EnCana cash flow rises 12 percent to US$5 billion in 2004; Earnings up more than 40 percent

Annual sales increase 16 percent to 4.6 billion cubic feet equivalent of gas per day Board of Directors recommend 2-for-1 stock split

CALGARY, Feb. 23 /CNW/ - EnCana (TSX & NYSE: ECA) today reports a
12 percent increase in 2004 cash flow to US$4.98 billion, or $10.64 per common
share diluted, compared to 2003. Total operating earnings in 2004 increased
41 percent to $1.98 billion, or $4.22 per common share diluted. Total
operating earnings are net earnings excluding the after-tax impacts of a
$1.4 billion gain on the sale of EnCana's U.K. North Sea assets, unrealized
gains due to foreign exchange on US$ denominated debt issued in Canada and tax
rate changes, and an unrealized mark-to-market loss. Net earnings in 2004
increased 49 percent to $3.5 billion, or $7.51 per common share diluted.
IMPORTANT NOTE: EnCana's 2004 year-end financial and operating results in
this news release are reported on a total consolidated basis, unless otherwise
noted. For financial statement purposes, EnCana is treating U.K. and Ecuador
operations as discontinued because the U.K. operations were sold in December
2004 and EnCana plans to sell its Ecuador assets. EnCana reports in U.S.
dollars and follows U.S. protocols, which report sales and reserves on an
after-royalties basis. All dollar figures are U.S. dollars unless otherwise
noted.
EnCana's double-digit sales growth and robust commodity prices
contributed to strong increases in cash flow and operating earnings. Natural
gas, oil and natural gas liquids (NGLs) sales increased 16 percent in 2004 to
average 4.6 billion cubic feet equivalent (Bcfe) per day. On a per share
basis, EnCana's 2004 sales increased 19 percent. Daily sales were comprised of
3.0 billion cubic feet of natural gas, up 17 percent from 2003, and
approximately 260,000 barrels per day of oil and NGLs, a 13 percent increase.
Operating and administrative costs in 2004 were approximately 70 cents per
thousand cubic feet equivalent, which was within EnCana's guidance range.
"In 2004, our cash flow per share increased 14 percent, total operating
earnings per share rose 45 percent and daily natural gas, oil and NGLs sales
increased 19 percent per share. Since mid-year, we enhanced our financial
strength by lowering our net debt-to-capitalization to 33 percent, well within
our target range of 30 to 40 percent. At the same time, under our Normal
Course Issuer Bid, we purchased about 4.3 percent of our shares for about
$1 billion," said Gwyn Morgan, EnCana's President & Chief Executive Officer.
"This outstanding 2004 performance was achieved through strong organic
growth from our portfolio of North American resource plays and by directing
excess cash flow from operations and proceeds from our divestitures of
conventional properties to strengthening our balance sheet and returning cash
to shareholders through share purchases," Morgan said.


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Financial and operating highlights
-------------------------------------------------------------------------
2004 Q4 - 2004
-------------------------------------------------------------------------
Cash flow per share
diluted $10.64, up 14% $3.21, up 19%
Total operating earnings
per share diluted $4.22, up 45% $1.23, up 81%
Net earnings per
share diluted $7.51, up 53% $5.55, up 510%
Total Mcfe sales,
per 1,000 shares 3,625 Mcfe, up 19%
Natural gas reserves 10.5 Tcf,
up 28% per share
-------------------------------------------------------------------------


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Natural gas sales 3.0 Bcf/d, up 17% 3.11 Bcf/d, up 16%
Oil and NGLs sales 260,000 bbls/d, up 13% 248,000 bbls/d, down 7%
Total Bcfe sales 4.56 Bcfe/d, up 16% 4.60 Bcfe/d, up 7%
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Two-for-one share split proposed

Due to EnCana's strong share price performance in 2004 and expectations
for continuing strong operating performance, the company's board of directors
is recommending that shareholders approve a two-for-one split of EnCana's
common shares, which is expected to encourage greater market liquidity and
wider distribution among retail investors. The proposed split will be voted on
at EnCana's Annual and Special Meeting on April 27, 2005 in Calgary.

Fourth quarter cash flow up 19 percent, total operating earnings up
81 percent

In the fourth quarter of 2004, EnCana's cash flow increased 19 percent to
$1.49 billion, or $3.21 per common share diluted, compared to the same 2003
period. Total operating earnings increased 81 percent to $573 million compared
to the same 2003 period. Net earnings increased six fold from the same period
in 2003 to $2.58 billion, or $5.55 per common share diluted, which includes a
$1.4 billion gain from the sale of the company's U.K. North Sea assets.

Focusing on North American resource plays

"During 2004, we sharpened our strategic focus on unconventional
resources in North America - natural gas and in-situ oilsands. The acquisition
of resource play focused Tom Brown, Inc. for $2.7 billion and the divestiture
of our U.K. North Sea assets for $2.1 billion, along with $1.4 billion in
North American conventional asset divestitures, were significant strategic
milestones. In the year, we became the continent's largest natural gas
producer, at more than 3 billion cubic feet per day - enough gas to meet the
daily requirements of every Canadian home, office, hospital, shopping centre
and commercial building," Morgan said.

Tom Brown assets performing well

Natural gas production from the former Tom Brown, Inc. assets in the U.S.
has increased about 13 percent in the seven months since the acquisition.
EnCana added about 209 billion cubic feet equivalent of proved reserves, net
of revisions, from former Tom Brown, Inc. lands in the U.S. in 2004.

EnCana continues to move ahead with divestiture of conventional assets

EnCana is planning to sell Canadian conventional properties producing
about 22,000 BOE per day. In order to enhance shareholder value, EnCana is
considering a variety of options to monetize these assets, including a cash
sale or the conversion of the assets into an income trust.
EnCana is also planning the sale of its portfolio of discoveries and
exploration interests in the Gulf of Mexico and producing properties and
pipeline interests in Ecuador. As a result, Ecuador operations have been
treated as discontinued for financial reporting purposes and EnCana's
corporate guidance for 2005 has been updated to reflect this change.
Proceeds from all of these divestitures are expected to be in the range
of $3 billion, plus or minus.
"For 2005, we will further increase our focus on growing our long-life
resource plays. And once we have completed our planned divestitures, we expect
that about 80 percent of EnCana's production will be natural gas, generating
about 85 percent of the company's operating cash flow," Morgan said.

North American natural gas reserves up 24 percent to 10.5 trillion cubic
feet

While 2004 was a year of strong growth, the company also added to the
source of its future growth. Proved reserves of North American natural gas
increased 24 percent to 10.5 trillion cubic feet in 2004, adding 2.2 trillion
cubic feet through the drill bit and acquiring a net 0.9 trillion cubic feet
primarily through the Tom Brown, Inc. acquisition. With total net North
America gas additions of 3.2 trillion cubic feet, compared to the 1.1 trillion
cubic feet of production in 2004, EnCana's North America gas production
replacement reached 290 percent. On February 1 and 16, 2005, the company
issued more detailed results of its 2004 operations, including reserve
additions, capital costs and a downward revision of 363 million barrels of
bitumen reserves. All of EnCana's proved reserves estimates are prepared by
independent qualified reserves evaluators.

Three years of consistent and competitive reserve addition costs

"EnCana's North American resource play exploitation programs steadily and
predictably convert our huge unbooked resource potential to proved reserves.
Future growth in reserves and production visibility is illustrated by the fact
that our unbooked resource potential exceeds our proved reserves. Over the
past three years, before the negative bitumen revision, we achieved a
production replacement averaging nearly 200 percent, at an average cost of
$1.42 per thousand cubic feet equivalent - a highly competitive cost during a
time when increasing demand for field services and a rising Canadian dollar
have fuelled inflation. In 2004, our proved reserve replacement costs were
$1.40 per thousand cubic feet equivalent. With our average netback, after
operating and administration costs, of $4.00 per thousand cubic feet
equivalent in 2004, we've achieved a recycle ratio of 2.9 times - evidence of
the strong value EnCana continues to create," said Randy Eresman, EnCana's
Chief Operating Officer.

Fourth quarter natural gas sales up 16 percent, total gas and oil sales
rise 7 percent despite divestitures

Fourth quarter natural gas, oil and NGLs sales averaged 4.6 Bcfe per day,
up 7 percent from 4.3 Bcfe per day in the same period in 2003. Natural gas
sales increased 16 percent to average 3.1 billion cubic feet per day. Oil and
NGLs sales in the fourth quarter of 2004 averaged 247,600 barrels per day,
down 7 percent from the same 2003 period due to the sale of conventional
producing properties. EnCana drilled 958 net wells in the fourth quarter of
2004, comprised of 811 development wells and 147 exploration wells.

EnCana targets 15 percent gas sales growth in 2005

In 2005, EnCana is forecasting daily gas sales of between 3.35 billion
and 3.5 billion cubic feet, which, at midpoint, is approximately a 15 percent
increase from the company's 2004 daily sales from continuing operations of
2.97 billion cubic feet per day. With planned divestitures of Canadian
conventional oil and gas properties, EnCana expects 2005 oil and NGLs sales
from continuing operations to be between 150,000 and 170,000 barrels per day.
Overall, EnCana is forecasting 2005 daily sales of between 4.25 Bcfe and
4.5 Bcfe, up about 10 percent from 2004 daily sales of 3.97 Bcfe from
continuing operations. EnCana has updated its corporate guidance on its Web
site, www.encana.com.


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

-------------------------------------------------------------------------
Financial Highlights
(as at and for the period
ended December 31)
(US$ millions, except Q4 Q4 % %
per share amounts) 2004 2003 change 2004 2003 change
-------------------------------------------------------------------------
Revenues, net of royalties
(including discontinued
operations) 4,407 2,850 + 55 12,433 10,303 + 21

Cash flow 1,491 1,254 + 19 4,980 4,459 + 12
Per share - basic 3.25 2.71 + 20 10.82 9.41 + 15
Per share - diluted 3.21 2.69 + 19 10.64 9.30 + 14

Add back:
---------
Total cash tax 20 (69) - 129 579 (54) -1,172

Pre-tax cash flow 1,511 1,185 + 28 5,559 4,405 + 26

Net capital investment (662) 1,381 - 148 4,206 3,422 + 23

Net earnings from
continuing operations 1,188 447 + 166 2,211 2,142 + 3
Per share - basic 2.59 0.97 + 167 4.80 4.52 + 6
Per share - diluted 2.56 0.96 + 167 4.72 4.47 + 6

Net earnings 2,580 426 + 506 3,513 2,360 + 49
Per share - basic 5.62 0.92 + 511 7.63 4.98 + 53
Per share - diluted 5.55 0.91 + 510 7.51 4.92 + 53

Add (Deduct):
-------------
(Gain) on sale of
discontinued operations,
after tax (1,364) - n/a (1,364) (169) n/a

Unrealized mark-to-market
accounting (gain)/loss,
after-tax (512) - n/a 165 - n/a

Unrealized foreign exchange
(gain) on translation of
U.S. dollar debt issued
in Canada, after-tax (131) (113) + 16 (229) (433) - 47

Future tax (recovery) due
to tax rate change - 3 n/a (109) (359) - 70

Total operating earnings 573 316 + 81 1,976 1,399 + 41
Per share - diluted 1.23 0.68 + 81 4.22 2.92 + 45
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Common shares (millions)
Weighted average (basic) 458.8 462.3 - 1 460.4 474.1 - 3
Weighted average (diluted) 464.9 465.9 - 468.0 479.7 - 2
-------------------------------------------------------------------------
-------------------------------------------------------------------------


-------------------------------------------------------------------------
Operating Highlights
(for the period ended
December 31) Q4 Q4 % %
(After royalties) 2004 2003 change 2004 2003 change
-------------------------------------------------------------------------
Continuing operations
North America Natural
Gas (MMcf/d)
Production (excluding
Tom Brown, Inc.) 2,833 2,662 + 6 2,802 2,523 + 11
Tom Brown, Inc.
production 280 - n/a 172 - n/a
Inventory withdrawal/
(injection) (26) - n/a (6) 30 n/a
-------------------------------------------------------------------------
Natural gas sales
(MMcf/d) 3,087 2,662 + 16 2,968 2,553 + 16
-------------------------------------------------------------------------
North America Oil and
NGLs (bbls/d) 159,470 174,471 - 9 166,417 165,895 0
-------------------------------------------------------------------------
Discontinued operations
U.K. natural gas
(MMcf/d) 22 20 + 10 30 13 + 131
U.K. oil and NGLs
(bbls/d) 10,260 15,067 - 32 15,973 10,128 + 58
Ecuador (bbls/d) 77,876 77,352 + 1 77,993 46,521 + 68
Syncrude (bbls/d) - - - - 7,629 -
-------------------------------------------------------------------------
Total discontinued
operations (BOE/d) 91,803 95,752 - 4 98,966 66,445 + 49
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total natural gas sales
(MMcf/d) 3,109 2,682 + 16 2,998 2,566 + 17
-------------------------------------------------------------------------
Total oil and NGLs sales
(bbls/d) 247,606 266,890 - 7 260,383 230,173 + 13
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total sales (MMcfe/d) 4,595 4,283 + 7 4,560 3,947 + 16
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total sales (BOE/d) 765,773 713,890 + 7 760,050 657,840 + 16
-------------------------------------------------------------------------
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Per share sales growth + 19
-------------------------------------------------------------------------
-------------------------------------------------------------------------

North American natural gas prices rise in 2004

North American realized field prices, excluding financial hedging,
averaged $5.47 per thousand cubic feet, up 12 percent from an average of $4.87
per thousand cubic feet in 2003. Driven by continued strong demand despite the
effects of a cooler summer and warmer average winter temperatures, the
influence of strong oil prices and ongoing concerns about North American gas
supply, the average 2004 benchmark NYMEX index gas price was $6.14 per
thousand cubic feet, up 14 percent from $5.39 per thousand cubic feet in 2003.
In the fourth quarter, EnCana's average realized field price, excluding
financial hedging, was $6.08 per thousand cubic feet, up 35 percent from $4.49
in the same 2003 period. The average benchmark NYMEX index price was $7.11 per
thousand cubic feet, an increase of 55 percent from the fourth quarter of
2003.

World oil prices strong in 2004; Canadian heavy oil price differentials
widen

World oil prices rose dramatically through much of 2004 due to strength
in global demand, primarily in Asia and North America and fourth quarter
concerns over sufficient heating oil supply. Supply concerns were fuelled by
Middle East tensions, the conflict in Iraq and, in the last half of 2004,
hurricane damage to Gulf of Mexico production facilities. During 2004, the
average benchmark West Texas Intermediate (WTI) crude oil price was $41.47 per
barrel, up 34 percent over the 2003 average of $30.99 per barrel. OPEC
increased production to satisfy demand, but new supplies were largely heavier
grades and more sour blends, which contributed to a widening of the light-
heavy price differential in Canada. The 2004 WTI/Bow River differential
increased 60 percent to $12.82 per barrel compared to 2003; and is up more
than double from more historical levels of $5.93 per barrel two years earlier
in 2002. In Ecuador, the WTI/NAPO differential also widened to $14.33 per
barrel, up 78 percent from $8.06 per barrel in the last four months of 2003.
In 2004, EnCana's average realized oil and NGLs price, excluding hedging,
was $29.17 per barrel; including hedging, it was $21.34 per barrel. In the
fourth quarter, the company's average realized oil and NGLs price, excluding
hedging, was $30.74 per barrel; including hedging, it was $20.61 per barrel.

Risk management strategy

EnCana's market risk mitigation strategy is intended to help deliver
greater predictability of cash flow and returns on investment. Detailed risk
management positions at December 31, 2004 are presented in Note 14 to the
unaudited fourth quarter consolidated financial statements. In 2004, EnCana's
financial commodity and currency risk management measures resulted in after-
tax cash flow being lower by approximately $700 million, comprised of
$540 million on oil hedges and $160 million on gas hedges. In the fourth
quarter, financial commodity and currency risk management measures resulted in
after-tax cash flow being lower by approximately $260 million, comprised of
$190 million on oil hedges and $70 million on gas hedges.

Hedging impact expected to wane in 2005

2004 oil hedging losses were exacerbated by an unprecedented discount
between heavy oil and benchmark WTI prices. A review of the company's hedging
strategy has resulted in a preference to the use of hedging instruments which
provide downside protection, but do not limit upside in a rising price
environment. EnCana has purchased WTI put options with a floor price of $40
per barrel for approximately 15 percent of forecast crude oil sales for 2005.
EnCana has also purchased NYMEX gas put options with a floor price of $5.46
per thousand cubic feet covering 27 percent of forecast gas sales for 2005.
About 19 percent of EnCana's 2005 forecast oil sales is hedged with swaps or
collars at approximately $29 per barrel. These arrangements were entered into
prior to the tactical change to focus on downside protection. In order to
limit the cost of possible extreme oil prices on these oil swaps, EnCana
entered into call options for 2005 at an average price of $49.76 per barrel,
allowing the company to participate in oil price upside above this level.
About 20 percent of EnCana's 2005 forecast gas sales are hedged with swaps at
an average price of $6.37 per thousand cubic feet. In addition, 1 percent of
EnCana's 2005 forecast gas sales are hedged with collars with a floor price of
$2.89 per thousand cubic feet and a ceiling price of $5.37 per thousand cubic
feet. Five percent of EnCana's gas sales are hedged with three-way options
with a floor price of $5.00 per thousand cubic feet and a ceiling price of
$6.69 per thousand cubic feet with a call option purchased at an average price
of $7.69, which will allow EnCana to participate in gas price upside above
this level. The company has also entered into longer term basis hedges
specifically for the purpose of protecting against high U.S. Rockies gas price
basis differentials. EnCana will continue to use a variety of hedging
instruments for its future hedging programs.

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

Quarterly dividend of $0.10 per share declared

EnCana's board of directors has declared a quarterly dividend of $0.10
per share payable on March 31, 2005 to common shareholders of record as of
March 15, 2005.

Shareholders to vote regarding two-for-one share split

At the Annual and Special meeting of EnCana's shareholders on April 27,
2005, EnCana's shareholders will be asked to approve the split of EnCana's
outstanding common shares on a two-for-one basis. In addition to shareholder
approval, the stock split is subject to the receipt of all required regulatory
approvals.
If approved by shareholders, and subject to regulatory approvals, each
shareholder will receive one additional common share for each common share he
or she holds on the record date for the stock split of May 12, 2005. Pursuant
to the rules of the Toronto Stock Exchange, EnCana's common shares will
commence trading on a subdivided basis at the opening of business on May 10,
2005, which is the second trading day preceding the record date. Also on May
10, 2005, EnCana's common shares listed on the New York Stock Exchange (NYSE)
will commence trading with rights entitling holders to an additional common
share for each common share held upon the commencement of trading of the
common shares on a subdivided basis on the NYSE. The trading of the common
shares on a subdivided basis on the NYSE will occur one day after the delivery
of share certificates to registered holders of EnCana's common shares. It is
anticipated that share certificates representing the additional common shares
resulting from the stock split will be mailed to registered common
shareholders on or about May 20, 2005.

Normal Course Issuer Bid increased to permit purchase of 10 percent of
EnCana's public float

On February 4, the Toronto Stock Exchange (TSX) approved an amendment to
EnCana's Normal Course Issuer Bid (Bid), first approved in October 2004,
increasing the number of common shares available for purchase from 5 percent
of the issued and outstanding shares on October 22, 2004 to 10 percent of the
public float on October 22, 2004. There were approximately 462 million common
shares outstanding on October 22, 2004. The company estimates that 10 percent
of the public float on that date is equal to approximately 46.1 million common
shares.
EnCana's planned divestitures of conventional assets in 2005 are expected
to bring in substantial funds and the company's capital program is expected to
be funded by cash flow. EnCana believes the Bid amendment will provide the
opportunity to increase net asset value per share through share purchases.
To date under its current Bid, EnCana has purchased approximately
21.2 million common shares, representing approximately 4.6 percent of the
company's outstanding common shares on October 22, 2004, at an average price
of US$54.56 per common share. As at January 31, 2005, EnCana had approximately
446 million common shares outstanding. In 2004, approximately 10 million
shares were issued upon the exercise of options by employees as part of the
company's long-term incentive program. Under the amended Bid, the company is
entitled to purchase for cancellation up to an additional 25 million common
shares through the expiry of the amended Bid on October 28, 2005. Purchases
will be made on the open market through the facilities of TSX in accordance
with its policies, and may also be made through the facilities of the NYSE in
accordance with its rules. The price to be paid will be the market price at
the time of acquisition.

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

EnCana targets a net debt-to-capitalization ratio between 30 and
40 percent. At December 31, 2004, the company's net debt-to-capitalization
ratio was 33:67. EnCana's net debt-to-EBITDA multiple, on a trailing 12-month
basis, was 1.4 times.

Capital investment

EnCana has published supplemental information detailing 2004 capital
investment on its Web site, www.encana.com.

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

EnCana Corporation will host a conference call today, Wednesday,
February 23, 2005 starting at 11 a.m., Mountain Time (1 p.m. Eastern
Time), to discuss EnCana's fourth quarter and year-end 2004 financial and
operating results.

To participate, please dial (913) 981-5523 approximately 10 minutes prior
to the conference call. An archived recording of the call will be
available from approximately 5 p.m. MT on February 23 until midnight
March 1, 2005 by dialling (888) 203-1112 or (719) 457-0820 and entering
access code 4871829.

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.
-------------------------------------------------------------------------
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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 well head, 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 and total operating
earnings. Total operating earnings is a non-GAAP measure that shows net
earnings excluding non-operating items such as the after-tax impacts of a
gain on the sale of discontinued operations, the after-tax gain/loss of
unrealized mark-to-market accounting for derivative instruments, the
after-tax gain/loss on translation of U.S. dollar denominated debt issued
in Canada and the effect of the reduction in income tax rates. Management
believes these items reduce the comparability of the company's underlying
financial performance between periods. The majority of the unrealized
gains/losses that relate to U.S. dollar debt issued in Canada are for
debt with maturity dates in excess of five years. These measures have
been described and presented in this news 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 US$35 billion, EnCana is one of
North America's leading natural gas producers, the largest holder of gas and
oil resource lands onshore North America and is a technical and cost leader in
the in-situ recovery of oilsands bitumen. EnCana delivers predictable,
reliable, profitable growth from its portfolio of long-life resource plays
situated in Canada and the United States. Contained in unconventional
reservoirs, resource plays are large contiguous accumulations of hydrocarbons,
located in thick or areally extensive deposits, that typically have low
geological and commercial development risk, low average decline rates and very
long producing lives. The application of technology to unlock the huge
resource potential of these plays typically results in continuous increases in
production and reserves and decreases in costs over multiple decades of
resource play life. 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.
In this news release, certain crude oil and NGLs volumes have been
converted to cubic feet equivalent (cfe) on the basis of one barrel (bbl) to
six thousand cubic feet (Mcf). Also, certain natural gas volumes have been
converted to barrels of oil equivalent (BOE) on the same basis. BOE and cfe
may be misleading, particularly if used in isolation. A conversion ratio of
one bbl to six Mcf is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not represent equivalency at
the well head.
Production replacement is calculated by dividing reserve replacement by
production in the same period. Reserve replacement is calculated by summing
the total proved reserves added over a given period, in this case calendar
year 2004, through one or more of revisions, improved recovery, extensions,
discoveries and acquisitions net of divestitures. Reserve replacement cost is
calculated by dividing total capital invested in finding, development and net
acquisitions by reserve replacement in the same period. EnCana uses the
aforementioned metrics as indicators of relative performance, along with a
number of other measures. Many performance measures exist. All measures have
limitations and historical measures are not necessarily indicative of future
performance.
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 and operating performance (including
per share growth and increase in net asset value); anticipated life of proved
reserves; anticipated unbooked resource potential; anticipated conversion of
unbooked resource potential to proved reserves; anticipated growth and success
of resource plays and the expected characteristics of resource plays; planned
divestitures of conventional Western Canadian properties, the potential
structure of such transactions and the potential monetization of such assets;
planned sale of interests in the Gulf of Mexico and Ecuador; the expected
proceeds from planned divestitures; expected proportion of total production
and cash flows contributed by natural gas; anticipated success of EnCana's
market risk mitigation strategy and EnCana's ability to participate in
commodity price upside and to protect against high U.S. Rockies gas price
basis differentials; the anticipated steps to implement the proposed two-for-
one share split and the impact of such a split; anticipated purchases pursuant
to the Normal Course Issuer Bid; estimated recycle ratios; potential demand
for gas; anticipated production in 2004 and beyond; anticipated drilling;
potential capital expenditures and investment; potential oil, natural gas and
NGLs 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 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 or the interpretations of such
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 Report
For the period ended December 31, 2004

EnCana Corporation

CONSOLIDATED STATEMENT OF EARNINGS (unaudited)

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

REVENUES, NET OF
ROYALTIES (Note 4)
Upstream $ 2,003 $ 1,462 $ 7,256 $ 5,797
Midstream & Market
Optimization 1,543 1,177 4,749 3,887
Corporate 662 - (195) 2
-------------------------------------------------------------------------
4,208 2,639 11,810 9,686

EXPENSES (Note 4)
Production and
mineral taxes 95 50 311 164
Transportation and
selling 109 143 499 484
Operating 390 296 1,350 1,196
Purchased product 1,367 1,049 4,276 3,455
Depreciation, depletion
and amortization 641 632 2,402 1,989
Administrative 61 52 197 173
Interest, net 113 81 397 283
Accretion of asset
retirement
obligation (Note 10) 6 3 22 17
Foreign exchange
gain (Note 7) (204) (161) (417) (598)
Stock-based
compensation 3 6 17 18
Gain on dispositions (Note 6) (78) (1) (113) (1)
-------------------------------------------------------------------------
2,503 2,150 8,941 7,180
-------------------------------------------------------------------------
NET EARNINGS BEFORE
INCOME TAX 1,705 489 2,869 2,506
Income tax expense (Note 8) 517 42 658 364
-------------------------------------------------------------------------
NET EARNINGS FROM
CONTINUING OPERATIONS 1,188 447 2,211 2,142
NET EARNINGS (LOSS)
FROM DISCONTINUED
OPERATIONS (Note 5) 1,392 (21) 1,302 218
-------------------------------------------------------------------------
NET EARNINGS $ 2,580 $ 426 $ 3,513 $ 2,360
-------------------------------------------------------------------------
-------------------------------------------------------------------------

NET EARNINGS FROM
CONTINUING OPERATIONS
PER COMMON SHARE (Note 13)
Basic $ 2.59 $ 0.97 $ 4.80 $ 4.52
Diluted $ 2.56 $ 0.96 $ 4.72 $ 4.47
-------------------------------------------------------------------------
-------------------------------------------------------------------------

NET EARNINGS PER
COMMON SHARE (Note 13)
Basic $ 5.62 $ 0.92 $ 7.63 $ 4.98
Diluted $ 5.55 $ 0.91 $ 7.51 $ 4.92
-------------------------------------------------------------------------
-------------------------------------------------------------------------


CONSOLIDATED STATEMENT OF RETAINED EARNINGS
(unaudited)
Year Ended December 31
----------------------
(US$ millions) 2004 2003
-------------------------------------------------------------------------

RETAINED EARNINGS, BEGINNING OF YEAR $ 5,276 $ 3,523
Net Earnings 3,513 2,360
Dividends on Common Shares (183) (139)
Charges for Normal Course Issuer Bid (Note 11) (671) (468)
-------------------------------------------------------------------------
RETAINED EARNINGS, END OF YEAR $ 7,935 $ 5,276
-------------------------------------------------------------------------
-------------------------------------------------------------------------

See accompanying Notes to Consolidated Financial Statements.



CONSOLIDATED BALANCE SHEET (unaudited)

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

ASSETS
Current Assets
Cash and cash equivalents $ 602 $ 113
Accounts receivable and accrued
revenues 1,898 1,165
Risk management (Note 14) 336 -
Inventories 513 557
Assets of discontinued operations (Note 5) 156 781
-------------------------------------------------------------------------
3,505 2,616
Property, Plant and Equipment, net (Note 4) 23,140 17,770
Investments and Other Assets 334 268
Risk Management (Note 14) 87 -
Assets of Discontinued Operations (Note 5) 1,623 1,545
Goodwill 2,524 1,911
-------------------------------------------------------------------------
(Note 4) $ 31,213 $ 24,110
-------------------------------------------------------------------------
-------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued
liabilities $ 1,879 $ 1,348
Income tax payable 359 32
Risk management (Note 14) 241 -
Liabilities of discontinued
operations (Note 5) 280 405
Current portion of long-term debt (Note 9) 188 287
-------------------------------------------------------------------------
2,947 2,072
Long-Term Debt (Note 9) 7,742 6,088
Other Liabilities 118 21
Risk Management (Note 14) 192 -
Asset Retirement Obligation (Note 10) 611 383
Liabilities of Discontinued
Operations (Note 5) 102 112
Future Income Taxes 5,193 4,156
-------------------------------------------------------------------------
16,905 12,832
-------------------------------------------------------------------------
Shareholders' Equity
Share capital (Note 11) 5,299 5,305
Share options, net 10 55
Paid in surplus 28 18
Retained earnings 7,935 5,276
Foreign currency translation adjustment 1,036 624
-------------------------------------------------------------------------
14,308 11,278
-------------------------------------------------------------------------
$ 31,213 $ 24,110
-------------------------------------------------------------------------
-------------------------------------------------------------------------

See accompanying Notes to Consolidated Financial Statements.



CONSOLIDATED STATEMENT OF CASH FLOWS (unaudited)

December 31
---------------------------------------
Three Months Ended Year Ended
---------------------------------------
(US$ millions) 2004 2003 2004 2003
-------------------------------------------------------------------------

OPERATING ACTIVITIES
Net earnings from
continuing operations $ 1,188 $ 447 $ 2,211 $ 2,142
Depreciation, depletion
and amortization 641 632 2,402 1,989
Future income taxes (Note 8) 461 136 91 477
Unrealized (gain)
loss on risk
management (Note 14) (662) - 190 -
Unrealized foreign
exchange gain (Note 7) (163) (141) (285) (545)
Accretion of asset
retirement
obligation (Note 10) 6 3 22 17
Gain on dispositions (Note 6) (78) (1) (113) (1)
Other 36 27 87 56
-------------------------------------------------------------------------
Cash flow from
continuing operations 1,429 1,103 4,605 4,135
Cash flow from
discontinued operations 62 151 375 324
-------------------------------------------------------------------------
Cash flow 1,491 1,254 4,980 4,459
Net change in other
assets and liabilities (105) (2) (176) (84)
Net change in non-cash
working capital from
continuing operations 1,857 (416) 1,455 (568)
Net change in non-cash
working capital from
discontinued operations (1,955) 96 (1,668) 497
-------------------------------------------------------------------------
1,288 932 4,591 4,304
-------------------------------------------------------------------------

INVESTING ACTIVITIES
Business combination
with Tom Brown, Inc. (Note 3) - - (2,335) -
Capital expenditures (Note 4) (1,509) (1,406) (4,817) (4,627)
Proceeds on disposal
of assets (Note 4) 72 282 1,144 301
Dispositions
(acquisitions) (Note 6) 99 - 386 (91)
Equity investments (5) (3) 47 (6)
Net change in investments
and other 70 17 45 (15)
Net change in non-cash
working capital from
continuing operations 77 - (21) (113)
Discontinued operations 1,891 (240) 1,292 822
-------------------------------------------------------------------------
695 (1,350) (4,259) (3,729)
-------------------------------------------------------------------------

FINANCING ACTIVITIES
Net issuance of revolving
long-term debt 287 26 72 288
Issuance of long-term debt - 500 3,761 500
Repayment of long-term debt (1,005) - (2,759) (142)
Issuance of common
shares (Note 11) 97 19 281 114
Purchase of common
shares (Note 11) (774) (186) (1,004) (868)
Dividends on common
shares (46) (36) (183) (139)
Other 6 (8) (5) (13)
Discontinued operations - - - (282)
-------------------------------------------------------------------------
(1,435) 315 163 (542)
-------------------------------------------------------------------------

DEDUCT: FOREIGN EXCHANGE
LOSS ON CASH AND CASH
EQUIVALENTS HELD IN
FOREIGN CURRENCY 6 1 6 10
-------------------------------------------------------------------------

INCREASE (DECREASE) IN
CASH AND CASH EQUIVALENTS 542 (104) 489 23
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD 60 217 113 90
-------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS,
END OF YEAR $ 602 $ 113 $ 602 $ 113
-------------------------------------------------------------------------
-------------------------------------------------------------------------

See accompanying Notes to Consolidated Financial Statements.



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, crude oil and natural gas
liquids, as well as natural gas storage, 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

Consolidation of Variable Interest Entities

On November 1, 2004, the Company retroactively adopted the new Canadian
Institute of Chartered Accountants' ("CICA") Accounting Guideline 15
("AcG - 15") "Consolidation of Variable Interest Entities". The guideline
defines a variable interest entity ("VIE") as a legal entity in which
either the total equity at risk is not sufficient to permit the entity to
finance its activities without additional subordinated financial support
provided by other parties or the equity owners lack a controlling
financial interest. The guideline requires the enterprise which absorbs
the majority of a VIE's expected gains or losses, the primary
beneficiary, to consolidate the VIE.

There was no effect on the Company's Consolidated Financial Statements
prior to the adoption of the guideline on November 1, 2004. Subsequent to
November 1, 2004, the Company became the primary beneficiary of a VIE.
At December 31, 2004, the Company has consolidated the results for this
entity as described in Note 4.

Hedging Relationships

On January 1, 2004, the Company adopted the amendments made to the CICA
Accounting Guideline 13 ("AcG - 13") "Hedging Relationships", and
Emerging Issues Committee Abstract 128 ("EIC 28") "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 elected not to designate any of
its risk management activities in place at December 31, 2003 as
accounting hedges under AcG - 13 and, accordingly, has accounted 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 December 31,
2004, a net unrealized gain remains to be recognized over the next four
years as follows:

Unrealized Gain
-------------------------------------------------------------------------

2005
Quarter 1 $ -
Quarter 2 14
Quarter 3 9
Quarter 4 9
-------------------------------------------------------------------------
Total to be recognized in 2005 $ 32
-------------------------------------------------------------------------

2006 $ 24
2007 15
2008 1
-------------------------------------------------------------------------
Total to be recognized in 2006 through to 2008 $ 40
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Total to be recognized $ 72
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Total to be recognized - Continuing Operations $ 73
Total to be recognized - Discontinued Operations (1)
-------------------------------------------------------------------------
$ 72
-------------------------------------------------------------------------
-------------------------------------------------------------------------

At December 31, 2004, the remaining deferred gains related to continuing
operations totalled $73 million of which $11 million was recorded in
Accounts receivable and accrued revenues, $4 million in Investments and
other assets, $44 million in Accounts payable and accrued liabilities and
$44 million in Other liabilities.

3. BUSINESS COMBINATION WITH TOM BROWN, INC.

In May 2004, the Company completed the tender offer for the common shares
of Tom Brown, Inc., a Denver based independent energy company, for total
cash consideration of $2.3 billion plus the assumption of $406 million of
long-term debt.

The business combination has been accounted for using the purchase method
with the results of operations of Tom Brown, Inc. included in the
Consolidated Financial Statements from the date of acquisition.

The calculation of the purchase price and the allocation to assets and
liabilities is shown below.

-------------------------------------------------------------------------
Calculation of Purchase Price
Cash paid for common shares of Tom Brown, Inc. $ 2,341
Transaction costs 13
-------------------------------------------------------------------------
Total purchase price $ 2,354

Plus: Fair value of liabilities assumed
Current liabilities 224
Long-term debt 406
Other non-current liabilities 39
Future income taxes 774
-------------------------------------------------------------------------
Total Purchase Price and Liabilities Assumed $ 3,797
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Fair Value of Assets Acquired
Current assets (including cash acquired of $19 million) $ 425
Property, plant and equipment, net 2,890
Other non-current assets 9
Goodwill 473
-------------------------------------------------------------------------
Total Fair Value of Assets Acquired $ 3,797
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Included in current assets as Assets held for sale is $263 million
related to the value of certain oil and gas properties located in west
Texas and New Mexico and the assets of Sauer Drilling Company, a
subsidiary of Tom Brown, Inc., for which the Company has entered into
purchase and sale agreements. These sales were completed on July 30,
2004.

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

- Midstream & Market Optimization is conducted by the Midstream &
Marketing division. Midstream includes natural gas storage,
natural gas liquids processing and power generation. The Marketing
groups' primary responsibility is the sale of the Company's
proprietary production. The results are included in the Upstream
segment. Correspondingly, the Marketing groups also undertake market
optimization activities which comprise third party purchases and sales
of product that provide operational flexibility for transportation
commitments, product type, delivery points and customer
diversification. These activities are reflected in the Midstream &
Market Optimization segment.

- 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 & Market Optimization purchases substantially 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 Continuing Operations
(For the three months ended December 31)

Midstream & Market
Upstream Optimization
---------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 2,003 $ 1,462 $ 1,543 $ 1,177
Expenses
Production and mineral taxes 95 50 - -
Transportation and selling 102 132 7 11
Operating 286 213 101 83
Purchased product - - 1,367 1,049
Depreciation, depletion and
amortization 614 596 10 27
-------------------------------------------------------------------------
Segment Income $ 906 $ 471 $ 58 $ 7
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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

Revenues, Net of Royalties(x) $ 662 $ - $ 4,208 $ 2,639
Expenses
Production and mineral taxes - - 95 50
Transportation and selling - - 109 143
Operating 3 - 390 296
Purchased product - - 1,367 1,049
Depreciation, depletion and
amortization 17 9 641 632
-------------------------------------------------------------------------
Segment Income $ 642 $ (9) 1,606 469
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Administrative 61 52
Interest, net 113 81
Accretion of asset retirement
obligation 6 3
Foreign exchange gain (204) (161)
Stock-based compensation 3 6
Gain on dispositions (78) (1)
-------------------------------------------------------------------------
(99) (20)
-------------------------------------------------------------------------
Net Earnings Before Income Tax 1,705 489
Income tax expense 517 42
-------------------------------------------------------------------------
Net Earnings From Continuing Operations $ 1,188 $ 447
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x) Corporate revenue primarily reflects unrealized gains or losses
recorded on derivative instruments. See also Note 14.


Upstream Canada United States
---------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 1,313 $ 1,131 $ 628 $ 298
Expenses
Production and mineral taxes 26 23 69 27
Transportation and selling 75 102 27 30
Operating 180 160 39 17
Depreciation, depletion and
amortization 455 422 145 82
-------------------------------------------------------------------------
Segment Income $ 577 $ 424 $ 348 $ 142
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Other Total Upstream
---------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 62 $ 33 $ 2,003 $ 1,462
Expenses
Production and mineral taxes - - 95 50
Transportation and selling - - 102 132
Operating 67 36 286 213
Depreciation, depletion and
amortization 14 92 614 596
-------------------------------------------------------------------------
Segment Income $ (19) $ (95) $ 906 $ 471
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Midstream & Market Optimization
Total Midstream
Market & Market
Midstream Optimization Optimization
-----------------------------------------------------
2004 2003 2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues $ 569 $ 438 $ 974 $ 739 $ 1,543 $ 1,177
Expenses
Transportation and
selling - - 7 11 7 11
Operating 87 73 14 10 101 83
Purchased product 416 339 951 710 1,367 1,049
Depreciation,
depletion and
amortization 10 22 - 5 10 27
-------------------------------------------------------------------------
Segment Income $ 56 $ 4 $ 2 $ 3 $ 58 $ 7
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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


Produced Gas Produced Gas
-----------------------------------------------------
Canada United States Total
-------------------------------------------------------------------------
2004 2003 2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues, Net
of Royalties $ 1,041 $ 862 $ 578 $ 275 $ 1,619 $ 1,137
Expenses
Production
and mineral
taxes 19 19 63 24 82 43
Transportation
and selling 74 81 27 30 101 111
Operating 103 84 39 17 142 101
-------------------------------------------------------------------------
Operating
Cash Flow $ 845 $ 678 $ 449 $ 204 $ 1,294 $ 882
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Oil & NGLs Oil & NGLs
-----------------------------------------------------
Canada United States Total
-------------------------------------------------------------------------
2004 2003 2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues, Net
of Royalties $ 272 $ 269 $ 50 $ 23 $ 322 $ 292
Expenses
Production
and mineral
taxes 7 4 6 3 13 7
Transportation
and selling 1 21 - - 1 21
Operating 77 76 - - 77 76
-------------------------------------------------------------------------
Operating
Cash Flow $ 187 $ 168 $ 44 $ 20 $ 231 $ 188
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Other & Total Upstream Other Total Upstream
---------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 62 $ 33 $ 2,003 $ 1,462
Expenses
Production and mineral taxes - - 95 50
Transportation and selling - - 102 132
Operating 67 36 286 213
-------------------------------------------------------------------------
Operating Cash Flow $ (5) $ (3) $ 1,520 $ 1,067
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Results of Continuing Operations (For the year ended December 31)

Midstream & Market
Upstream Optimization
---------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 7,256 $ 5,797 $ 4,749 $ 3,887
Expenses
Production and mineral taxes 311 164 - -
Transportation and selling 472 429 27 55
Operating 1,026 872 325 324
Purchased product - - 4,276 3,455
Depreciation, depletion and
amortization 2,271 1,900 70 48
-------------------------------------------------------------------------
Segment Income $ 3,176 $ 2,432 $ 51 $ 5
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Corporate Consolidated
---------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------
Revenues, Net of Royalties(x) $ (195) $ 2 $ 11,810 $ 9,686
Expenses
Production and mineral taxes - - 311 164
Transportation and selling - - 499 484
Operating (1) - 1,350 1,196
Purchased product - - 4,276 3,455
Depreciation, depletion and
amortization 61 41 2,402 1,989
-------------------------------------------------------------------------
Segment Income $ (255) $ (39) 2,972 2,398
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Administrative 197 173
Interest, net 397 283
Accretion of asset retirement obligation 22 17
Foreign exchange gain (417) (598)
Stock-based compensation 17 18
Gain on dispositions (113) (1)
-------------------------------------------------------------------------
103 (108)
-------------------------------------------------------------------------
Net Earnings Before Income Tax 2,869 2,506
Income tax expense 658 364
-------------------------------------------------------------------------
Net Earnings From Continuing Operations $ 2,211 $ 2,142
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(x) Corporate revenue primarily reflects unrealized gains or losses
recorded on derivative instruments. See also Note 14.


Upstream Canada United States
---------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 5,083 $ 4,474 $ 1,941 $ 1,143
Expenses
Production and mineral taxes 87 56 224 108
Transportation and selling 352 343 120 86
Operating 685 642 119 60
Depreciation, depletion and
amortization 1,751 1,511 475 293
-------------------------------------------------------------------------
Segment Income $ 2,208 $ 1,922 $ 1,003 $ 596
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Transportation and selling for the United States includes a one-time
payment of $21 million made in Q2 2004 to terminate a long-term physical
delivery contract.

Other Total Upstream
---------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 232 $ 180 $ 7,256 $ 5,797
Expenses
Production and mineral taxes - - 311 164
Transportation and selling - - 472 429
Operating 222 170 1,026 872
Depreciation, depletion and
amortization 45 96 2,271 1,900
-------------------------------------------------------------------------
Segment Income $ (35) $ (86) $ 3,176 $ 2,432
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Total Midstream
Midstream & Market Market & Market
Optimization Midstream Optimization Optimization
-----------------------------------------------------
2004 2003 2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues $ 1,450 $ 1,084 $ 3,299 $ 2,803 $ 4,749 $ 3,887
Expenses
Transportation
and selling - - 27 55 27 55
Operating 279 261 46 63 325 324
Purchased product 1,071 762 3,205 2,693 4,276 3,455
Depreciation,
depletion and
amortization 68 40 2 8 70 48
-------------------------------------------------------------------------
Segment Income $ 32 $ 21 $ 19 $ (16) $ 51 $ 5
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Midstream Depreciation, depletion and amortization includes a $35 million
impairment charge made in Q2 2004 on the Company's interest in Oleoducto
Trasandino in Argentina and Chile.


Upstream Geographic and Product Information (Continuing Operations)
(For the year ended December 31)


Produced Gas Produced Gas
-----------------------------------------------------
Canada United States Total
-----------------------------------------------------
2004 2003 2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues, Net of
Royalties $ 3,928 $ 3,396 $ 1,776 $ 1,051 $ 5,704 $ 4,447
Expenses
Production and
mineral taxes 65 52 205 101 270 153
Transportation and
selling 296 274 120 86 416 360
Operating 400 342 119 60 519 402
-------------------------------------------------------------------------
Operating Cash Flow $ 3,167 $ 2,728 $ 1,332 $ 804 $ 4,499 $ 3,532
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Transportation and selling for the United States includes a one-time
payment of $21 million made in Q2 2004 to terminate a long-term physical
delivery contract.

Oil & NGLs Oil & NGLs
-----------------------------------------------------
Canada United States Total
-----------------------------------------------------
2004 2003 2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues, Net of
Royalties $ 1,155 $ 1,078 $ 165 $ 92 $ 1,320 $ 1,170
Expenses
Production and
mineral taxes 22 4 19 7 41 11
Transportation and
selling 56 69 - - 56 69
Operating 285 300 - - 285 300
-------------------------------------------------------------------------
Operating Cash Flow $ 792 $ 705 $ 146 $ 85 $ 938 $ 790
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Other & Total Upstream Other Total Upstream
---------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 232 $ 180 $ 7,256 $ 5,797
Expenses
Production and mineral taxes - - 311 164
Transportation and selling - - 472 429
Operating 222 170 1,026 872
-------------------------------------------------------------------------
Operating Cash Flow $ 10 $ 10 $ 5,447 $ 4,332
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Capital Expenditures (Continuing Operations)

Three Months Ended Year Ended
December 31, December 31,
---------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Upstream
Canada $ 742 $ 911 $ 3,079 $ 3,198
United States 695 342 1,549 968
Other Countries 30 15 79 78
-------------------------------------------------------------------------
1,467 1,268 4,707 4,244
Midstream & Market Optimization 24 69 64 276
Corporate 18 69 46 107
-------------------------------------------------------------------------
Total $ 1,509 $ 1,406 $ 4,817 $ 4,627
-------------------------------------------------------------------------
-------------------------------------------------------------------------

On December 17, 2004, the Company acquired certain natural gas and crude
oil properties in Texas for approximately $251 million. The purchase was
facilitated by an unrelated party, Brown Ranger LLC, which holds the
assets in trust for the Company. Pursuant to the agreement with Brown
Ranger LLC, the Company operates the properties, receives all the revenue
and pays all of the expenses associated with the properties. The assets
will be transferred to the Company at the earlier of June 15, 2005 or
upon the disposition of certain natural gas and crude oil properties by
the Company. The Company has determined that the relationship with Brown
Ranger LLC represents an interest in a VIE and that the Company is the
primary beneficiary of the VIE. The Company has consolidated Brown Ranger
LLC from the date of acquisition.

In addition to the capital expenditures, during 2004, the Company
divested of mature conventional oil and natural gas assets and other
property, plant and equipment for proceeds of $1,144 million (2003 -
$301 million).

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

Upstream $ 22,097 $ 16,757 $ 26,118 $ 19,416
Midstream & Market
Optimization 804 784 1,904 1,879
Corporate 239 229 1,412 489
Assets of Discontinued
Operations (Note 5) 1,779 2,326
-------------------------------------------------------------------------
Total $ 23,140 $ 17,770 $ 31,213 $ 24,110
-------------------------------------------------------------------------
-------------------------------------------------------------------------


5. DISCONTINUED OPERATIONS

On December 1, 2004, the Company completed the sale of its 100 percent
interest in EnCana (U.K.) Limited for net cash consideration of
approximately $2.1 billion. The Company's U.K. operations included crude
oil and natural gas interests in the U.K. central North Sea including the
Buzzard, Scott and Telford oil fields, as well as other satellite
discoveries and exploration licenses. The majority of the Company's
revenue in the United Kingdom was earned from a single customer who has a
high quality investment grade credit rating. A gain on sale of
approximately $1.4 billion was recorded. Accordingly, these operations
have been accounted for as discontinued operations.

At December 31, 2004, the Company has decided to divest of its Ecuador
operations and such operations have been accounted for as discontinued
operations. The Company's Ecuador operations include the 100 percent
working interest in the Tarapoa Block, majority operating interest in
Blocks 14, 17 and Shiripuno, the non-operated economic interest in
Block 15 and the 36.3 percent indirect equity investment in Oleoducto de
Crudos Pesados (OCP) Ltd. ("OCP"), which is the owner of a crude oil
pipeline in Ecuador that ships crude oil from the producing areas of
Ecuador to an export marine terminal. The Company is a shipper on the OCP
Pipeline and pays commercial rates for tariffs. The majority of the
Company's crude oil produced in Ecuador is sold to a single marketing
company. Payments are secured by letters of credit from a major financial
institution which has a high quality investment grade credit rating.

In 2003, in two separate transactions, the Company completed the sale of
its 13.75 percent working interest and a gross overriding royalty in the
Syncrude Joint Venture ("Syncrude") for net cash consideration of
$999 million.

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 $1 billion, including
assumption of related long-term debt by the purchaser, and recorded an
after-tax gain on sale of $169 million.

The following tables present the effect of the discontinued operations on
the Consolidated Statement of Earnings:


Consolidated Statement of Earnings

For the three months ended December 31
-----------------------------------------------------

Ecuador United Kingdom Syncrude
-----------------------------------------------------
2004 2003 2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues, Net of
Royalties $ 173 $ 166 $ 27 $ 45 $ (1) $ -
-------------------------------------------------------------------------

Expenses
Production and
mineral taxes 19 8 - - - -
Transportation and
selling 11 21 7 6 - -
Operating 36 33 4 8 - -
Depreciation,
depletion and
amortization 66 72 25 21 - -
Interest, net (2) 4 (4) - - -
Accretion of asset
retirement
obligation - - - 1 - -
Foreign exchange
loss (gain) 4 1 (5) (5) - -
(Gain) loss on
dispositions - - (1) 1 - -
(Gain) loss on
discontinuance - - (1,364) - 2 -
-------------------------------------------------------------------------
134 139 (1,338) 32 2 -
-------------------------------------------------------------------------
Net Earnings (Loss)
Before Income Tax 39 27 1,365 13 (3) -
Income tax
(recovery) expense (1) 44 10 17 - -
-------------------------------------------------------------------------
Net Earnings (Loss)
From Discontinued
Operations $ 40 $ (17) $ 1,355 $ (4) $ (3) $ -
-------------------------------------------------------------------------
-------------------------------------------------------------------------


For the three months
ended December 31
---------------------------
Midstream
- Pipelines Total
---------------------------
2003 2004 2003
-----------------------------------------------

Revenues, Net of
Royalties $ - $ 199 $ 211
-----------------------------------------------

Expenses
Production and
mineral taxes - 19 8
Transportation and
selling - 18 27
Operating - 40 41
Depreciation,
depletion and
amortization - 91 93
Interest, net - (6) 4
Accretion of asset
retirement
obligation - - 1
Foreign exchange
loss (gain) - (1) (4)
(Gain) loss on
dispositions - (1) 1
(Gain) loss on
discontinuance - (1,362) -
-----------------------------------------------
- (1,202) 171
-----------------------------------------------
Net Earnings (Loss)
Before Income Tax - 1,401 40
Income tax
(recovery) expense - 9 61
-----------------------------------------------
Net Earnings (Loss)
From Discontinued
Operations $ - $ 1,392 $ (21)
-----------------------------------------------
-----------------------------------------------

Included in United Kingdom Revenues, Net of Royalties for the three
months ended December 31, 2004 is $43 million related to realized losses
on terminated risk management contracts for the United Kingdom crude oil
volumes.

Consolidated Statement of Earnings

For the year ended December 31
-----------------------------------------------------

Ecuador United Kingdom Syncrude
-----------------------------------------------------
2004 2003 2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues, Net of
Royalties $ 471 $ 412 $ 153 $ 118 $ (1) $ 87
-------------------------------------------------------------------------

Expenses
Production and
mineral taxes 61 25 - - - -
Transportation
and selling 60 45 36 16 - 2
Operating 125 83 36 18 - 46
Depreciation,
depletion and
amortization 263 159 118 74 - 7
Interest, net (3) 4 (9) - - -
Accretion of asset
retirement
obligation 1 1 3 1 - -
Foreign exchange
loss (gain) 5 2 (2) (5) - -
(Gain) loss on
dispositions - - (1) 1 - -
(Gain) loss on
discontinuance - - (1,364) - 2 -
-------------------------------------------------------------------------
512 319 (1,183) 105 2 55
-------------------------------------------------------------------------
Net Earnings (Loss)
Before Income Tax (41) 93 1,336 13 (3) 32
Income tax
(recovery) expense (8) 61 (2) 20 - 8
-------------------------------------------------------------------------
Net Earnings (Loss)
From Discontinued
Operations $ (33) $ 32 $ 1,338 $ (7) $ (3) $ 24
-------------------------------------------------------------------------
-------------------------------------------------------------------------


For the year
ended December 31
---------------------------
Midstream
- Pipelines Total
---------------------------
2003 2004 2003
-----------------------------------------------

Revenues, Net of
Royalties $ - $ 623 $ 617
-----------------------------------------------

Expenses
Production and
mineral taxes - 61 25
Transportation
and selling - 96 63
Operating - 161 147
Depreciation,
depletion and
amortization - 381 240
Interest, net - (12) 4
Accretion of asset
retirement
obligation - 4 2
Foreign exchange
loss (gain) - 3 (3)
(Gain) loss on
dispositions - (1) 1
(Gain) loss on
discontinuance (220) (1,362) (220)
-----------------------------------------------
(220) (669) 259
-----------------------------------------------
Net Earnings (Loss)
Before Income Tax 220 1,292 358
Income tax
(recovery) expense 51 (10) 140
-----------------------------------------------
Net Earnings (Loss)
From Discontinued
Operations $ 169 $ 1,302 $ 218
-----------------------------------------------
-----------------------------------------------


Consolidated Balance Sheet

The impact of the discontinued operations in the Consolidated Balance
Sheet is as follows:

As at December 31
--------------------------------------------------------
United United
Ecuador Kingdom Syncrude Total Ecuador Kingdom Total
--------------------------------------------------------
2004 2003
-------------------------------------------------------------------------
Assets
Cash and cash
equivalents $ 2 $ 12 $ - $ 14 $ 2 $ 33 $ 35
Accounts
receivable and
accrued revenues 111 13 - 124 79 123 202
Risk management 3 - - 3 - - -
Inventories 15 - - 15 16 - 16
-------------------------------------------------------------------------
131 25 - 156 97 156 253
Property, plant
and equipment,
net 1,295 - - 1,295 1,254 521 1,775
Investments and
other assets 328 - - 328 291 7 298
-------------------------------------------------------------------------
$1,754 $ 25 $ - $1,779 $1,642 $ 684 $2,326
-------------------------------------------------------------------------
Liabilities
Accounts payable
and accrued
liabilities $ 61 $ 32 $ 3 $ 96 $ 103 $ 128 $ 231
Income tax
payable 101 - - 101 33 - 33
Risk management 72 - - 72 - - -
-------------------------------------------------------------------------
234 32 3 269 136 128 264
Asset retirement
obligation 22 - - 22 19 28 47
Future income
taxes 80 11 - 91 93 113 206
-------------------------------------------------------------------------
336 43 3 382 248 269 517
-------------------------------------------------------------------------
Net Assets of
Discontinued
Operations $1,418 $ (18) $ (3) $1,397 $1,394 $ 415 $1,809
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Acquisition / Disposition

On January 31, 2003, the Company acquired the Ecuador interests of
Vintage Petroleum Inc. ("Vintage") for net cash consideration of
$116 million. During the fourth quarter of 2003, the Company disposed of
its interest in Block 27 in Ecuador for approximately $14 million.

Contingencies

In Ecuador, a subsidiary of the Company has a 40 percent non-operated
economic interest in relation to Block 15 pursuant to a contract with a
subsidiary of Occidental Petroleum Corporation. During the third quarter,
Occidental Petroleum Corporation filed a Form 8-K indicating that its
subsidiary had received formal notification from Petroecuador, the state
oil company of Ecuador, initiating proceedings to determine if the
subsidiary had violated the Hydrocarbons Law and its Participation
Contract for Block 15 with Petroecuador and whether such violations
constitute grounds for terminating the Participation Contract.

In its Form 8-K, Occidental Petroleum Corporation indicated that it
believes it has complied with all material obligations under the
Participation Contract and that any termination of the Participation
Contract by Ecuador based upon these stated allegations would be
unfounded and would constitute an unlawful expropriation under
international treaties.

In addition to the above, the Company is proceeding with its arbitration
related to value-added tax ("VAT") owed to the Company and is in
discussions related to certain income tax matters related to interest
deductibility in Ecuador.

6. DISPOSITIONS (ACQUISITIONS)

On December 22, 2004, the Company sold its interest in the Alberta Ethane
Gathering System Joint Venture for approximately $108 million, including
working capital. A $54 million pre-tax gain was recorded on this sale. On
December 15, 2004, the Company sold its 25 percent limited partnership
interest in Kingston CoGen Limited Partnership for net cash consideration
of $25 million, recording a pre-tax gain on sale of $28 million.

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

On February 18, 2004, the Company sold its 53.3 percent interest in
Petrovera Resources ("Petrovera") for approximately $287 million,
including working capital adjustments. In order to facilitate the
transaction, the Company 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 $540 million, including working capital
adjustments. In accordance with full cost accounting for oil and gas
activities, proceeds were credited to property, plant and equipment.

On July 18, 2003, the Company acquired the common shares of Savannah
Energy Inc. ("Savannah") for net cash consideration of $91 million.
Savannah's operations are in Texas, USA. This purchase was accounted for
using the purchase method with the results reflected in the consolidated
results of the Company from the date of acquisition.

Other dispositions of discontinued operations are disclosed in Note 5.

7. FOREIGN EXCHANGE GAIN

Three Months Ended Year Ended
December 31, December 31,
---------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Unrealized Foreign Exchange Gain
on Translation of U.S. Dollar
Debt Issued in Canada $ (163) $ (141) $ (285) $ (545)
Realized Foreign Exchange Gains (41) (20) (132) (53)
-------------------------------------------------------------------------
$ (204) $ (161) $ (417) $ (598)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

8. INCOME TAXES

The provision for income taxes is as follows:

Three Months Ended Year Ended
December 31, December 31,
---------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Current
Canada $ 89 $ (118) $ 594 $ (136)
United States (30) 29 (12) 39
Other (3) (5) (15) (16)
-------------------------------------------------------------------------
Total Current Tax 56 (94) 567 (113)
Future 461 133 200 836
Future Tax Rate Reductions(x) - 3 (109) (359)
-------------------------------------------------------------------------
Total Future Tax 461 136 91 477
-------------------------------------------------------------------------
$ 517 $ 42 $ 658 $ 364
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(x) 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 Year Ended
December 31, December 31,
---------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Net Earnings Before Income Tax $ 1,705 $ 489 $ 2,869 $ 2,506
Canadian Statutory Rate 39.1% 41.0% 39.1% 41.0%
-------------------------------------------------------------------------
Expected Income Tax 667 200 1,123 1,026

Effect on Taxes Resulting from:
Non-deductible Canadian crown
payments 38 55 192 231
Canadian resource allowance (59) (52) (246) (258)
Canadian resource allowance on
unrealized risk management losses (37) - (10) -
Statutory and other rate
differences (10) (24) (55) (45)
Effect of tax rate changes - 3 (109) (359)
Non-taxable capital gains (50) (48) (91) (119)
Previously unrecognized capital
losses 7 (48) 17 (119)
Tax basis retained on dispositions (17) - (179) -
Large corporations tax 11 2 24 27
Other (33) (46) (8) (20)
-------------------------------------------------------------------------
$ 517 $ 42 $ 658 $ 364
-------------------------------------------------------------------------
Effective Tax Rate 30.3% 8.6% 22.9% 14.5%
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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

Canadian Dollar Denominated Debt
Revolving credit and term loan borrowings $ 1,515 $ 1,425
Unsecured notes and debentures 1,309 1,335
Preferred securities - 252
-------------------------------------------------------------------------
2,824 3,012
-------------------------------------------------------------------------

U.S. Dollar Denominated Debt
Revolving credit and term loan borrowings 399 417
Unsecured notes and debentures 4,641 2,713
Preferred securities - 150
-------------------------------------------------------------------------
5,040 3,280
-------------------------------------------------------------------------

Increase in Value of Debt Acquired(x) 66 83
Current Portion of Long-Term Debt (188) (287)
-------------------------------------------------------------------------
$ 7,742 $ 6,088
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(x) Certain of the notes and debentures of the Company were acquired in
business combinations and were accounted for at their fair value at
the dates 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 22
years.

To fund the acquisition of Tom Brown, Inc., the Company arranged a
$3 billion non-revolving term loan facility with a group of the
Company's lenders. At December 31, 2004, the facility has been
completely repaid and cancelled.

10. 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:

As at As at
December 31, December 31,
2004 2003
-------------------------------------------------------------------------

Asset Retirement Obligation, Beginning of Year $ 383 $ 288
Liabilities Incurred 98 45
Liabilities Settled (16) (23)
Liabilities Disposed (35) -
Change in Estimated Future Cash Flows 124 -
Accretion Expense 22 17
Other 35 56
-------------------------------------------------------------------------
Asset Retirement Obligation, End of Year $ 611 $ 383
-------------------------------------------------------------------------
-------------------------------------------------------------------------

11. SHARE CAPITAL

December 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 9.7 281 5.5 114
Shares Repurchased (20.0) (287) (23.8) (320)
-------------------------------------------------------------------------
Common Shares Outstanding,
End of Year 450.3 $ 5,299 460.6 $ 5,305
-------------------------------------------------------------------------
-------------------------------------------------------------------------

On October 26, 2004, the Company received regulatory approval for a new
Normal Course Issuer Bid commencing October 29, 2004. Under this bid, the
Company may purchase for cancellation up to 23,114,500 of its Common
Shares, representing five percent of the approximately 462.29 million
Common Shares outstanding as of the filing of the bid on October 22,
2004. On February 4, 2005, the Company received regulatory approval for
an amendment to the Normal Course Issuer Bid which increases the number
of shares available for purchase from five percent of the issued and
outstanding Common Shares to ten percent of the public float of Common
Shares (a total of approximately 46.1 million Common Shares). The current
Normal Course Issuer Bid expires on October 28, 2005.

During the quarter, the Company purchased, for cancellation, 14,493,600
Common Shares (Year-to-date - 19,983,600 Common Shares) for total
consideration of approximately $774 million (Year-to-date -
$1,004 million). Of the total amount paid, $287 million was charged to
Share capital, $46 million was charged to Paid in surplus and $671
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 predecessor 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 December 31, 2004:
Weighted
Stock Average
Options Exercise
(millions) Price (C$)
-------------------------------------------------------------------------

Outstanding, Beginning of Year 28.8 43.13
Exercised (9.7) 36.63
Forfeited (1.0) 47.50
-------------------------------------------------------------------------
Outstanding, End of Year 18.1 46.29
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Exercisable, End of Year 10.8 45.09
-------------------------------------------------------------------------
-------------------------------------------------------------------------



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

13.50 to 19.99 0.1 0.2 18.49 0.1 18.49
20.00 to 24.99 0.6 3.5 22.69 0.6 22.69
25.00 to 29.99 0.4 1.3 26.18 0.4 26.18
30.00 to 43.99 0.5 1.7 40.18 0.4 39.93
44.00 to 53.00 16.5 2.4 47.97 9.3 47.87
-------------------------------------------------------------------------
18.1 2.4 46.29 10.8 45.09
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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. Stock options granted
in 2004 have an associated Tandem Share Appreciation Right attached.
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 December 31, 2004 would have been $2,570 million;
$5.60 per common share - basic; $5.53 per common share - diluted (2003 -
$418 million; $0.90 per common share - basic; $0.90 per common share -
diluted). Pro forma Net Earnings and Net Earnings per Common Share for
the year ended December 31, 2004 would have been $3,476 million;
$7.55 per common share - basic; $7.43 per common share - diluted (2003 -
$2,326 million; $4.91 per common share - basic; $4.85 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:

December 31,
2003
-------------------------------------------------------------------------

Weighted Average Fair Value of Options Granted (C$) $ 12.21
Risk-Free Interest Rate 3.87%
Expected Lives (years) 3.00
Expected Volatility 0.33
Annual Dividend per Share (C$) $ 0.40
-------------------------------------------------------------------------
-------------------------------------------------------------------------

12. COMPENSATION PLANS

The tables below outline certain information related to the Company's
compensation plans at December 31, 2004. Additional information is
contained in Note 16 of the Company's annual audited Consolidated
Financial Statements for the year ended December 31, 2003.

A) Pensions

The following table summarizes the net benefit plan expense:

Three Months Ended Year Ended
December 31, December 31,
--------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Current Service Cost $ 2 $ 1 $ 6 $ 6
Interest Cost 5 3 14 12
Expected Return on Plan Assets (4) (2) (12) (9)
Plan Amendment - 2 - 2
Amortization of Net Actuarial Loss 1 1 4 4
Amortization of Transitional Obligation (1) - (2) (2)
Amortization of Past Service Cost 1 (2) 2 (1)
Expense for Defined Contribution Plan 9 3 19 12
-------------------------------------------------------------------------
Net Benefit Plan Expense $ 13 $ 6 $ 31 $ 24
-------------------------------------------------------------------------
-------------------------------------------------------------------------

At December 31, 2004, $17 million has been contributed to the pension
plans.

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

The following table summarizes the information about SAR's at December
31, 2004:
Weighted
Average
Outstanding Exercise
SAR's Price
-------------------------------------------------------------------------

Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 1,175,070 35.87
Exercised (698,775) 35.48
Forfeited (11,040) 29.25
-------------------------------------------------------------------------
Outstanding, End of Year 465,255 36.61
-------------------------------------------------------------------------
Exercisable, End of Year 465,255 36.61
-------------------------------------------------------------------------
-------------------------------------------------------------------------

U.S. Dollar Denominated (US$)
Outstanding, Beginning of Year 753,417 28.98
Exercised (365,647) 29.19
Forfeited (1,840) 25.29
-------------------------------------------------------------------------
Outstanding, End of Year 385,930 28.80
-------------------------------------------------------------------------
Exercisable, End of Year 385,930 28.80
-------------------------------------------------------------------------
-------------------------------------------------------------------------

The following table summarizes the information about Tandem SAR's at
December 31, 2004:
Weighted
Average
Outstanding Exercise
Tandem SAR's Price
-------------------------------------------------------------------------

Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year - -
Granted 1,080,450 55.31
Forfeited (212,950) 54.37
-------------------------------------------------------------------------
Outstanding, End of Year 867,500 55.54
-------------------------------------------------------------------------
Exercisable, End of Year - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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

The following table summarizes the information about DSU's at December
31, 2004:
Weighted
Average
Outstanding Exercise
DSU's Price
-------------------------------------------------------------------------

Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 319,250 48.68
Granted, Directors 58,931 54.04
Units, in Lieu of Dividends 3,208 59.86
Exercised (6,083) 48.68
-------------------------------------------------------------------------
Outstanding, End of Year 375,306 49.61
-------------------------------------------------------------------------
Exercisable, End of Year 293,955 52.55
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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

The following table summarizes the information about PSU's at December
31, 2004:
Weighted
Average
Outstanding Exercise
PSU's Price
-------------------------------------------------------------------------

Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 126,283 46.52
Granted 1,690,790 53.95
Forfeited (169,970) 53.51
-------------------------------------------------------------------------
Outstanding, End of Year 1,647,103 53.42
-------------------------------------------------------------------------
Exercisable, End of Year - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------

U.S. Dollar Denominated (US$)
Outstanding, Beginning of Year - -
Granted 250,224 41.12
Forfeited (25,609) 41.12
-------------------------------------------------------------------------
Outstanding, End of Year 224,615 41.12
-------------------------------------------------------------------------
Exercisable, End of Year - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------

13. PER SHARE AMOUNTS

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

Three Months Ended Year Ended
--------------------------------------------------
March June September
31, 30, 30, December 31, December 31,
--------------------------------------------------
(millions) 2004 2004 2004 2004 2003 2004 2003
-------------------------------------------------------------------------

Weighted Average
Common Shares
Outstanding - Basic 460.9 460.3 461.7 458.8 462.3 460.4 474.1
Effect of Dilutive
Securities 6.2 5.2 4.5 6.1 3.6 7.6 5.6
-------------------------------------------------------------------------
Weighted Average
Common Shares
Outstanding - Diluted 467.1 465.5 466.2 464.9 465.9 468.0 479.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------

14. 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. None of these risk management contracts qualify or have been
designated as accounting hedges. 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 were not considered accounting
hedges was recorded in the Consolidated Balance Sheet with an offsetting
net deferred loss amount. The deferred loss is recognized into net
earnings over the life of the related contracts. Changes in fair value
after that time are recorded in 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 December 31, 2004:

Net Deferred Total
Amounts Fair Unrealized
Recognized Market Gain/
on Transition Value (Loss)
-------------------------------------------------------------------------

Fair Value of Contracts,
January 1, 2004 (Note 2) $ 235 $ (235) $ -
Change in Fair Value of Contracts
Still Outstanding at December 31,
2004 - 78 78
Fair Value of Contracts Realized
During 2004 (307) 307 -
Fair Value of Contracts Entered
into During 2004 - (339) (339)
-------------------------------------------------------------------------
Fair Value of Contracts Outstanding $ (72) $ (189) $ (261)
-------------------------------------------------------------------------
Premiums Paid on Collars and Options 110
-------------------------------------------------------------------------
Fair Value of Contracts Outstanding
and Premiums Paid, End of Year $ (79)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Amounts Allocated to Continuing
Operations $ (73) $ (10) $ (190)
Amounts Allocated to Discontinued
Operations 1 (69) (71)
-------------------------------------------------------------------------
$ (72) $ (79) $ (261)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

The total realized loss recognized in net earnings for the quarter and
year-to-date ended December 31, 2004 was $155 million ($227 million,
before tax) and $464 million ($686 million, before tax), respectively.

At December 31, 2004, the remaining net deferred amounts recognized on
transition and the risk management amounts are recorded in the
Consolidated Balance Sheet as follows:

As at
December 31,
2004
-------------------------------------------------------------------------

Remaining Deferred Amounts Recognized on Transition
Accounts receivable and accrued revenues $ 11
Investments and other assets 4

Accounts payable and accrued liabilities 44
Other liabilities 44
-------------------------------------------------------------------------
Net Deferred Gain - Continuing Operations $ 73
Net Deferred Loss - Discontinued Operations (1)
-------------------------------------------------------------------------
$ 72
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Risk Management
Current asset $ 336
Long-term asset 87

Current liability 241
Long-term liability 192
-------------------------------------------------------------------------
Net Risk Management Liability - Continuing Operations $ (10)
Net Risk Management Liability - Discontinued Operations (69)
-------------------------------------------------------------------------
$ (79)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

A summary of all unrealized estimated fair value financial positions is
as follows:
As at
December 31,
2004
-------------------------------------------------------------------------

Commodity Price Risk
Natural gas $ 107
Crude oil (143)
Power 2
Foreign Currency Risk -
Interest Rate Risk 24
-------------------------------------------------------------------------
Total Fair Value Positions - Continuing Operations $ (10)
Total Fair Value Positions - Discontinued Operations (69)
-------------------------------------------------------------------------
$ (79)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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 December 31, 2004.

Natural Gas

At December 31, 2004, the Company's gas risk management activities from
financial contracts had an unrealized gain of $36 million and a fair
market value position of $107 million. The contracts were as follows:

Notional Fair
Volumes Market
(MMcf/d) Term Average Price Value
-------------------------------------------------------------------------

Sales Contracts
Fixed Price Contracts
NYMEX Fixed Price 481 2005 6.72 US$/Mcf $ 81
Colorado Interstate Gas
(CIG) 113 2005 4.87 US$/Mcf (27)
Other(1) 110 2005 5.21 US$/Mcf (23)

NYMEX Fixed Price 525 2006 5.66 US$/Mcf (105)
Colorado Interstate Gas
(CIG) 100 2006 4.44 US$/Mcf (37)
Other(1) 171 2006 4.85 US$/Mcf (59)

Collars and Other Options
Purchased NYMEX Put
Options 906 2005 5.46 US$/Mcf 29
Other(2) 5 2005 4.57 - 7.23 US$/Mcf -
NYMEX 3-Way Call Spread 180 2005 5.00/6.69/7.69 US$/Mcf (13)
Purchased NYMEX Put
Options 210 2006 5.00 US$/Mcf 5

Basis Contracts
Fixed NYMEX to AECO Basis 877 2005 (0.66) US$/Mcf 70
Fixed NYMEX to Rockies
Basis 268 2005 (0.49) US$/Mcf 19
Other(3) 442 2005 (0.47) US$/Mcf 4

Fixed NYMEX to AECO Basis 703 2006 (0.65) US$/Mcf 41
Fixed NYMEX to Rockies
Basis 312 2006 (0.57) US$/Mcf 14
Fixed NYMEX to CIG Basis 279 2006 (0.83) US$/Mcf (9)
Other(3) 182 2006 (0.36) US$/Mcf 2

Fixed Rockies to CIG Basis 12 2007 (0.10) US$/Mcf -
Fixed NYMEX to AECO Basis 345 2007-2008 (0.65) US$/Mcf 17
Fixed NYMEX to Rockies
Basis 248 2007-2008 (0.57) US$/Mcf 14
Fixed NYMEX to CIG Basis 110 2007-2009 (0.68) US$/Mcf 5

Purchase Contracts
Fixed Price Contracts
Waha Purchase 27 2005 5.90 US$/Mcf (2)
Waha Purchase 23 2006 5.32 US$/Mcf 3

-------------------------------------------------------------------------
29
Gas Storage Optimization Financial Positions 2
Gas Marketing Financial Positions(4) 5
-------------------------------------------------------------------------
Total Unrealized Gain on Financial Contracts 36
Premiums Paid on Options 71
-------------------------------------------------------------------------
Total Fair Value Positions $ 107
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Other Fixed Price Contracts relate to various price points at San
Juan, Waha, Houston Ship Channel ("HSC"), Colorado Interstate Gas
("CIG") and Rockies.

(2) Other Collars and Other Options relate to collars at Permian, San
Juan, Waha, CIG, HSC, Mid-Continent, Rockies and Texas Oklahoma.

(3) Other Basis Contracts relate to San Juan, CIG, HSC, Mid-Continent,
Waha and Ventura.

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

Crude Oil

At December 31, 2004, the Company's oil risk management activities from
all financial contracts had an unrealized loss of $251 million and a fair
market value position of $(212) million. The contracts were as follows:

Notional Fair
Volumes Average Price Market
(bbl/d) Term (US$/bbl) Value
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Fixed WTI NYMEX Price 41,000 2005 28.41 $ (209)
Costless 3-Way Put
Spread 9,000 2005 20.00/25.00/28.78 (45)
Unwind WTI NYMEX Fixed
Price (4,500) 2005 35.90 11
Purchased WTI NYMEX Call
Options (38,000) 2005 49.76 13
Purchased WTI NYMEX Put
Options 35,000 2005 40.00 13

Fixed WTI NYMEX Price 15,000 2006 34.56 (31)
Purchased WTI NYMEX Put
Options 22,000 2006 27.36 (2)
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(250)
Crude Oil Marketing Financial Positions(1) (1)
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Total Unrealized Loss on Financial Contracts (251)
Premiums Paid on Options 39
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Total Fair Value Positions $ (212)
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Total Fair Value Positions - Continuing Operations (143)
Total Fair Value Positions - Discontinued Operations (69)
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$ (212)
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(1) The crude oil marketing activities are part of the daily ongoing
operations of the Company's proprietary production management.

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

Tracy Weeks
Manager, Investor Relations
403-645-2007

Paul Gagne
Manager, Investor Relations
403-645-4737

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

ECA stock price

TSX $15.12 Can 0.200

NYSE $11.85 USD 0.160

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