sales (MMcf/d) 2,712 2,589 + 5
-------------------------------------------------------------------------
Oil and NGLs sales (bbls/d)
North America 165,877 156,295 + 6
International 99,070 41,883 + 137
-------------------------------------------------------------------------
Total oil and NGLs sales (bbls/d) 264,947 198,178 +34
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total sales (BOE/d) 716,947 629,678 +14
-------------------------------------------------------------------------

Resource play growth exceeds 25 percent across EnCana's portfolio
In North America, development capital continues to be focused on turning
resource play potential into production. First quarter oil and gas production
from EnCana's key North American resource plays has increased more than 25
percent since the first quarter of 2003. This is comprised of increases in gas
production at Mamm Creek in Colorado, Greater Sierra in northeast B.C., and
Canadian Plains shallow gas on legacy Suffield and Palliser Blocks and
increases in oilsands production at Foster Creek in northeast Alberta.

-------------------------------------------------------------------------
Growth from key
North American Net
resource plays Daily Production Wells Drilled
-------------------------------------------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------
Full
Natural gas (MMcf/d) Q1 Q4 Q3 Q2 Q1 Q1 year
-------------------------------------------------------------------------
Jonah 394 389 376 356 375 11 59
Mamm Creek 191 175 126 112 86 66 259
Canadian Plains shallow
gas 593 586 564 548 536 536 2,404
Coalbed methane 10 7 3 3 2 81 267
Greater Sierra 216 175 144 136 118 135 199
Cutbank Ridge 22 6 2 2 2 17 20
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Oil (Mbbls/d)
-------------------------------------------------------------------------
Foster Creek 28 26 22 20 19 4 8
Pelican Lake 15 15 16 17 15 29 134
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Corporate developments
----------------------

Dividend $0.10 per share
EnCana's board of directors has declared a quarterly dividend of $0.10
per share payable on June 30, 2004 to common shareholders of record as of
June 15, 2004.

Normal Course Issuer Bid purchases
To date in 2004, EnCana has purchased for cancellation 5.5 million of its
shares at an average price of C$55.37 per share under its current Normal
Course Issuer Bid. The company had 459.8 million shares outstanding at March
31, 2004.

Financial strength
------------------
EnCana maintains a strong balance sheet. At March 31, 2004 the company's
net debt-to-capitalization ratio was 37:63. EnCana's net debt-to-EBITDA
multiple, on a trailing 12-month basis, was 1.6 times.
At March 31, 2004, on a pro forma basis with the Tom Brown acquisition
and the planned divestitures of Canadian non-core conventional production,
EnCana's estimated net debt-to-capitalization would be 41 percent and net
debt-to-EBITDA would be 1.9 times. EnCana expects to refinance its $3 billion
bridge financing through the proceeds from the anticipated divestitures,
future cash flow, and accessing the capital and bank markets through
approximately $5 billion of existing and unused debt shelf registration
statements and bank credit facilities.
In the first quarter of 2004, EnCana invested $1,538 million of capital,
net divestitures were $313 million, resulting in net capital investment of
$1,225 million. EnCana expects its book tax rate, on a normalized basis, to be
between 26 and 31 percent for 2004, compared to the previous guidance of
between 34 and 36 percent, primarily as a result of Alberta tax changes and
the effects of asset dispositions.

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

EnCana Corporation will host a conference call today, Wednesday,
April 28, 2004 starting at 8 a.m., Mountain Time (10 a.m. Eastern Time),
to discuss EnCana's first quarter 2004 financial and operating results.

To participate, please dial (719) 457-2683 approximately 10 minutes prior
to the conference call. An archived recording of the call will be
available from approximately 5 p.m. on April 28, 2004 until midnight
May 3, 2004 by dialing (888) 203-1112 or (719) 457-0820 and entering pass
code 615046.

A live audio Web cast of the conference call will also be available via
EnCana's Web site, www.encana.com, under Investor Relations. The Web cast
will be archived for approximately 90 days.
-------------------------------------------------------------------------

NOTE 1. EnCana financial results in U.S. dollars and operating results
according to U.S. protocols
Starting with year-end 2003, EnCana is reporting its financial results in
U.S. dollars and its reserves and production according to U.S. protocols
in order to facilitate a more direct comparison to other North American
upstream oil and natural gas exploration and development companies.
Reserves and production are reported on an after-royalties basis. There
is no change to the physical volumes produced and sold or to the actual
reserves as a result of adopting U.S. protocols. However, readers should
note that the change results in a general lowering of reported numbers
for EnCana's sales volumes and impacts the percentage changes year over
year. For example, under previous Canadian protocols, if EnCana produced
and sold 100 barrels of oil at the wellhead, it reported sales of 100
barrels. Under the new U.S. protocol, royalties paid to the Crown, state
or mineral rights owners are deducted before sales volumes are reported.
For example, under U.S. protocols, if EnCana produced and sold
100 barrels and the oil was subject to a 20 percent royalty, EnCana would
report sales of 80 barrels of oil.

NOTE 2. Non-GAAP measures
This news release contains references to cash flow, operating EBITDA (net
earnings from continuing operations before interest, income taxes, DD&A,
accretion of asset retirement obligation, foreign exchange loss (gain),
gain on disposition and unrealized loss on risk management), EBITDA and
operating earnings, and the related basic and diluted per common share
amounts as applicable, which are not measures that have any standardized
meaning prescribed by Canadian GAAP and are considered non-GAAP measures.
Therefore, these measures may not be comparable to similar measures
presented by other issuers. These measures have been described and
presented in this press release in order to provide shareholders and
potential investors with additional information regarding EnCana's
liquidity and its ability to generate funds to finance its operations.

EnCana Corporation
With an enterprise value of approximately $25 billion, EnCana is one of
the world's leading independent oil and gas companies and North America's
largest independent natural gas producer and gas storage operator. Ninety
percent of the company's assets are located in North America. EnCana is the
largest producer and landholder in Western Canada and is a key player in
Canada's emerging offshore East Coast basins. Through its U.S. subsidiaries,
EnCana is one of the largest gas explorers and producers in the Rocky Mountain
states and has a strong position in the deep water Gulf of Mexico.
International subsidiaries operate two key high potential international growth
regions: Ecuador, where it is the largest private sector oil producer, and the
U.K. where it is the operator of a large oil discovery. EnCana and its
subsidiaries also conduct high upside potential new ventures exploration in
other parts of the world. EnCana is driven to be the industry's high
performance benchmark in production cost, per-share growth and value creation
for shareholders. EnCana common shares trade on the Toronto and New York stock
exchanges under the symbol ECA.

ADVISORY REGARDING RESERVES DATA AND OTHER OIL AND GAS INFORMATION -
EnCana's disclosure of reserves data and other oil and gas information is
made in reliance on an exemption granted to EnCana by Canadian securities
regulatory authorities which permits it to provide such disclosure in
accordance with U.S. disclosure requirements. The information provided by
EnCana may differ from the corresponding information prepared in accordance
with Canadian disclosure standards under National Instrument 51-101
(NI 51-101). EnCana's reserves quantities represent net proved reserves
calculated using the standards contained in Regulation S-X of the U.S.
Securities and Exchange Commission. Further information about the differences
between the U.S. requirements and the NI 51-101 requirements is set forth
under the heading "Note Regarding Reserves Data and Other Oil and Gas
Information" in EnCana's Annual Information Form.
Natural gas volumes that have been converted to barrels of oil equivalent
(BOEs) have been converted on the basis of six thousand cubic feet (mcf) to
one barrel (bbl). BOEs may be misleading, particularly if used in isolation. A
BOE conversion ratio of six mcf to one bbl is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not
represent equivalency at the well head.

EnCana Corporation resource descriptions
EnCana uses the terms resource play, estimated ultimate recovery and
resource potential. Resource play is a term used by EnCana to describe an
accumulation of hydrocarbons known to exist over a large areal expanse and/or
thick vertical section, which when compared to a conventional play, typically
has a lower geological and/or commercial development risk and lower average
decline rate. As used by EnCana, estimated ultimate recovery (EUR) has the
meaning set out jointly by the Society of Petroleum Engineers and World
Petroleum Congress in the year 2000, being those quantities of petroleum which
are estimated, on a given date, to be potentially recoverable from an
accumulation, plus those quantities already produced therefrom. Resource
potential is a term used by EnCana to refer to the estimated quantities of
hydrocarbons that may be added to proved reserves over a specified period of
time from a specified resource play or plays.

ADVISORY REGARDING FORWARD-LOOKING STATEMENTS - In the interests of
providing EnCana shareholders and potential investors with information
regarding EnCana, including management's assessment of EnCana's and its
subsidiaries' future plans and operations, certain statements contained in
this news release are forward-looking statements within the meaning of the
"safe harbour" provisions of the United States Private Securities Litigation
Reform Act of 1995. Forward-looking statements in this news release include,
but are not limited to: future economic performance (including per share
growth); anticipated life of proved reserves; anticipated success of resource
plays; the anticipated proportion of total North American resource play
production; potential success of such projects as SAGD, coalbed methane,
Ecuador, Deep Panuke, Buzzard, Cutbank Ridge, Greater Sierra, Mamm Creek,
Jonah and Entrega; the anticipated completion, timing and capacity of the
Entrega Pipeline; the anticipated resource potential associated with Tom
Brown, Inc. (TBI); the anticipated successful completion of the TBI
acquisition; the potential impact of the TBI acquisition on EnCana's
production, cash flow, earnings and financial benchmarks; the anticipated
sources of refinancing for that acquisition and anticipated divestitures;
anticipated risk mitigation strategies and the effect of such strategies;
potential demand for gas; anticipated production in 2004 and beyond (including
U.S. production); anticipated volatility in reported net earnings; anticipated
book tax rate; anticipated drilling; potential capital expenditures and
investment; anticipated coalbed methane development in 2004 and beyond;
potential oil and gas sales in 2004 and beyond, anticipated costs; potential
risks associated with drilling and references to potential exploration.
Readers are cautioned not to place undue reliance on forward-looking
statements, as there can be no assurance that the plans, intentions or
expectations upon which they are based will occur. By their nature,
forward-looking statements involve numerous assumptions, known and unknown
risks and uncertainties, both general and specific, that contribute to the
possibility that the predictions, forecasts, projections and other
forward-looking statements will not occur, which may cause the company's
actual performance and financial results in future periods to differ
materially from any estimates or projections of future performance or results
expressed or implied by such forward-looking statements. These risks and
uncertainties include, among other things: volatility of oil and gas prices;
fluctuations in currency and interest rates; product supply and demand; market
competition; risks inherent in the company's marketing operations, including
credit risks; imprecision of reserves estimates and estimates of recoverable
quantities of oil, natural gas and liquids from resource plays and other
sources not currently classified as proved or probable reserves; the company's
ability to replace and expand oil and gas reserves; its ability to generate
sufficient cash flow from operations to meet its current and future
obligations; its ability to access external sources of debt and equity
capital; the timing and the costs of well and pipeline construction; the
company's ability to secure adequate product transportation; changes in
environmental and other regulations; political and economic conditions in the
countries in which the company operates, including Ecuador; the risk of war,
hostilities, civil insurrection and instability affecting countries in which
the company operates and terrorist threats; risks associated with existing and
potential future lawsuits and regulatory actions made against the company; and
other risks and uncertainties described from time to time in the reports and
filings made with securities regulatory authorities by EnCana. Although EnCana
believes that the expectations represented by such forward-looking statements
are reasonable, there can be no assurance that such expectations will prove to
be correct. Readers are cautioned that the foregoing list of important factors
is not exhaustive.

Furthermore, the forward-looking statements contained in this news
release are made as of the date of this news release, and EnCana does not
undertake any obligation to update publicly or to revise any of the included
forward-looking statements, whether as a result of new information, future
events or otherwise. The forward-looking statements contained in this news
release are expressly qualified by this cautionary statement.


Interim Consolidated Financial Statements
(unaudited)
For the three months ended March 31, 2004


EnCana Corporation


U.S. DOLLARS


Notice to Reader

The draft financial statements are provided for your information; the
reader should be aware the financial statements are still under review
and changes may be made. The financial statements are confidential and
are not to be distributed.




Interim Report PREPARED IN US$
For the three months ended March 31, 2004

EnCana Corporation

CONSOLIDATED STATEMENT OF EARNINGS

March 31
-------------------------
(unaudited) Three Months Ended
-------------------------
(US$ millions, except per share amounts) 2004 2003
-------------------------------------------------------------------------

REVENUES, NET OF ROYALTIES (Notes 4, 13) $ 2,850 $ 2,743
-------------------------------------------------------------------------

EXPENSES (Note 4)
Production and mineral taxes 65 50
Transportation and selling 162 125
Operating 353 313
Purchased product 1,287 945
Depreciation, depletion and
amortization 624 471
Administrative 49 37
Interest, net 79 64
Accretion of asset retirement
obligation (Note 9) 7 5
Foreign exchange loss (gain) (Note 6) 58 (210)
Stock-based compensation 5 -
Gain on disposition (Note 3) (34) -
-------------------------------------------------------------------------
2,655 1,800
-------------------------------------------------------------------------
NET EARNINGS BEFORE INCOME TAX 195 943
Income tax (recovery) expense (Note 7) (95) 293
-------------------------------------------------------------------------
NET EARNINGS FROM CONTINUING
OPERATIONS 290 650
NET EARNINGS FROM DISCONTINUED
OPERATIONS (Note 5) - 187
-------------------------------------------------------------------------
NET EARNINGS $ 290 $ 837
-------------------------------------------------------------------------
-------------------------------------------------------------------------

NET EARNINGS FROM CONTINUING
OPERATIONS PER COMMON SHARE (Note 12)
Basic $ 0.63 $ 1.35
Diluted $ 0.62 $ 1.34
-------------------------------------------------------------------------
-------------------------------------------------------------------------

NET EARNINGS PER COMMON SHARE (Note 12)
Basic $ 0.63 $ 1.74
Diluted $ 0.62 $ 1.73
-------------------------------------------------------------------------
-------------------------------------------------------------------------



CONSOLIDATED STATEMENT OF RETAINED EARNINGS
Three Months Ended
March 31,
-------------------------
(unaudited) (US$ millions) 2004 2003
-------------------------------------------------------------------------

RETAINED EARNINGS, BEGINNING OF YEAR
As previously reported $ 5,276 $ 3,457
Retroactive adjustment for changes
in accounting policies - 66
-------------------------------------------------------------------------
As restated 5,276 3,523
Net Earnings 290 837
Dividends on Common Shares (46) (33)
Charges for Normal Course Issuer Bid (Note 10) (120) -
-------------------------------------------------------------------------
RETAINED EARNINGS, END OF PERIOD $ 5,400 $ 4,327
-------------------------------------------------------------------------
-------------------------------------------------------------------------

See accompanying Notes to Consolidated Financial Statements.




Interim Report PREPARED IN US$
For the three months ended March 31, 2004

EnCana Corporation

CONSOLIDATED BALANCE SHEET

As at As at
March 31, December 31,
(unaudited) (US$ millions) 2004 2003
-------------------------------------------------------------------------

ASSETS
Current Assets
Cash and cash equivalents $ 250 $ 148
Accounts receivable and accrued
revenues 1,722 1,367
Risk management (Note 13) 39 -
Inventories 273 573
-------------------------------------------------------------------------
2,284 2,088
Property, Plant and Equipment, net (Note 4) 19,991 19,545
Investments and Other Assets 563 566
Risk Management (Note 13) 86 -
Goodwill 1,884 1,911
-------------------------------------------------------------------------
(Note 4) $ 24,808 $ 24,110
-------------------------------------------------------------------------
-------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued
liabilities $ 1,886 $ 1,579
Risk management (Note 13) 559 -
Income tax payable 218 65
Current portion of long-term debt (Note 8) 189 287
-------------------------------------------------------------------------
2,852 1,931
Long-Term Debt (Note 8) 6,031 6,088
Other Liabilities 95 21
Risk Management (Note 13) 40 -
Asset Retirement Obligation (Note 9) 441 430
Future Income Taxes 3,977 4,362
-------------------------------------------------------------------------
13,436 12,832
-------------------------------------------------------------------------
Shareholders' Equity
Share capital (Note 10) 5,343 5,305
Share options, net 30 55
Paid in surplus 26 18
Retained earnings 5,400 5,276
Foreign currency translation
adjustment 573 624
-------------------------------------------------------------------------
11,372 11,278
-------------------------------------------------------------------------
$ 24,808 $ 24,110
-------------------------------------------------------------------------
-------------------------------------------------------------------------

See accompanying Notes to Consolidated Financial Statements.




Interim Report PREPARED IN US$
For the three months ended March 31, 2004

EnCana Corporation

CONSOLIDATED STATEMENT OF CASH FLOWS
Three Months Ended
-------------------------
March 31,
-------------------------
(unaudited) (US$ millions) 2004 2003
-------------------------------------------------------------------------

OPERATING ACTIVITIES
Net earnings from continuing
operations $ 290 $ 650
Depreciation, depletion and
amortization 624 471
Future income taxes (Note 7) (327) 273
Unrealized loss on risk management (Note 13) 376 -
Unrealized foreign exchange
loss (gain) (Note 6) 39 (178)
Accretion of asset retirement
obligation (Note 9) 7 5
Gain on disposition (Note 3) (34) -
Other 20 (30)
-------------------------------------------------------------------------
Cash flow from continuing operations 995 1,191
Cash flow from discontinued
operations - 30
-------------------------------------------------------------------------
Cash flow 995 1,221
Net change in other assets and
liabilities (5) (3)
Net change in non-cash working
capital from continuing operations 467 50
Net change in non-cash working
capital from discontinued
operations - 11
-------------------------------------------------------------------------
1,457 1,279
-------------------------------------------------------------------------

INVESTING ACTIVITIES
Capital expenditures (Note 4) (1,538) (1,011)
Proceeds on disposal of property,
plant and equipment 25 7
Dispositions (acquisitions) (Note 3) 288 (116)
Equity investments (Note 3) 44 (45)
Net change in investments and other (2) (23)
Net change in non-cash working
capital from continuing operations 85 (134)
Discontinued operations - 1,289
-------------------------------------------------------------------------
(1,098) (33)
-------------------------------------------------------------------------

FINANCING ACTIVITIES
Repayment of long-term debt (103) (892)
Issuance of common shares (Note 10) 111 29
Purchase of common shares (Note 10) (218) -
Dividends on common shares (46) (33)
Other (1) (1)
Net change in non-cash working
capital from continuing operations - (4)
Discontinued operations - (282)
-------------------------------------------------------------------------
(257) (1,183)
-------------------------------------------------------------------------

DEDUCT: FOREIGN EXCHANGE LOSS ON
CASH AND CASH EQUIVALENTS HELD IN
FOREIGN CURRENCY - 2
-------------------------------------------------------------------------

INCREASE IN CASH AND CASH EQUIVALENTS 102 61
CASH AND CASH EQUIVALENTS,
BEGINNING OF YEAR 148 116
-------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS, END OF PERIOD $ 250 $ 177
-------------------------------------------------------------------------
-------------------------------------------------------------------------

See accompanying Notes to Consolidated Financial Statements.



Interim Report
For the three months ended March 31, 2004

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)


1. BASIS OF PRESENTATION

The interim Consolidated Financial Statements include the accounts of
EnCana Corporation and its subsidiaries (the "Company"), and are
presented in accordance with Canadian generally accepted accounting
principles. The Company is in the business of exploration for, and
production and marketing of, natural gas, natural gas liquids and crude
oil, as well as natural gas storage operations, natural gas liquids
processing and power generation operations.

The interim Consolidated Financial Statements have been prepared
following the same accounting policies and methods of computation as the
annual audited Consolidated Financial Statements for the year ended
December 31, 2003, except as noted 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, 2003.


2. CHANGE IN ACCOUNTING POLICIES AND PRACTICES

Hedging Relationships

On January 1, 2004, the Company adopted the amendments made to Accounting
Guideline 13 ("AcG - 13") "Hedging Relationships", and EIC 128,
"Accounting for Trading, Speculative or Non Trading Derivative Financial
Instruments". Derivative instruments that do not qualify as a hedge under
AcG - 13, or are not designated as a hedge, are recorded in the
Consolidated Balance Sheet as either an asset or liability with changes
in fair value recognized in net earnings. The Company has elected not to
designate any of its price risk management activities in place at
March 31, 2004 as accounting hedges under AcG - 13 and, accordingly, will
account for all these non-hedging derivatives using the mark-to-market
accounting method. The impact on the Company's Consolidated Financial
Statements at January 1, 2004 resulted in the recognition of risk
management assets with a fair value of $145 million, risk management
liabilities with a fair value of $380 million and a net deferred loss of
$235 million which will be recognized into net earnings as the contracts
expire. At March 31, 2004, it is estimated that over the following 12
months, $169 million ($118 million, net of tax) will be reclassified into
net earnings from net deferred losses.

The following table presents the deferred amounts expected to be
recognized in net earnings as unrealized gains/(losses) over the years
2004 to 2008:

Unrealized
Gain/(Loss)
-------------------------------------------------------------------------

2004
Quarter 2 $ (54)
Quarter 3 (51)
Quarter 4 (64)
-------------------------------------------------------------------------
Total remaining to be recognized in 2004 $ (169)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

2005
Quarter 1 $ -
Quarter 2 13
Quarter 3 9
Quarter 4 9
-------------------------------------------------------------------------
Total to be recognized in 2005 $ 31
-------------------------------------------------------------------------
-------------------------------------------------------------------------

2006 24
2007 15
2008 1
-------------------------------------------------------------------------
Total remaining to be recognized $ (98)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


3. DISPOSITIONS (ACQUISITIONS)

In March 2004, the Company sold its investment in a well servicing
company for approximately $44 million, recording a gain on sale of
$34 million.

On February 18, 2004, the Company sold its 53.3 percent interest in
Petrovera Resources ("Petrovera") for approximately $288 million,
including working capital adjustments. In order to facilitate the
transaction, EnCana purchased the 46.7 percent interest of its partner
for approximately $253 million, including working capital adjustments,
and then sold the 100 percent interest in Petrovera for a total of
approximately $541 million, including working capital adjustments. There
was no gain or loss recorded on this sale.

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

Other dispositions of discontinued operations are disclosed in Note 5.


4. SEGMENTED INFORMATION

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

- Upstream includes the Company's exploration for, and development and
production of, natural gas, natural gas liquids and crude oil and
other related activities. The majority of the Company's Upstream
operations are located in Canada, the United States, the United
Kingdom and Ecuador. International new venture exploration is mainly
focused on opportunities in Africa, South America and the Middle
East.

- Midstream & Marketing includes natural gas storage operations,
natural gas liquids processing and power generation operations, as
well as marketing activities. These marketing activities include the
sale and delivery of produced product and the purchasing of third
party product primarily for the optimization of midstream assets, as
well as the optimization of transportation arrangements not fully
utilized for the Company's own production.

- Corporate includes unrealized gains or losses recorded on derivative
instruments. Once amounts are settled, the realized gains and losses
are recorded in the operating segment to which the derivative
instrument relates.

Midstream & Marketing purchases all of the Company's North American
Upstream production. Transactions between business segments are based on
market values and eliminated on consolidation. The tables in this note
present financial information on an after eliminations basis.

Operations that have been discontinued are disclosed in Note 5.


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

Upstream Midstream &
Marketing
---------------------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues,
Net of Royalties $ 1,808 $ 1,650 $ 1,419 $ 1,093

Expenses
Production and
mineral taxes 65 50 - -
Transportation
and selling 154 107 8 18
Operating 277 219 78 94
Purchased product - - 1,287 945
Depreciation,
depletion and
amortization 601 459 7 5
-------------------------------------------------------------------------
Segment Income $ 711 $ 815 $ 39 $ 31
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Corporate Consolidated
---------------------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues,
Net of Royalties $ (377) $ - $ 2,850 $ 2,743

Expenses
Production and
mineral taxes - - 65 50
Transportation
and selling - - 162 125
Operating (2) - 353 313
Purchased product - - 1,287 945
Depreciation,
depletion and
amortization 16 7 624 471
-------------------------------------------------------------------------
Segment Income $ (391) $ (7) 359 839
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Administrative 49 37
Interest, net 79 64
Accretion of asset
retirement
obligation 7 5
Foreign exchange
loss (gain) 58 (210)
Stock-based
compensation 5 -
Gain on disposition (34) -
-------------------------------------------------------------------------
164 (104)
-------------------------------------------------------------------------
Net Earnings Before
Income Tax 195 943
Income tax
(recovery) expense (95) 293
-------------------------------------------------------------------------
Net Earnings from
Continuing Operations $ 290 $ 650
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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

North America
----------------------------------------------
Upstream Produced Gas and NGLs
Canada United States Crude Oil
----------------------------------------------
2004 2003 2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues,
Net of Royalties $ 971 $ 963 $ 358 $ 311 $ 250 $ 224

Expenses
Production and
mineral taxes 15 4 34 29 5 5
Transportation and
selling 82 61 25 15 20 20
Operating 101 87 20 10 73 67
Depreciation, depletion
and amortization 298 254 82 66 118 93
-------------------------------------------------------------------------
Segment Income $ 475 $ 557 $ 197 $ 191 $ 34 $ 39
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Total
Ecuador U.K. North Sea Other Upstream
--------------------------------------------------------------
2004 2003 2004 2003 2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues,
Net of
Royalties $ 126 $ 87 $ 53 $ 32 $ 50 $ 33 $1,808 $1,650

Expenses
Production
and
mineral
taxes 11 12 - - - - 65 50
Transpor-
tation
and
selling 19 7 8 4 - - 154 107
Operating 30 15 6 3 47 37 277 219
Depre-
ciation,
depletion
and
amort-
ization 65 23 33 22 5 1 601 459
-------------------------------------------------------------------------
Segment
Income $ 1 $ 30 $ 6 $ 3 $ (2) $ (5) $ 711 $ 815
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Total
Midstream & Marketing Midstream
Midstream Marketing(*) & Marketing
----------------------------------------------
2004 2003 2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues $ 551 $ 318 $ 868 $ 775 $1,419 $1,093

Expenses
Transportation
and selling - - 8 18 8 18
Operating 71 79 7 15 78 94
Purchased product 449 204 838 741 1,287 945
Depreciation, depletion
and amortization 7 4 - 1 7 5
-------------------------------------------------------------------------
Segment Income $ 24 $ 31 $ 15 $ - $ 39 $ 31
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(*) Includes transportation cost optimization activity under which the
Company purchases and takes delivery of product from others and
delivers product to customers under transportation arrangements not
utilized for the Company's own production.


Capital Expenditures
Three Months Ended
March 31,
-------------------------
2004 2003
-------------------------------------------------------------------------

Upstream
Canada $ 1,028 $ 707
United States 210 150
Ecuador 54 73
United Kingdom 213 16
Other Countries 15 17
-------------------------------------------------------------------------
1,520 963
Midstream & Marketing 9 36
Corporate 9 12
-------------------------------------------------------------------------
Total $ 1,538 $ 1,011
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Property, Plant and Equipment and Total Assets

Property, Plant
and Equipment Total Assets
---------------------------------------------------
As at As at
---------------------------------------------------
March 31, December 31, March 31, December 31,
2004 2003 2004 2003
-------------------------------------------------------------------------

Upstream $ 18,991 $ 18,532 $ 22,350 $ 21,742
Midstream & Marketing 777 784 1,551 1,879
Corporate 223 229 907 489
-------------------------------------------------------------------------
Total $ 19,991 $ 19,545 $ 24,808 $ 24,110
-------------------------------------------------------------------------
-------------------------------------------------------------------------


5. DISCONTINUED OPERATIONS

On February 28, 2003, the Company completed the sale of its 10 percent
working interest in the Syncrude Joint Venture ("Syncrude") to Canadian
Oil Sands Limited for net cash consideration of C$1,026 million
($690 million). On July 10, 2003, the Company completed the sale of the
remaining 3.75 percent interest in Syncrude and a gross overriding
royalty for net cash consideration of C$427 million ($309 million). There
was no gain or loss on this sale.

On January 2, 2003 and January 9, 2003, the Company completed the sales
of its interests in the Cold Lake Pipeline System and Express Pipeline
System for total consideration of approximately C$1.6 billion
($1 billion), including assumption of related long-term debt by the
purchaser, and recorded an after-tax gain on sale of C$263 million
($169 million).

As all discontinued operations have either been disposed of or wind up
has been completed by December 31, 2003, there are no remaining assets or
liabilities on the Consolidated Balance Sheet. The following table
presents the effect of the discontinued operations on the Consolidated
Statement of Earnings for 2003:

Consolidated Statement of Earnings

For the three months ended
March 31, 2003
--------------------------------------
Midstream -
Syncrude Pipelines Total
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 60 $ - $ 60
-------------------------------------------------------------------------

Expenses
Transportation and selling 1 - 1
Operating 28 - 28
Depreciation, depletion and
amortization 5 - 5
Gain on discontinuance - (220) (220)
-------------------------------------------------------------------------
34 (220) (186)
-------------------------------------------------------------------------
Net Earnings Before Income Tax 26 220 246
Income tax expense 8 51 59
-------------------------------------------------------------------------
Net Earnings from Discontinued
Operations $ 18 $ 169 $ 187
-------------------------------------------------------------------------
-------------------------------------------------------------------------


6. FOREIGN EXCHANGE LOSS (GAIN)
Three Months Ended
March 31,
-------------------------
2004 2003
-------------------------------------------------------------------------

Unrealized Foreign Exchange Loss (Gain) on
Translation of U.S. Dollar Debt Issued
in Canada $ 39 $ (178)
Realized Foreign Exchange Losses (Gains) 19 (32)
-------------------------------------------------------------------------
$ 58 $ (210)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


7. INCOME TAXES

The provision for income taxes is as follows:

Three Months Ended
March 31,
-------------------------
2004 2003
-------------------------------------------------------------------------

Current
Canada $ 205 $ 12
United States 8 -
Ecuador 19 8
-------------------------------------------------------------------------
232 20
Future (218) 273
Future tax rate reductions(*) (109) -
-------------------------------------------------------------------------
$ (95) $ 293
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(*) On March 31, 2004, the Alberta government substantively enacted the
income tax rate reduction previously announced in February 2004.

The following table reconciles income taxes calculated at the Canadian
statutory rate with the actual income taxes:

Three Months Ended
March 31,
2004 2003
-------------------------------------------------------------------------

Net Earnings Before Income Taxes $ 195 $ 943
Canadian Statutory Rate 39.1% 41.0%
-------------------------------------------------------------------------
Expected Income Taxes 76 386

Effect on Taxes Resulting from:
Non-deductible Canadian crown payments 52 78
Canadian resource allowance (57) (105)
Canadian resource allowance on unrealized
risk management losses 21 -
Statutory rate differences (9) (11)
Effect of tax rate changes (109) -
Non-taxable capital gains 7 (34)
Previously unrecognized capital losses 13 (34)
Tax recovery on dispositions (80) -
Large corporations tax 4 7
Other (13) 6
-------------------------------------------------------------------------
$ (95) $ 293
-------------------------------------------------------------------------
Effective Tax Rate (48.7%) 31.1%
-------------------------------------------------------------------------
-------------------------------------------------------------------------


8. LONG-TERM DEBT
As at As at
March 31, December 31,
2004 2003
-------------------------------------------------------------------------

Canadian Dollar Denominated Debt
Revolving credit and term loan borrowings $ 1,387 $ 1,425
Unsecured notes and debentures 1,316 1,335
Preferred securities 153 252
-------------------------------------------------------------------------
2,856 3,012
-------------------------------------------------------------------------

U.S. Dollar Denominated Debt
Revolving credit and term loan borrowings 421 417
Unsecured notes and debentures 2,713 2,713
Preferred securities 150 150
-------------------------------------------------------------------------
3,284 3,280
-------------------------------------------------------------------------

Increase in Value of Debt Acquired(*) 80 83
Current Portion of Long-Term Debt (189) (287)
-------------------------------------------------------------------------
$ 6,031 $ 6,088
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(*) Certain of the notes and debentures of the Company were acquired in
the business combination with Alberta Energy Company Ltd. on April 5,
2002 and were accounted for at their fair value at the date of
acquisition. The difference between the fair value and the principal
amount of the debt is being amortized over the remaining life of the
outstanding debt acquired, approximately 27 years.


9. ASSET RETIREMENT OBLIGATION

The following table presents the reconciliation of the beginning and
ending aggregate carrying amount of the obligation associated with the
retirement of oil and gas properties:


March 31, December 31,
2004 2003
-------------------------------------------------------------------------

Asset Retirement Obligation, Beginning of Year $ 430 $ 309
Liabilities Incurred 25 64
Liabilities Settled (4) (23)
Liabilities Disposed (12) -
Accretion Expense 7 19
Change in Estimate 1 -
Other (6) 61
-------------------------------------------------------------------------
Asset Retirement Obligation, End of Period $ 441 $ 430
-------------------------------------------------------------------------
-------------------------------------------------------------------------


10. SHARE CAPITAL

March 31, 2004 December 31, 2003
------------------------------------------
(millions) Number Amount Number Amount
-------------------------------------------------------------------------

Common Shares Outstanding,
Beginning of Year 460.6 5,305 478.9 5,511
Shares Issued under Option
Plans 4.4 111 5.5 114
Shares Repurchased (5.2) (73) (23.8) (320)
-------------------------------------------------------------------------
Common Shares Outstanding,
End of Period 459.8 5,343 460.6 5,305
-------------------------------------------------------------------------
-------------------------------------------------------------------------

During the quarter, the Company purchased, for cancellation, 5,190,000
Common Shares for total consideration of approximately C$287 million
($218 million). Of the amount paid this quarter, C$95 million
($73 million) was charged to share capital, C$34 million ($25 million)
was charged to paid in surplus and C$158 million ($120 million) was
charged to retained earnings.

The Company has stock-based compensation plans that allow employees and
directors to purchase Common Shares of the Company. Option exercise
prices approximate the market price for the Common Shares on the date the
options were issued. Options granted under the plans are generally fully
exercisable after three years and expire five years after the grant date.
Options granted under previous successor and/or related company
replacement plans expire ten years from the date the options were
granted.

The following tables summarize the information about options to purchase
Common Shares at March 31, 2004:

Weighted
Stock Average
Options Exercise
(millions) Price (C$)
-------------------------------------------------------------------------

Outstanding, Beginning of Year 28.8 43.13
Exercised (4.4) 33.24
Forfeited (0.2) 47.19
-------------------------------------------------------------------------
Outstanding, End of Period 24.2 43.93
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Exercisable, End of Period 11.3 41.14
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Outstanding Options Exercisable Options
-------------------------------------------------------
Weighted
Average
Number Remaining Weighted Number Weighted
of Options Contractual Average of Options Average
Range of Exercise Outstanding Life Exercise Outstanding Exercise
Price (C$) (millions) (years) Price (C$) (millions) Price (C$)
-------------------------------------------------------------------------

13.50 to 19.99 0.6 0.6 18.55 0.6 18.55
20.00 to 24.99 1.0 1.1 22.49 1.0 22.49
25.00 to 29.99 1.2 1.0 26.31 1.2 26.31
30.00 to 43.99 0.8 1.6 39.16 0.7 38.61
44.00 to 53.00 20.6 3.4 47.96 7.8 47.71
-------------------------------------------------------------------------
24.2 2.4 43.93 11.3 41.14
-------------------------------------------------------------------------
-------------------------------------------------------------------------

The Company has recorded stock-based compensation expense in the
Consolidated Statement of Earnings for stock options granted to employees
and directors in 2003 using the fair-value method. Compensation expense
has not been recorded in the Consolidated Statement of Earnings related
to stock options granted prior to 2003. If the Company had applied the
fair-value method to options granted prior to 2003, pro forma Net
Earnings and Net Earnings per Common Share for the three months ended
March 31, 2004 would have been $281 million; $0.61 per common share -
basic; $0.60 per common share - diluted (2003 - $829 million; $1.73 per
common share - basic; $1.71 per common share - diluted).

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:


March 31, 2003
-------------------------------------------------------------------------

Weighted Average Fair Value of Options Granted (C$) $ 13.05
Risk Free Interest Rate 4.19%
Expected Lives (years) 3.00
Expected Volatility 0.33
Annual Dividend per Share (C$) $ 0.40
-------------------------------------------------------------------------
-------------------------------------------------------------------------


11. COMPENSATION PLANS

The tables below outline certain information related to the Company's
compensation plans at March 31, 2004. Additional information is contained
in Note 16 of the Company's annual audited Consolidated Financial
Statements.

A) Defined Benefit Pension Plans

The following table summarizes the net defined benefit plan expense:

Three Months Ended
March 31,
---------------------
2004 2003
-------------------------------------------------------------------------

Current Service Cost $ 2 $ 1
Interest Cost 3 3
Expected Return on Plan Assets (3) (2)
Amortization of Net Actuarial Loss - 1
Expense for Defined Contribution Plan 3 3
-------------------------------------------------------------------------
Net Defined Benefit Plan Expense $ 5 $ 6
-------------------------------------------------------------------------
-------------------------------------------------------------------------

The Company previously disclosed in its Consolidated Financial Statements
for the year ended December 31, 2003 that it expected to contribute
$6 million to its defined benefit pension plans in 2004. As of March 31,
2004, no contributions have been made. The Company presently anticipates
contributing $6 million to fund its defined benefit pension plans in
2004.

B) Share Appreciation Rights ("SAR's")

The following table summarizes the information about SAR's at
March 31, 2004:

Weighted
Average
Outstanding Exercise
SAR's Price ($)
-------------------------------------------------------------------------

Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 1,175,070 35.87
Exercised (372,828) 35.42
-------------------------------------------------------------------------
Outstanding, End of Period 802,242 36.06
-------------------------------------------------------------------------
Exercisable, End of Period 802,242 36.06
-------------------------------------------------------------------------
-------------------------------------------------------------------------

U.S. Dollar Denominated (US$)
Outstanding, Beginning of Year 753,417 28.98
Exercised (206,223) 29.05
-------------------------------------------------------------------------
Outstanding, End of Period 547,194 28.95
-------------------------------------------------------------------------
Exercisable, End of Period 547,194 28.95
-------------------------------------------------------------------------
-------------------------------------------------------------------------

The following table summarizes the information about Tandem SAR's at
March 31, 2004:
Weighted
Outstanding Average
Tandem Exercise
SAR's Price (C$)
-------------------------------------------------------------------------

Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year - -
Granted 206,900 53.05
-------------------------------------------------------------------------
Outstanding, End of Period 206,900 53.05
-------------------------------------------------------------------------
Exercisable, End of Period - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------

C) Deferred Share Units ("DSU's")

The following table summarizes the information about DSU's at March 31,
2004:
Weighted
Average
Outstanding Exercise
DSU's Price (C$)
-------------------------------------------------------------------------

Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 319,250 48.68
Granted, Directors 24,347 51.43
Granted, Senior Executives 557 56.68
-------------------------------------------------------------------------
Outstanding, End of Period 344,154 48.89
-------------------------------------------------------------------------
Exercisable, End of Period 80,830 48.70
-------------------------------------------------------------------------
-------------------------------------------------------------------------

D) Performance Share Units ("PSU's")

The following table summarizes the information about PSU's at March 31,
2004:

Weighted
Average
Outstanding Exercise
PSU's Price ($)
-------------------------------------------------------------------------

Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 126,283 46.52
Granted 1,664,911 53.97
-------------------------------------------------------------------------
Outstanding, End of Period 1,791,194 53.44
-------------------------------------------------------------------------
Exercisable, End of Period - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------

U.S. Dollar Denominated (US$)
Outstanding, Beginning of Year - -
Granted 247,960 41.12
-------------------------------------------------------------------------
Outstanding, End of Period 247,960 41.12
-------------------------------------------------------------------------
Exercisable, End of Period - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------


12. PER SHARE AMOUNTS

The following table summarizes the Common Shares used in calculating Net
Earnings per Common Share:


As at March 31,
(millions) 2004 2003
-------------------------------------------------------------------------

Weighted Average Common Shares Outstanding - Basic 460.9 479.9
Effect of Dilutive Securities 6.2 4.4
-------------------------------------------------------------------------
Weighted Average Common Shares Outstanding - Diluted 467.1 484.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------


13. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

As a means of managing commodity price volatility, the Company has
entered into various financial instrument agreements and physical
contracts. The following information presents all positions for financial
instruments only.

As discussed in Note 2, on January 1, 2004, the fair value of all
outstanding financial instruments that are not considered accounting
hedges was recorded on the Consolidated Balance Sheet with an offsetting
net deferred loss amount. The deferred loss is recognized into net
earnings over the life of the associated contracts. Changes in fair value
after that time are recorded on the Consolidated Balance Sheet with the
associated unrealized gain or loss recorded in net earnings. The
estimated fair value of all derivative instruments is based on quoted
market prices or, in their absence, third party market indications and
forecasts.

The following table presents a reconciliation of the change in the
unrealized amounts from January 1, 2004 to March 31, 2004:


Net Deferred
Amounts Total
Recognized Mark- Unrealized
on Transition To-Market Gain/(Loss)
-------------------------------------------------------------------------

Fair Value of Contracts,
January 1, 2004 (Note 2) $ 235 $ (235) $ -
Change in Fair Value
of Contracts Still
Outstanding at
March 31, 2004 - (316) (316)
Fair Value of Contracts
Realized During
the Period (137) 137 -
Fair Value of Contracts
Entered into During
the Period - (60) (60)
-------------------------------------------------------------------------
Fair Value of Contracts
Outstanding,
End of Period $ 98 $ (474) $ (376)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

The total realized losses recognized in net earnings for three months
ended March 31, 2004 was $145 million ($99 million, net of tax).

At March 31, 2004 the net deferred amounts recognized on transition and
the risk management amounts are recorded in the Consolidated Balance
Sheet as follows:
As at
March 31, 2004
-------------------------------------------------------------------------

Deferred Amounts Recognized on Transition:
Accounts receivable and accrued revenues $ 211
Investments and other assets 2

Accounts payable and accrued liabilities 40
Other liabilities 75
-------------------------------------------------------------------------
Total Net Deferred Loss $ 98
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Risk Management
Current asset $ 39
Long-term asset 86

Current liability 559
Long-term liability 40
-------------------------------------------------------------------------
Total Net Risk Management Liability $ (474)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

A summary of all unrealized estimated fair value financial positions are
as follows:

As at
March 31, 2004
-------------------------------------------------------------------------

Commodity Price Risk
Natural gas $ (147)
Crude oil (369)
Power 5
Foreign Currency Risk (1)
Interest Rate Risk 38
-------------------------------------------------------------------------
$ (474)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Information with respect to power, foreign currency risk and interest
rate risk contracts in place at December 31, 2003, is disclosed in
Note 17 to the Company's annual audited Consolidated Financial
Statements. No significant new contracts have been entered into as at
March 31, 2004.

Natural Gas

At March 31, 2004, the Company's gas risk management activities for
financial contracts had an unrealized loss of $147 million. The contracts
were as follows:

Notional
Volumes Unrealized
(MMcf/d) Term Price Gain/(Loss)
-------------------------------------------------------------------------

Fixed Price Contracts
Sales Contracts
Fixed AECO price 452 2004 6.20 C$/Mcf $ (59)
NYMEX Fixed price 712 2004 5.03 US$/Mcf (183)
Chicago Fixed price 40 2004 5.41 US$/Mcf (7)
AECO Collars 71 2004 5.34-7.52 C$/Mcf (4)

Basis Contracts
Sales Contracts
Fixed NYMEX to
AECO basis 352 2004 (0.55) US$/Mcf 24
Fixed NYMEX to
Rockies basis 277 2004 (0.49) US$/Mcf 18
Fixed NYMEX to
San Juan basis 64 2004 (0.63) US$/Mcf 1
Fixed Rockies to
CIG basis 50 2004 (0.10) US$/Mcf -

Fixed NYMEX to
AECO basis 877 2005 (0.66) US$/Mcf 24
Fixed NYMEX to
Rockies basis 258 2005 (0.48) US$/Mcf 17
Fixed NYMEX to
San Juan basis 75 2005 (0.63) US$/Mcf 1
Fixed NYMEX to
CIG basis 25 2005 (0.87) US$/Mcf (2)
Fixed Rockies to
CIG basis 50 2005 (0.10) US$/Mcf -

Fixed NYMEX to
AECO basis 402 2006-2008 (0.65) US$/Mcf 18
Fixed NYMEX to
Rockies basis 162 2006-2008 (0.56) US$/Mcf 16
Fixed NYMEX to
San Juan basis 62 2006 (0.63) US$/Mcf 1
Fixed NYMEX to
CIG basis 125 2006 (0.87) US$/Mcf (6)
Fixed Rockies to
CIG basis 31 2006-2007 (0.10) US$/Mcf (1)

Purchase Contracts
Fixed NYMEX to
AECO basis 38 2004 (0.73) US$/Mcf (1)
-------------------------------------------------------------------------
(143)
Gas Storage Financial
Positions (10)
Gas Marketing Financial
Positions(1) 6
-------------------------------------------------------------------------
$ (147)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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


Crude Oil

As at March 31, 2004, the Company's oil risk management activities for
all financial contracts had an unrealized loss of $369 million. The
contracts were as follows:


Notional Average
Volumes Price Unrealized
(bbl/d) Term (US$/bbl) Gain/(Loss)
-------------------------------------------------------------------------

Fixed WTI NYMEX Price 62,500 2004 23.13 $ (180)
Collars on WTI NYMEX 62,500 2004 20.00-25.69 (138)
Fixed WTI NYMEX Price 45,000 2005 28.41 (40)
3-way Put Spread 45,000 2005 20.00/25.00/28.78 (11)
-------------------------------------------------------------------------
(369)
Crude Oil Marketing
Financial Positions(1) -
-------------------------------------------------------------------------
$ (369)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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


14. SUBSEQUENT EVENT

On April 15, 2004, the Company announced that it was making a public
tender offer to acquire all of the issued and outstanding common shares
of Tom Brown, Inc., a publicly traded exploration and production company
with operations in the United States and Canada, for total cash
consideration of approximately $2.3 billion plus the assumption of debt
of approximately $0.4 billion. This transaction is expected to close
later in the second quarter.
15. RECLASSIFICATION

Certain information provided for prior periods has been reclassified to
conform to the presentation adopted in 2004.

For further information: on EnCana Corporation is available on the company's Web site, www.encana.com, or by contacting:

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

Greg Kist
Manager, Investor Relations
403-645-4737

Tracy Weeks
Manager, Investor Relations
403-645-2007

Media contact:
Alan Boras
Manager, Media Relations
403-645-4747

investor.relations@encana.com

ECA stock price

TSX $14.27 Can -0.540

NYSE $11.11 USD -0.510

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