EnCana’s third quarter oil and gas sales up 22 percent to 781,000 BOE per day; cash flow exceeds US$1.36 billion

CALGARY, Oct. 27 /CNW/ - EnCana Corporation (TSX & NYSE: ECA) today
reported third quarter sales growth of more than 22 percent to 781,000 barrels
of oil equivalent (BOE) per day, a 40 percent increase in cash flow to
US$1,363 million, or $2.92 per share diluted and a doubling of operating
earnings to $559 million, or $1.20 per share diluted, compared to the third
quarter of 2003.

EnCana reports in U.S. dollars and according to U.S. protocols in order
to facilitate a more direct comparison to other North American upstream oil
and natural gas exploration and development companies. Reserves and production
are reported on an after-royalties basis. All figures are in U.S. dollars
unless otherwise noted.

Third quarter operating earnings rise 104 percent to $559 million
EnCana's third quarter operating earnings of $559 million, or $1.20 per
share diluted, were up 104 percent from $274 million in the third quarter of
2003. Third quarter operating earnings exclude an after-tax unrealized
mark-to-market loss of $321 million related to price hedges and an after-tax
unrealized gain of $155 million due to changes in foreign exchange on
translation related to U.S. dollar denominated debt. After inclusion of these
non-cash items, net earnings in the third quarter were $393 million, or 84
cents per share diluted, up 36 percent from the third quarter 2003. Third
quarter pre-tax cash flow was $1,487 million, up 45 percent from the same
period in 2003. Third quarter after-tax cash flow of $1,363 million, or $2.92
per share diluted, includes a cash tax provision of $124 million, compared
with $51 million of cash taxes in the same 2003 period. Third quarter revenues
net of royalties were $2,458 million.

Third quarter gas sales up 24 percent in past year; oil and NGLs sales up
19 percent
Contributing to EnCana's growth in operating earnings, third quarter
natural gas sales increased 24 percent to 3.13 billion cubic feet per day
compared to the third quarter of 2003. The increase was mainly driven by
strong organic sales growth from resource plays at Greater Sierra, Cutbank
Ridge and Southern Plains shallow gas in Canada and Mamm Creek in the U.S.
Rockies, plus the acquisition of Tom Brown, Inc. (Tom Brown), which added an
average of 275 million cubic feet per day during the quarter. EnCana's third
quarter oil and NGLs sales grew 19 percent to 259,000 barrels per day driven
largely by sales growth from Canadian oilsands, Ecuador and the U.K. North
Sea. Operating costs were $3.38 per BOE, down 4 percent from the third quarter
of 2003. EnCana drilled 1,314 net wells in the third quarter. Core capital
investment, excluding acquisitions and divestitures, was approximately
$1.1 billion during the quarter.

Sales growth on track
EnCana is on track to achieve its 2004 sales guidance of between 725,000
and 765,000 BOE per day, which at the midpoint is a 15 percent increase from
2003 sales volumes. Projected sales are comprised of between 2.95 billion and
3.05 billion cubic feet of natural gas per day and between 235,000 and 255,000
barrels of oil and NGLs per day. Upstream core capital is expected to be in
the range of $4,550 million and $4,850 million for 2004, unchanged from the
company's most recent guidance published in June 2004.

"EnCana continues to create exceptional value through investments in our
portfolio of low-cost, long-life, North American resource plays. These
unconventional assets are delivering unconventional production growth. In 2004
EnCana expects to achieve 15 percent sales growth, 80 percent of which is
organic. Given our share buyback program in 2003 and 2004 to date, this would
result in year-over-year sales growth of about 20 percent per share," said
Gwyn Morgan, EnCana's President & Chief Executive Officer.

Third quarter gas price realizations up 11 percent, oil and NGLs price
realizations up 55 percent
Third quarter realized pre-hedging North American natural gas prices were
up about 11 percent from the third quarter of 2003 to $5.18 per thousand cubic
feet. Realized pre-hedging oil and NGLs prices were up about 55 percent from
the third quarter of 2003 to $32.83 per barrel.

Nine months cash flow exceeds $3.4 billion, sales up 21 percent
Pre-tax cash flow in the first nine months was $4,048 million, up 26
percent from the same 2003 period. After-tax, EnCana generated $3,489 million
of cash flow, or $7.47 per share diluted, in the first nine months of 2004.
This includes a cash tax provision in the first nine months of 2004 of
$559 million, compared with a cash tax provision of $17 million in the same
2003 period. Daily sales in the first nine months averaged 758,000 BOE, up 21
percent from the first nine months of 2003. Daily sales were comprised of
2.96 billion cubic feet of gas and 265,000 barrels of oil and NGLs. In the
first nine months, EnCana drilled 3,998 net wells, about 70 percent of the
5,500 net wells planned for 2004. Core capital investment, excluding
acquisitions and divestitures, was $3,703 million for the first nine months of
2004.

Operating earnings in the first nine months were $1,403 million, up
32 percent
In the first nine months of 2004, EnCana achieved operating earnings of
$1,403 million, or $3.00 per share diluted, up 32 percent from the first nine
months of 2003. Net earnings in the first nine months were $933 million, or
$2.00 per share diluted, which includes three non-cash items: an after-tax
unrealized mark-to-market loss of $677 million, an after-tax unrealized gain
on foreign exchange on US$ denominated debt issued in Canada of $98 million,
and a $109 million gain due to tax rate changes. Nine month operating costs
were $3.39 per BOE compared to $3.41 per BOE in the same period of 2003, which
is in line with the full year 2004 operating cost forecast of between $3.30
and $3.50 per BOE. In the first nine months of 2004, revenues net of royalties
were $8,026 million.

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

-------------------------------------------------------------------------
Financial Highlights
(as at and for the period
ended September 30)
(US$ millions, except Q3 Q3 % 9 months 9 months %
per share amounts) 2004 2003 change 2004 2003 change
-------------------------------------------------------------------------

Revenues,
net of royalties 2,458 2,291 + 7 8,026 7,366 + 9

Operating EBITDA(1) 1,484 1,072 + 38 4,188 3,361 + 25

Cash flow 1,363 977 + 40 3,489 3,205 + 9
Per share - basic 2.95 2.06 + 43 7.57 6.71 + 13
Per share - diluted 2.92 2.04 + 43 7.47 6.63 + 13
Add back:
---------
Cash tax 124 51 + 143 559 17 +3,188

Pre-tax cash flow 1,487 1,028 + 45 4,048 3,222 + 26

Capital investment
Core capital 1,098 1,340 - 18 3,703 3,183 + 16
Net acquisitions and
divestitures(2) (891) 96 -1,028 1,165 443 + 163
Net capital investment
- continuing operations 207 1,436 - 86 4,868 3,626 + 34

Net earnings 393 290 + 36 933 1,934 - 52
Per share - basic 0.85 0.61 + 39 2.02 4.05 - 50
Per share - diluted 0.84 0.61 + 38 2.00 4.00 - 50

Net earnings from
continuing operations 393 286 + 37 933 1,741 - 46
Per share - basic 0.85 0.60 + 42 2.02 3.64 - 45
Per share - diluted 0.84 0.60 + 40 2.00 3.60 - 44
Add back:
---------
Unrealized mark-to-market
accounting loss, after-tax 321 - n/a 677 - n/a
Add back:
---------
Unrealized foreign
exchange (gain)
related to translation
of U.S. dollar debt,
after tax (155) (12) +1,192 (98) (320) - 69
Less:
-----
Future tax (recovery) due
to tax rate change - - n/a (109) (362) - 70

Operating earnings 559 274 + 104 1,403 1,059 + 32
Per share - basic 1.21 0.58 + 109 3.04 2.22 + 37
Per share - diluted 1.20 0.57 + 111 3.00 2.19 + 37
-------------------------------------------------------------------------

Common shares at
September 30 (millions)
Weighted average (basic) 461.7 473.4 - 2 461.0 478.0 - 4
Weighted average (diluted) 466.2 477.9 - 2 467.1 483.7 - 3
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Operating EBITDA is net earnings from continuing operations before
interest, income taxes, depreciation, depletion and amortization
(DD&A), accretion of asset retirement obligation, foreign exchange
loss (gain), gain on disposition and unrealized loss on risk
management ($1,028 million, year-to-date, before tax).

(2) Includes both property and corporate acquisitions and divestitures.


-------------------------------------------------------------------------
Operating Highlights
(for the period ended Q3 Q3 % 9 months 9 months %
September 30) 2004 2003 change 2004 2003 change
-------------------------------------------------------------------------
(After royalties)
Natural Gas (MMcf/d)
Production
(excluding Tom Brown) 2,853 2,525 + 13 2,824 2,490 + 13
Tom Brown production 275 - n/a 136 - n/a
Produced gas withdrawn
from storage - - - - 38 n/a
-------------------------------------------------------------------------
Total natural gas sales
(MMcf/d) 3,128 2,525 + 24 2,960 2,528 + 17
-------------------------------------------------------------------------
Oil and NGLs sales
(bbls/d)
North America 169,673 172,870 - 2 168,750 163,008 + 4
International 89,735 45,620 + 97 95,922 44,595 + 115
-------------------------------------------------------------------------
Total oil and NGLs
sales (bbls/d) 259,408 218,490 + 19 264,672 207,603 +27
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total sales (BOE/d) 780,741 639,323 + 22 758,005 628,936 +21
-------------------------------------------------------------------------
Per share sales growth + 26 + 26
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Risk management strategy
EnCana's market risk mitigation strategy is designed to deliver greater
predictability of cash flow and returns on investment. EnCana has hedged
approximately 40 percent, about 1.3 billion cubic feet per day, of its
projected fourth quarter 2004 natural gas sales at an average NYMEX equivalent
price of $5.47 per thousand cubic feet. In addition, about 200 million cubic
feet per day is subject to NYMEX collars at an average floor price of $4.43
per thousand cubic feet and an average ceiling price of $6.42 per thousand
cubic feet. 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. About half of EnCana's projected 2004 oil sales are
hedged with swaps or costless collars between $20 and $26 per barrel of WTI.
In addition, for the balance of 2004, EnCana has also purchased call options
with an average price of US$46.64, allowing EnCana to participate in oil price
upside above this level. Detailed risk management positions at September 30,
2004 are presented in Note 14 to the unaudited third quarter consolidated
financial statements. In the third quarter, EnCana's financial commodity and
currency risk management measures resulted in realized gross revenue being
lower by approximately $265 million, comprised of $221 million on oil sales
and $44 million on gas sales.

Hedging impact expected to wane in 2005
Due to the dramatic increase in world oil prices in 2004 and EnCana's use
of swaps and costless collars, the company experienced a substantial loss on
its 2004 hedging program. About one quarter of EnCana's 2005 forecast oil
sales is hedged with swaps or collars at approximately $29 per barrel. EnCana
has also purchased call options for 2005 at an average price of $49.76 per
barrel, allowing EnCana to participate in oil price upside above this level.
About 17 percent of EnCana's 2005 forecast gas sales is hedged with swaps and
collars at prices ranging from $4.90 to $6.70 per thousand cubic feet; on one
third of these swaps/collars, call options have been purchased at an average
price of $7.69, which will allow EnCana to participate in gas price upside
above this level. EnCana has also purchased NYMEX gas put options with a floor
price of $5.00 per thousand cubic feet covering a further 13 percent of
forecast natural gas sales for 2005. EnCana will continue to use a variety of
hedging instruments for its 2005 program including employing put options.
These provide downside protection but do not limit the opportunity for the
company to capture commodity price upside.

Resource plays continue to deliver strong growth
Across North America, EnCana's portfolio of long-life, low-decline
resource plays continues to deliver double-digit oil and gas production
growth. Daily third quarter production from EnCana's key North American
resource plays has increased about 31 percent since the same period in 2003.
This growth was generated primarily by increased gas production at four
resource plays: Mamm Creek in Colorado, Greater Sierra and Cutbank Ridge in
northeast B.C., and Southern Plains shallow gas on legacy Suffield and
Palliser Blocks in southern Alberta. Oil production increases are from Foster
Creek and Pelican Lake in northeast Alberta.


Growth from key North American resource plays
-------------------------------------------------------------------------
Resource Play Daily Production
-------------------------------------------------------------------------
2004 2003
-------------------------------------------------------------------------

Natural gas (MMcf/d) YTD Q3 Q2 Q1 Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Canada
Southern Plains
shallow gas 580 595 590 554 538 509 499 483
Greater Sierra 236 244 247 216 175 144 136 118
Cutbank Ridge 37 45 41 22 6 2 2 2
Coalbed methane 13 19 11 10 7 3 3 2
-------------------------------------------------------------------------
U.S.A.(3)
Jonah 384 373 387 394 389 376 356 375
Mamm Creek 205 220 203 191 175 126 112 86
North Texas 25 31 23 21 19 12 - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Oil (Mbbls/d)(Canada)
-------------------------------------------------------------------------
Foster Creek 29 29 30 28 26 22 20 19
Pelican Lake 17 22 15 15 15 16 17 15
-------------------------------------------------------------------------


-------------------------------------------------------
Resource Play Net Wells Drilled
-------------------------------------------------------
2004 2003
-------------------------------------------------------
Full
Natural gas (MMcf/d) YTD Q3 Q2 Q1 year
-------------------------------------------------------
Canada
Southern Plains
shallow gas 1,330 384 416 530 2,366
Greater Sierra 169 13 21 135 199
Cutbank Ridge 33 12 4 17 20
Coalbed methane 451 272 98 81 267
-------------------------------------------------------
U.S.A.(3)
Jonah 49 17 21 11 59
Mamm Creek 196 65 65 66 259
North Texas 28 10 10 8 5
-------------------------------------------------------
-------------------------------------------------------
Oil (Mbbls/d)(Canada)
-------------------------------------------------------
Foster Creek 4 - - 4 8
Pelican Lake 92 33 30 29 134
-------------------------------------------------------

(3) Excludes Tom Brown production.


EnCana's resource play production approaching 75 percent of North America
portfolio
Throughout 2004, EnCana has been transitioning its North American asset
portfolio to reduce the production contribution from mature conventional oil
and gas assets in favour of increasing production from long-life, low-cost
resource plays. This has been achieved three ways, first through the steady
and focused investment in the company's established resource plays, mainly at
Mamm Creek, Jonah, Greater Sierra, Cutbank Ridge and in Southern Plains
shallow gas. Second, the $2.7 billion acquisition of Tom Brown, which included
a portfolio of U.S. resource plays, and third, the divestment of mature,
Canadian conventional oil and gas assets have accelerated this transition. To
date in 2004, EnCana has divested of conventional assets which were producing
approximately 129 million cubic feet per day and 30,600 barrels of oil per
day, plus other non-core assets, generating proceeds of about $1.36 billion.
As a result of these transactions and the company's focused investment
strategy, EnCana's proportion of production from resource plays has increased
from about 60 percent in 2003 to close to 75 percent. Additional divestitures
of conventional assets in Western Canada are planned, and the vast majority of
new capital is expected to be allocated towards resource plays.


-------------------------------------------------------------------------
EnCana 2004 Divestitures to September 30
-------------------------------------------------------------------------
Production
-------------------
Price Oil & NGLs Gas
Asset Completed ($million) (bbls/d) (MMcf/d) BOE/d
-------------------------------------------------------------------------
Petrovera (net) February 287 17,500 15 20,000
Northeast B.C. April 84 - 12 2,000
New Mexico July 235 900 18 3,900
East/Central Alberta
oil September 380 11,800 30 16,800
Northeast Alberta gas August 226 - 43 7,250
Sauer Drilling Co. July 37 - - -
Other Various 109 400 11 2,250
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total Sold $1,358 30,600 129 52,200
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Future gas growth underpinned by 25 trillion cubic feet of natural gas
resources
In 2004, EnCana is on track to produce more than 1 trillion cubic feet of
natural gas. As of December 31, 2003 and including the Tom Brown reserves
acquired in May 2004, EnCana's proved gas reserves exceeded 9.4 trillion cubic
feet, yielding a reserve life index of approximately nine years. Beyond that,
EnCana has identified approximately 16 trillion cubic feet of Unbooked
Resource Potential, which EnCana defines as estimated quantities of
hydrocarbons on existing company lands that are expected to be converted to
proved reserves in the next five years.

"Our Unbooked Resource Potential is unique to EnCana because it is unique
to resource plays. This potential is not dependent upon exploration success,
as is the case with conventional plays. Rather this resource potential is on
lands we currently own and where the resources have been estimated based on
wells intended to be drilled over the next five years in geologically defined
areas. EnCana has a proven track record of converting resource potential into
proved reserves in a highly-efficient and cost effective manner. Our Unbooked
Resource Potential is the key driver behind our steady growth in proved
reserves and production. Together, the company's proved reserves and Unbooked
Resource Potential for natural gas totals 25 trillion cubic feet, which
represents close to 25 years - a quarter century - of clearly visible resource
life at current production rates. This is what underpins EnCana's visible
long-life, sustainable gas production growth," Morgan said.

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

Dividend $0.10 per share
EnCana's board of directors has declared a quarterly dividend of $0.10
per share payable on December 31, 2004 to common shareholders of record as of
December 15, 2004.

EnCana renews Normal Course Issuer Bid
EnCana has received approval for renewal of the company's Normal Course
Issuer Bid from Toronto Stock Exchange (TSX). Under the renewed bid, EnCana
may purchase for cancellation up to 23,114,500 of its common shares,
representing five percent of the approximately 462 million common shares
outstanding as at October 15, 2004. In the past 12 months under its previous
Normal Course Issuer Bid, EnCana purchased 9,105,000 common shares,
representing approximately two percent of the company's outstanding shares on
October 14, 2003, at an average price of C$51.56 per common share. Purchases
under the renewed bid may commence on October 29, 2004 and may be made until
October 28, 2005. Purchases will be made on the open market through the
facilities of the TSX in accordance with its policies, and may also be made
through the facilities of the New York Stock Exchange (NYSE) in accordance
with its rules. Approval of the bid is not required from the NYSE. The price
to be paid will be the market price at the time of acquisition. EnCana
believes that the purchase of its common shares will help create value for the
company's shareholders.

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

-----------------------------------------------------------------
Balance Sheet Highlights
(US$ millions, except percent September 30 December 31
and ratio amounts) 2004 2003
-----------------------------------------------------------------
Total assets 29,673 24,110
Long-term debt 8,036 6,088
Shareholders' equity 12,083 11,278
Net debt-to-capitalization ratio 43% 34%
Net Debt/Trailing EBITDA 2.1 times 1.3 times
-----------------------------------------------------------------

To fund the Tom Brown acquisition, EnCana arranged a $3.0 billion credit
facility, which was paid down to $846 million by the end of September. On July
29, EnCana made a public offering in the United States of US$250 million of
4.60% Notes due August 15, 2009 and US$750 million of 6.50% Notes due August
15, 2034. The net proceeds of the offering were used to repay a portion of
EnCana's existing bank and commercial paper indebtedness. These investment
grade debt securities are rated A- Outlook Negative by Standard & Poor's
Ratings Services, Baa2 by Moody's Investors Service and A(low) negative trend
by Dominion Bond Rating Service (DBRS).
In the third quarter of 2004, EnCana invested $1,098 million of core
capital, acquisitions totaled $49 million and divestitures were $940 million,
resulting in net capital investment of $207 million.

-------------------------------------------------------------------------
CONFERENCE CALL TODAY
EnCana Corporation will host a conference call today, Wednesday,
October 27, 2004 starting at 11 a.m., Mountain Time (1 p.m. Eastern
Time), to discuss EnCana's third quarter 2004 financial and operating
results. To participate, please dial (913) 981-4903 approximately
10 minutes prior to the conference call. An archived recording of the
call will be available from approximately 5 p.m. on October 27, 2004
until midnight November 2, 2004 by dialing (888) 203-1112 or
(719) 457-0820 and entering pass code 974614.
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.
-------------------------------------------------------------------------


Non-GAAP measures
This news release contains references to cash flow, pre-tax cash flow,
operating EBITDA (net earnings from continuing operations before interest,
income taxes, DD&A, accretion of asset retirement obligation, foreign exchange
loss (gain), gain on disposition and unrealized loss on risk management),
EBITDA and operating earnings, and the related basic and diluted per common
share amounts as applicable, which are not measures that have any standardized
meaning prescribed by Canadian GAAP and are considered non-GAAP measures.
Therefore, these measures may not be comparable to similar measures presented
by other issuers. These measures have been described and presented in this
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 $30 billion, EnCana is one of
the world's leading independent oil and gas companies and North America's
largest independent natural gas producer and gas storage operator. Ninety
percent of the company's assets are located in North America. EnCana is the
largest producer and landholder in Western Canada and is a key player in
Canada's emerging offshore East Coast basins. Through its U.S. subsidiaries,
EnCana is one of the largest gas explorers and producers in the Rocky Mountain
states and has a strong position in the deep water Gulf of Mexico.
International subsidiaries operate two key high potential international growth
regions: Ecuador, where it is the largest private sector oil producer, and the
U.K., where the portfolio includes the Buzzard oil field development. EnCana
and its subsidiaries also conduct high upside potential new ventures
exploration in other parts of the world. EnCana is driven to be the industry's
high performance benchmark in production cost, per-share growth and value
creation for shareholders. EnCana common shares trade on the Toronto and New
York stock exchanges under the symbol ECA.

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

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

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: production, sales, reserves, and growth estimates for
crude oil, natural gas and NGLs for 2004 and the next five years, including
estimates calculated on a per share basis; the company's ability to achieve
its 2004 sales guidance; the company's projections with respect to the
percentage of production from resource plays in the future and the impact of
increasing the company's proportion of resource play assets on future decline
rates and the reliability and predictability of resource and production
growth; the resource potential, unbooked resource potential, production and
growth potential, including the company's plans therefor, and capital costs
associated therewith with respect to EnCana's various assets and initiatives,
including assets and initiatives in North America, Ecuador, the U.K. central
North Sea, the Gulf of Mexico and potential international exploration;
estimates of resource life, including over the next 25 years; potential
dispositions of assets in 2004 and beyond, including anticipated proceeds
therefrom and the dates for receipt thereof; anticipated purchases pursuant to
the company's Normal Course Issuer Bid and the value of such bid to
shareholders; the company's projected capital investment levels for 2004, and
the source of funding therefor; anticipated returns on capital; projected
additional production from the Tom Brown, Inc. acquisition and the impact on
production levels of proposed asset dispositions; the effect of the company's
risk management program, including the impact of derivative financial
instruments; projected operating and administrative costs for 2004; projected
DD&A rates for 2004 and beyond; projected levels of, and volatility of, crude
oil and natural gas prices in 2004 and beyond and the potential causes
therefor, including the impact which weather, the timing of new production,
economic activity levels and political instability may have on commodity
prices in the near term; projected tax rates and projected current taxes
payable for 2004 and the impact of future unrealized foreign exchange gains
and losses thereon and the adequacy of the company's provision for taxes;
projections with respect to the number of wells drilled and well tie-ins made
in 2004; the impact of new oil and natural gas price hedging accounting
standards, including their impact on the volatility of future reported net
earnings; unbooked resource potential which may be recognized as proved
reserves in the future; projections with respect to anticipated future cash
flow levels; projections with respect to potential future drilling and service
cost escalations; the impact of the company's divestitures and potential
divestitures on operating costs, netbacks and decline rates 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; political and economic conditions in the countries in which the
company operates, including Ecuador; the risk of war, hostilities, civil
insurrection and instability affecting countries in which the company operates
and terrorist threats; risks associated with existing and potential future
lawsuits and regulatory actions made against the company; and other risks and
uncertainties described from time to time in the reports and filings made with
securities regulatory authorities by EnCana. Although EnCana believes that the
expectations represented by such forward-looking statements are reasonable,
there can be no assurance that such expectations will prove to be correct.
Readers are cautioned that the foregoing list of important factors is not
exhaustive.
Furthermore, the forward-looking statements contained in this news
release are made as of the date of this news release, and EnCana does not
undertake any obligation to update publicly or to revise any of the included
forward-looking statements, whether as a result of new information, future
events or otherwise. The forward-looking statements contained in this news
release are expressly qualified by this cautionary statement.

<<

Interim Consolidated Financial Statements
(unaudited)
For the period ended September 30, 2004


EnCana Corporation


U.S. DOLLARS


Interim Report PREPARED IN US$
For the period ended September 30, 2004

EnCana Corporation
CONSOLIDATED STATEMENT OF EARNINGS (unaudited)

September 30
---------------------------------------
Three Months Ended Nine Months Ended
(US$ millions, ---------------------------------------
except per share amounts) 2004 2003 2004 2003
-------------------------------------------------------------------------

REVENUES,
NET OF ROYALTIES (Note 5)
Upstream $ 2,070 $ 1,509 $ 5,853 $ 4,651
Midstream & Marketing 889 781 3,206 2,713
Corporate (501) 1 (1,033) 2
-------------------------------------------------------------------------
2,458 2,291 8,026 7,366

EXPENSES (Note 5)
Production and
mineral taxes 97 33 258 131
Transportation and
selling 144 125 468 375
Operating 382 322 1,081 960
Purchased product 800 692 2,909 2,406
Depreciation, depletion
and amortization 694 525 2,051 1,497
Administrative 43 41 136 121
Interest, net 103 71 278 202
Accretion of asset
retirement
obligation (Note 10) 8 5 20 15
Foreign exchange
(gain) (Note 7) (288) (20) (209) (436)
Stock-based
compensation 5 6 14 12
Gain on dispositions (Note 4) - - (35) -
-------------------------------------------------------------------------
1,988 1,800 6,971 5,283
-------------------------------------------------------------------------
NET EARNINGS BEFORE
INCOME TAX 470 491 1,055 2,083
Income tax expense (Note 8) 77 205 122 342
-------------------------------------------------------------------------
NET EARNINGS FROM
CONTINUING OPERATIONS 393 286 933 1,741
NET EARNINGS FROM
DISCONTINUED
OPERATIONS (Note 6) - 4 - 193
-------------------------------------------------------------------------
NET EARNINGS $ 393 $ 290 $ 933 $ 1,934
-------------------------------------------------------------------------
-------------------------------------------------------------------------

NET EARNINGS FROM
CONTINUING OPERATIONS
PER COMMON SHARE (Note 13)
Basic $ 0.85 $ 0.60 $ 2.02 $ 3.64
Diluted $ 0.84 $ 0.60 $ 2.00 $ 3.60
-------------------------------------------------------------------------
-------------------------------------------------------------------------

NET EARNINGS PER
COMMON SHARE (Note 13)
Basic $ 0.85 $ 0.61 $ 2.02 $ 4.05
Diluted $ 0.84 $ 0.61 $ 2.00 $ 4.00
-------------------------------------------------------------------------
-------------------------------------------------------------------------


CONSOLIDATED STATEMENT OF RETAINED EARNINGS
Nine Months Ended
September 30,
------------------
(US$ millions) 2004 2003
-------------------------------------------------------------------------

RETAINED EARNINGS, BEGINNING OF YEAR
As previously reported $ 5,276 $ 3,457
Retroactive adjustment for changes in
accounting policies - 66
-------------------------------------------------------------------------
As restated 5,276 3,523
Net Earnings 933 1,934
Dividends on Common Shares (137) (103)
Charges for Normal Course Issuer Bid (Note 11) (126) (360)
-------------------------------------------------------------------------
RETAINED EARNINGS, END OF PERIOD $ 5,946 $ 4,994
-------------------------------------------------------------------------
-------------------------------------------------------------------------

See accompanying Notes to Consolidated Financial Statements.



CONSOLIDATED BALANCE SHEET (unaudited)

As at As at
September December
(US$ millions) 30, 2004 31, 2003
-------------------------------------------------------------------------

ASSETS
Current Assets
Cash and cash equivalents $ 107 $ 148
Accounts receivable and accrued
revenues 2,066 1,367
Risk management (Note 14) 84 -
Inventories 700 573
-------------------------------------------------------------------------
2,957 2,088
Property, Plant and Equipment, net (Note 5) 23,623 19,545
Investments and Other Assets 637 566
Risk Management (Note 14) 46 -
Goodwill 2,410 1,911
-------------------------------------------------------------------------
(Note 5) $ 29,673 $ 24,110
-------------------------------------------------------------------------
-------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued
liabilities $ 2,059 $ 1,579
Risk management (Note 14) 800 -
Income tax payable 526 65
Current portion of long-term debt (Note 9) 550 287
-------------------------------------------------------------------------
3,935 1,931
Long-Term Debt (Note 9) 8,036 6,088
Other Liabilities 85 21
Risk Management (Note 14) 332 -
Asset Retirement Obligation (Note 10) 490 430
Future Income Taxes 4,712 4,362
-------------------------------------------------------------------------
17,590 12,832
-------------------------------------------------------------------------
Shareholders' Equity
Share capital (Note 11) 5,412 5,305
Share options, net 21 55
Paid in surplus 53 18
Retained earnings 5,946 5,276
Foreign currency translation adjustment 651 624
-------------------------------------------------------------------------
12,083 11,278
-------------------------------------------------------------------------
$ 29,673 $ 24,110
-------------------------------------------------------------------------
-------------------------------------------------------------------------

See accompanying Notes to Consolidated Financial Statements.



CONSOLIDATED STATEMENT OF CASH FLOWS (unaudited)

September 30
---------------------------------------
Three Months Ended Nine Months Ended
---------------------------------------
(US$ millions) 2004 2003 2004 2003
-------------------------------------------------------------------------

OPERATING ACTIVITIES
Net earnings from
continuing operations $ 393 $ 286 $ 933 $ 1,741
Depreciation, depletion
and amortization 694 525 2,051 1,497
Future income taxes (Note 8) (47) 154 (437) 325
Unrealized loss on
risk management (Note 14) 497 - 1,028 -
Unrealized foreign
exchange (gain) (Note 7) (193) (15) (122) (404)
Accretion of asset
retirement
obligation (Note 10) 8 5 20 15
Gain on dispositions (Note 4) - - (35) -
Other 11 18 51 29
-------------------------------------------------------------------------
Cash flow from
continuing operations 1,363 973 3,489 3,203
Cash flow from
discontinued operations - 4 - 2
-------------------------------------------------------------------------
Cash flow 1,363 977 3,489 3,205
Net change in other
assets and liabilities (25) (111) (71) (82)
Net change in non-cash
working capital from
continuing operations (276) 159 (103) 200
Net change in non-cash
working capital from
discontinued operations - (3) - 54
-------------------------------------------------------------------------
1,062 1,022 3,315 3,377
-------------------------------------------------------------------------

INVESTING ACTIVITIES
Business combination
with Tom Brown, Inc. (Note 3) - - (2,335) -
Capital expenditures (Note 5) (1,147) (1,345) (3,892) (3,438)
Proceeds on disposal
of assets 941 - 1,072 19
Dispositions
(acquisitions) (Note 4) (1) (91) 287 (207)
Equity investments (Note 4) 8 (25) 52 (158)
Net change in
investments and other (46) (41) (68) (68)
Net change in non-cash
working capital from
continuing operations (24) 46 (70) (112)
Discontinued operations - 307 - 1,585
-------------------------------------------------------------------------
(269) (1,149) (4,954) (2,379)
-------------------------------------------------------------------------

FINANCING ACTIVITIES
Net (repayment)
issuance of revolving
long-term debt (662) 722 (215) 262
Issuance of long-term
debt 1,000 - 3,761 -
Repayment of
long-term debt (1,205) (71) (1,754) (142)
Issuance of common
shares (Note 11) 30 12 184 95
Purchase of common
shares (Note 11) - (560) (230) (682)
Dividends on common
shares (45) (35) (137) (103)
Other (6) 8 (11) (5)
Discontinued operations - - - (282)
-------------------------------------------------------------------------
(888) 76 1,598 (857)
-------------------------------------------------------------------------

DEDUCT: FOREIGN EXCHANGE
LOSS ON CASH AND CASH
EQUIVALENTS HELD IN
FOREIGN CURRENCY - 1 - 9
-------------------------------------------------------------------------

(DECREASE) INCREASE IN
CASH AND CASH EQUIVALENTS (95) (52) (41) 132
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD 202 300 148 116
-------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS,
END OF PERIOD $ 107 $ 248 $ 107 $ 248
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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, natural gas liquids and crude
oil, as well as natural gas storage operations, natural gas liquids
processing and power generation operations.

The interim Consolidated Financial Statements have been prepared
following the same accounting policies and methods of computation as the
annual audited Consolidated Financial Statements for the year ended
December 31, 2003, except as noted below. The disclosures provided below
are incremental to those included with the annual audited Consolidated
Financial Statements. The interim Consolidated Financial Statements
should be read in conjunction with the annual audited Consolidated
Financial Statements and the notes thereto for the year ended
December 31, 2003.

2. CHANGE IN ACCOUNTING POLICIES AND PRACTICES

Hedging Relationships

On January 1, 2004, the Company adopted the amendments made to Accounting
Guideline 13 ("AcG - 13") "Hedging Relationships", and EIC 128,
"Accounting for Trading, Speculative or Non Trading Derivative Financial
Instruments". Derivative instruments that do not qualify as a hedge under
AcG - 13, or are not designated as a hedge, are recorded in the
Consolidated Balance Sheet as either an asset or liability with changes
in fair value recognized in net earnings. The Company has elected not to
designate any of its price risk management activities in place at
September 30, 2004 as accounting hedges under AcG - 13 and, accordingly,
will account for all these non-hedging derivatives using the
mark-to-market accounting method. The impact on the Company's
Consolidated Financial Statements at January 1, 2004 resulted in the
recognition of risk management assets with a fair value of $145 million,
risk management liabilities with a fair value of $380 million and a net
deferred loss of $235 million which will be recognized into net earnings
as the contracts expire. At September 30, 2004, it is estimated that over
the following 12 months, $42 million ($30 million, net of tax) will be
reclassified into net earnings from net deferred losses.

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

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

2004
Quarter 4 $ (64)
-------------------------------------------------------------------------
Total remaining to be recognized in 2004 $ (64)
-------------------------------------------------------------------------

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

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

-------------------------------------------------------------------------
Total to be recognized $ 7
-------------------------------------------------------------------------
-------------------------------------------------------------------------

At September 30, 2004, the remaining net deferred loss totalled
$7 million of which $72 million was recorded in Accounts receivable and
accrued revenues, $3 million in Investments and other assets, $30 million
in Accounts payable and accrued liabilities and $52 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.

The business combination has been accounted for using the purchase method
with 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 preliminary allocation to
assets and liabilities is shown below. The purchase price and goodwill
allocation is preliminary because certain items such as determination of
the final tax bases and fair values of the assets and liabilities as of
the acquisition date have not been completed.

-------------------------------------------------------------------------
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 276
Long-term debt 406
Other non-current liabilities 39
Future income taxes 710
-------------------------------------------------------------------------
Total Purchase Price and Liabilities Assumed $ 3,785
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Fair Value of Assets Acquired
Current assets (including cash acquired of $19 million) $ 440
Property, plant, and equipment 2,879
Other non-current assets 9
Goodwill 457
-------------------------------------------------------------------------
Total Fair Value of Assets Acquired $ 3,785
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Included in current assets as Assets held for sale is $278 million
related to the value of certain oil and gas properties located in west
Texas and southwestern New Mexico and the assets of Sauer Drilling
Company, a subsidiary of Tom Brown, Inc., which the Company has entered
into purchase and sale agreements. These sales were completed on
July 30, 2004.

4. DISPOSITIONS (ACQUISITIONS)

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

On February 18, 2004, the Company sold its 53.3 percent interest in
Petrovera Resources ("Petrovera") for approximately $287 million,
including working capital adjustments. In order to facilitate the
transaction, EnCana purchased the 46.7 percent interest of its partner
for approximately $253 million, including working capital adjustments,
and then sold the 100 percent interest in Petrovera for a total of
approximately $540 million, including working capital adjustments. There
was no gain or loss recorded on this sale.

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

Other dispositions of discontinued operations are disclosed in Note 6.

5. SEGMENTED INFORMATION

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

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

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

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

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

Operations that have been discontinued are disclosed in Note 6.

Results of Operations (For the three months ended September 30)

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

Revenues, Net of Royalties $ 2,070 $ 1,509 $ 889 $ 781

Expenses
Production and mineral taxes 97 33 - -
Transportation and selling 140 114 4 11
Operating 304 258 77 64
Purchased product - - 800 692
Depreciation, depletion
and amortization 672 502 8 9
-------------------------------------------------------------------------
Segment Income $ 857 $ 602 $ - $ 5
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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

Revenues, Net of Royalties(*) $ (501) $ 1 $ 2,458 $ 2,291

Expenses
Production and mineral taxes - - 97 33
Transportation and selling - - 144 125
Operating 1 - 382 322
Purchased product - - 800 692
Depreciation, depletion
and amortization 14 14 694 525
-------------------------------------------------------------------------
Segment Income $ (516) $ (13) 341 594
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Administrative 43 41
Interest, net 103 71
Accretion of asset retirement
obligation 8 5
Foreign exchange (gain) (288) (20)
Stock-based compensation 5 6
Gain on dispositions - -
-------------------------------------------------------------------------
(129) 103
-------------------------------------------------------------------------
Net Earnings Before Income Tax 470 491
Income tax expense 77 205
-------------------------------------------------------------------------
Net Earnings from Continuing Operations $ 393 $ 286
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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



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

Revenues,
Net of Royalties $1,283 $1,072 $ 512 $ 281 $ 159 $ 81
Expenses
Production and
mineral taxes 23 4 56 28 18 1
Transportation and
selling 91 80 23 22 16 9
Operating 170 170 32 18 30 16
Depreciation, depletion
and amortization 445 377 131 78 63 33
-------------------------------------------------------------------------
Segment Income $ 554 $ 441 $ 270 $ 135 $ 32 $ 22
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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

Revenues,
Net of Royalties $ 50 $ 17 $ 66 $ 58 $2,070 $1,509
Expenses
Production and mineral
taxes - - - - 97 33
Transportation
and selling 10 3 - - 140 114
Operating 12 3 60 51 304 258
Depreciation, depletion
and amortization 26 12 7 2 672 502
-------------------------------------------------------------------------
Segment Income $ 2 $ (1) $ (1) $ 5 $ 857 $ 602
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Total Midstream
Midstream & Marketing Midstream Marketing & Marketing
-----------------------------------------------
2004 2003 2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues $ 158 $ 180 $ 731 $ 601 $ 889 $ 781
Expenses
Transportation and
selling - - 4 11 4 11
Operating 65 57 12 7 77 64
Purchased product 88 112 712 580 800 692
Depreciation, depletion
and amortization 8 7 - 2 8 9
-------------------------------------------------------------------------
Segment Income $ (3) $ 4 $ 3 $ 1 $ - $ 5
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Upstream Geographic and Product Information
(For the three months ended September 30)


Produced Gas Produced Gas
-------------------------------------------------------------
Canada United States U.K. North Sea Total
-------------------------------------------------------------------------
2004 2003 2004 2003 2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues,
Net of
Royalties $ 970 $ 806 $ 462 $ 259 $ 10 $ 2 $1,442 $1,067
Expenses
Production
and
mineral
taxes 18 15 51 25 - - 69 40
Transport-
ation and
selling 72 71 23 22 7 1 102 94
Operating 99 89 32 18 - - 131 107
-------------------------------------------------------------------------
Operating
Cash Flow $ 781 $ 631 $ 356 $ 194 $ 3 $ 1 $1,140 $ 826
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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

Revenues,
Net of Royalties $ 313 $ 266 $ 50 $ 22 $ 159 $ 81
Expenses
Production and
mineral taxes 5 (11) 5 3 18 1
Transportation and
selling 19 9 - - 16 9
Operating 71 81 - - 30 16
-------------------------------------------------------------------------
Operating Cash Flow $ 218 $ 187 $ 45 $ 19 $ 95 $ 55
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Oil & NGLs
-------------------------------
U.K. North Sea Total
-------------------------------------------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 40 $ 15 $ 562 $ 384
Expenses
Production and mineral taxes - - 28 (7)
Transportation and selling 3 2 38 20
Operating 12 3 113 100
-------------------------------------------------------------------------
Operating Cash Flow $ 25 $ 10 $ 383 $ 271
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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

Revenues, Net of Royalties $ 66 $ 58 $2,070 $1,509
Expenses
Production and mineral taxes - - 97 33
Transportation and selling - - 140 114
Operating 60 51 304 258
-------------------------------------------------------------------------
Operating Cash Flow $ 6 $ 7 $1,529 $1,104
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Results of Operations (For the nine months ended September 30)

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

Revenues, Net of Royalties $5,853 $4,651 $3,206 $2,713

Expenses
Production and mineral taxes 258 131 - -
Transportation and selling 448 331 20 44
Operating 861 719 224 241
Purchased product - - 2,909 2,406
Depreciation, depletion and
amortization 1,947 1,444 60 21
-------------------------------------------------------------------------
Segment Income $2,339 $2,026 $ (7) $ 1
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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

Revenues, Net of Royalties(*) $(1,033) $ 2 $8,026 $7,366

Expenses
Production and mineral taxes - - 258 131
Transportation and selling - - 468 375
Operating (4) - 1,081 960
Purchased product - - 2,909 2,406
Depreciation, depletion and
amortization 44 32 2,051 1,497
-------------------------------------------------------------------------
Segment Income $(1,073) $ (30) 1,259 1,997
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Administrative 136 121
Interest, net 278 202
Accretion of asset retirement
obligation 20 15
Foreign exchange (gain) (209) (436)
Stock-based compensation 14 12
Gain on dispositions (35) -
-------------------------------------------------------------------------
204 (86)
-------------------------------------------------------------------------
Net Earnings Before Income Tax 1,055 2,083
Income tax expense 122 342
-------------------------------------------------------------------------
Net Earnings from Continuing Operations $ 933 $1,741
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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


Results of Operations (For the nine months ended September 30)


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

Revenues,
Net of Royalties $3,770 $3,343 $1,313 $ 845 $ 432 $ 243
Expenses
Production and
mineral taxes 61 33 155 81 42 17
Transportation and
selling 277 241 93 56 49 24
Operating 505 482 80 43 89 50
Depreciation, depletion
and amortization 1,296 1,089 330 211 197 87
-------------------------------------------------------------------------
Segment Income $1,631 $1,498 $ 655 $ 454 $ 55 $ 65
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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.

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

Revenues,
Net of Royalties $ 168 $ 73 $ 170 $ 147 $5,853 $4,651
Expenses
Production and mineral
taxes - - - - 258 131
Transportation and
selling 29 10 - - 448 331
Operating 32 10 155 134 861 719
Depreciation, depletion
and amortization 93 53 31 4 1,947 1,444
-------------------------------------------------------------------------
Segment Income $ 14 $ - $ (16) $ 9 $2,339 $2,026
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Total Midstream
Midstream & Marketing Midstream Marketing & Marketing
-----------------------------------------------
2004 2003 2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues $ 881 $ 649 $2,325 $2,064 $3,206 $2,713
Expenses
Transportation and
selling - - 20 44 20 44
Operating 192 188 32 53 224 241
Purchased product 655 423 2,254 1,983 2,909 2,406
Depreciation, depletion
and amortization 58 18 2 3 60 21
-------------------------------------------------------------------------
Segment Income $ (24) $ 20 $ 17 $ (19) $ (7) $ 1
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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
(For the nine months ended September 30)

Produced Gas Produced Gas
-------------------------------------------------------------
Canada United States U.K. North Sea Total
-------------------------------------------------------------------------
2004 2003 2004 2003 2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues,
Net of
Royalties $2,887 $2,534 $1,198 $ 776 $ 36 $ 8 $4,121 $3,318
Expenses
Production
and
mineral
taxes 46 33 142 77 - - 188 110
Transport-
ation
and
selling 222 193 93 56 19 6 334 255
Operating 297 258 80 43 - - 377 301
-------------------------------------------------------------------------
Operating
Cash
Flow $2,322 $2,050 $ 883 $ 600 $ 17 $ 2 $3,222 $2,652
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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 Ecuador
-------------------------------------------------------------------------
2004 2003 2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues,
Net of Royalties $ 883 $ 809 $ 115 $ 69 $ 432 $ 243
Expenses
Production and mineral
taxes 15 - 13 4 42 17
Transportation and
selling 55 48 - - 49 24
Operating 208 224 - - 89 50
-------------------------------------------------------------------------
Operating Cash Flow $ 605 $ 537 $ 102 $ 65 $ 252 $ 152
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Oil & NGLs
-------------------------------
U.K. North Sea Total
-------------------------------------------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 132 $ 65 $1,562 $1,186
Expenses
Production and mineral taxes - - 70 21
Transportation and selling 10 4 114 76
Operating 32 10 329 284
-------------------------------------------------------------------------
Operating Cash Flow $ 90 $ 51 $1,049 $ 805
-------------------------------------------------------------------------
-------------------------------------------------------------------------



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

Revenues, Net of Royalties $ 170 $ 147 $5,853 $4,651
Expenses
Production and mineral taxes - - 258 131
Transportation and selling - - 448 331
Operating 155 134 861 719
-------------------------------------------------------------------------
Operating Cash Flow $ 15 $ 13 $4,286 $3,470
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Capital Expenditures
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Upstream
Canada $ 634 $ 901 $ 2,337 $ 2,287
United States 328 280 854 626
Ecuador 53 65 163 172
United Kingdom 92 19 421 45
Other Countries 15 15 49 63
-------------------------------------------------------------------------
1,122 1,280 3,824 3,193
Midstream & Marketing 15 58 40 207
Corporate 10 7 28 38
-------------------------------------------------------------------------
Total $ 1,147 $ 1,345 $ 3,892 $ 3,438
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Property, Plant and Equipment and Total Assets

Property, Plant
and Equipment Total Assets
----------------------------------------
As at As at
----------------------------------------
September December September December
30, 2004 31, 2003 30, 2004 31, 2003
-------------------------------------------------------------------------

Upstream $ 22,590 $ 18,532 $ 27,030 $ 21,742
Midstream & Marketing 808 784 1,977 1,879
Corporate 225 229 666 489
-------------------------------------------------------------------------
Total $ 23,623 $ 19,545 $ 29,673 $ 24,110
-------------------------------------------------------------------------
-------------------------------------------------------------------------

6. DISCONTINUED OPERATIONS

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

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

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

Consolidated Statement of Earnings
For the three months ended
September 30, 2003
------------------------------
Midstream-
Syncrude Pipelines Total
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 8 $ - $ 8
-------------------------------------------------------------------------

Expenses
Transportation and selling - - -
Operating 4 - 4
Depreciation, depletion and amortization 1 - 1
Gain on discontinuance - - -
-------------------------------------------------------------------------
5 - 5
-------------------------------------------------------------------------
Net Earnings Before Income Tax 3 - 3
Income tax expense (1) - (1)
-------------------------------------------------------------------------
Net Earnings from Discontinued Operations $ 4 $ - $ 4
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Consolidated Statement of Earnings
For the nine months ended
September 30, 2003
------------------------------
Midstream-
Syncrude Pipelines Total
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 87 $ - $ 87
-------------------------------------------------------------------------

Expenses
Transportation and selling 2 - 2
Operating 46 - 46
Depreciation, depletion and amortization 7 - 7
Gain on discontinuance - (220) (220)
-------------------------------------------------------------------------
55 (220) (165)
-------------------------------------------------------------------------
Net Earnings Before Income Tax 32 220 252
Income tax expense 8 51 59
-------------------------------------------------------------------------
Net Earnings from Discontinued Operations $ 24 $ 169 $ 193
-------------------------------------------------------------------------
-------------------------------------------------------------------------

7. FOREIGN EXCHANGE (GAIN)
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Unrealized Foreign Exchange (Gain)
on Translation of U.S. Dollar
Debt Issued in Canada $ (193) $ (15) $ (122) $ (404)
Realized Foreign Exchange (Gain) (95) (5) (87) (32)
-------------------------------------------------------------------------
$ (288) $ (20) $ (209) $ (436)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

8. INCOME TAXES

The provision for income taxes is as follows:

Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Current
Canada $ 76 $ 31 $ 441 $ (18)
United States 3 10 18 10
Ecuador 44 8 98 21
United Kingdom - 1 - 3
Other 1 1 2 1
-------------------------------------------------------------------------
Total Current Tax 124 51 559 17

Future (47) 154 (328) 687
Future Tax Rate Reductions(*) - - (109) (362)
-------------------------------------------------------------------------
Total Future Tax (47) 154 (437) 325
-------------------------------------------------------------------------
$ 77 $ 205 $ 122 $ 342
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(*) 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 Nine Months Ended
September 30, September 30,
----------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Net Earnings Before Income Tax $ 470 $ 491 $ 1,055 $ 2,083
Canadian Statutory Rate 39.1% 41.0% 39.1% 41.0%
-------------------------------------------------------------------------
Expected Income Taxes 184 201 413 853

Effect on Taxes Resulting from:
Non-deductible Canadian crown
payments 51 44 154 176
Canadian resource allowance (57) (56) (173) (206)
Canadian resource allowance
on unrealized risk management
losses 13 - 40 -
Statutory and other rate
differences (19) 1 (49) (23)
Effect of tax rate changes - - (109) (362)
Non-taxable capital gains (55) (1) (41) (71)
Previously unrecognized
capital losses (5) (71) 10 (71)
Tax basis retained on
dispositions (59) - (162) -
Large corporations tax 6 8 13 25
Other 18 79 26 21
-------------------------------------------------------------------------
$ 77 $ 205 $ 122 $ 342
-------------------------------------------------------------------------
Effective Tax Rate 16.4% 41.8% 11.6% 16.4%
-------------------------------------------------------------------------
-------------------------------------------------------------------------

9. LONG-TERM DEBT
As at As at
September 30, December 31,
2004 2003
-------------------------------------------------------------------------

Canadian Dollar Denominated Debt
Revolving credit and term loan borrowings $ 1,509 $ 1,425
Unsecured notes and debentures 1,325 1,335
Preferred securities - 252
-------------------------------------------------------------------------
2,834 3,012
-------------------------------------------------------------------------

U.S. Dollar Denominated Debt
Revolving credit and term loan borrowings 965 417
Unsecured notes and debentures 4,716 2,713
Preferred securities - 150
-------------------------------------------------------------------------
5,681 3,280
-------------------------------------------------------------------------

Increase in Value of Debt Acquired(*) 71 83
Current Portion of Long-Term Debt (550) (287)
-------------------------------------------------------------------------
$ 8,036 $ 6,088
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(*) 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. The facility size has been reduced to an outstanding amount of
$846 million as at September 30, 2004. The remaining facility amount is
to be reduced to $450 million by August 20, 2005 and to zero on May 20,
2006.

During the quarter, the Company completed an issue of notes under its
shelf prospectus. The US$250 million notes are due in 2009 and bear
interest at 4.60%. The US$750 million notes are due in 2034 and bear
interest at 6.50%. The proceeds from the note issue were used to repay
bank and commercial paper indebtedness. In addition, the Company also
redeemed, at par value, the C$200 million 8.50% Preferred Securities and
the US$150 million 9.50% Preferred Securities.

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
September 30, December 31,
2004 2003
-------------------------------------------------------------------------

Asset Retirement Obligation, Beginning of Year $ 430 $ 309
Liabilities Incurred 64 64
Liabilities Settled (9) (23)
Liabilities Disposed (35) -
Accretion Expense 20 19
Other 20 61
-------------------------------------------------------------------------
Asset Retirement Obligation, End of Period $ 490 $ 430
-------------------------------------------------------------------------
-------------------------------------------------------------------------

11. SHARE CAPITAL
September 30, 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 6.9 184 5.5 114
Shares Repurchased (5.5) (77) (23.8) (320)
-------------------------------------------------------------------------
Common Shares Outstanding,
End of Period 462.0 $ 5,412 460.6 $ 5,305
-------------------------------------------------------------------------
-------------------------------------------------------------------------

To September 30, 2004, the Company purchased, for cancellation, 5,490,000
Common Shares for total consideration of approximately C$304 million
($230 million). Of the amount paid, C$101 million ($77 million) was
charged to Share capital, C$36 million ($27 million) was charged to Paid
in surplus and C$167 million ($126 million) was charged to Retained
earnings.

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

The following tables summarize the information about options to purchase
Common Shares at September 30, 2004:
Weighted
Average
Stock Exercise
Options Price
(millions) (C$)
-------------------------------------------------------------------------

Outstanding, Beginning of Year 28.8 43.13
Exercised (6.9) 35.46
Forfeited (0.6) 47.30
-------------------------------------------------------------------------
Outstanding, End of Period 21.3 45.42
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Exercisable, End of Period 13.4 43.90
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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

13.50 to 19.99 0.4 0.6 18.62 0.4 18.62
20.00 to 24.99 0.8 1.1 22.53 0.8 22.53
25.00 to 29.99 0.7 1.2 26.23 0.7 26.23
30.00 to 43.99 0.7 1.7 39.87 0.6 39.41
44.00 to 53.00 18.7 3.1 47.96 10.9 47.87
-------------------------------------------------------------------------
21.3 2.4 45.42 13.4 43.90
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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 September 30, 2004 would have been $384 million; $0.83
per common share - basic; $0.82 per common share - diluted (2003 -
$281 million; $0.59 per common share - basic; $0.59 per common share -
diluted). Pro forma Net Earnings and Net Earnings per Common Share for
the nine months ended September 30, 2004 would have been $906 million;
$1.97 per common share - basic; $1.94 per common share - diluted (2003 -
$1,908 million; $3.99 per common share - basic; $3.94 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:
September 30,
2003
-------------------------------------------------------------------------

Weighted Average Fair Value of Options Granted (C$) $ 12.21
Risk Free Interest Rate 3.89%
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 September 30, 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 Nine Months Ended
September 30, September 30,
----------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Current Service Cost $ 1 $ 2 $ 4 $ 5
Interest Cost 3 3 9 9
Expected Return on Plan Assets (2) (2) (8) (7)
Amortization of Net Actuarial Loss 1 1 3 3
Amortization of Transitional
Obligation - (1) (1) (2)
Amortization of Past Service Cost - - 1 1
Expense for Defined Contribution
Plan 3 3 10 9
-------------------------------------------------------------------------
Net Benefit Plan Expense $ 6 $ 6 $ 18 $ 18
-------------------------------------------------------------------------
-------------------------------------------------------------------------

At September 30, 2004, $17 million has been contributed to the pension
plans and the Company expects to make no additional contributions during
the remainder of 2004.

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

The following table summarizes the information about SAR's at
September 30, 2004:

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

Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 1,175,070 35.87
Exercised (497,785) 35.15
Forfeited (11,040) 29.25
-------------------------------------------------------------------------
Outstanding, End of Period 666,245 36.52
-------------------------------------------------------------------------
Exercisable, End of Period 666,245 36.52
-------------------------------------------------------------------------

U.S. Dollar Denominated (US$)
Outstanding, Beginning of Year 753,417 28.98
Exercised (279,258) 29.27
Forfeited (1,472) 24.08
-------------------------------------------------------------------------
Outstanding, End of Period 472,687 28.82
-------------------------------------------------------------------------
Exercisable, End of Period 472,687 28.82
-------------------------------------------------------------------------
-------------------------------------------------------------------------

The following table summarizes the information about Tandem SAR's at
September 30, 2004:
Weighted
Outstanding Average
Tandem Exercise
SAR's Price (C$)
-------------------------------------------------------------------------

Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year - -
Granted 976,650 54.58
Forfeited (77,500) 54.24
-------------------------------------------------------------------------
Outstanding, End of Period 899,150 54.61
-------------------------------------------------------------------------
Exercisable, End of Period - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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

The following table summarizes the information about DSU's at
September 30, 2004:
Weighted
Average
Outstanding Exercise
DSU's Price (C$)
-------------------------------------------------------------------------

Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 319,250 48.68
Granted, Directors 58,145 53.69
Granted, Senior Executives 1,686 57.54
-------------------------------------------------------------------------
Outstanding, End of Period 379,081 49.49
-------------------------------------------------------------------------
Exercisable, End of Period 297,874 51.82
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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

The following table summarizes the information about PSU's at
September 30, 2004:
Weighted
Average
Outstanding Exercise
PSU's Price ($)
-------------------------------------------------------------------------

Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 126,283 46.52
Granted 1,687,571 53.97
Forfeited (70,540) 53.17
-------------------------------------------------------------------------
Outstanding, End of Period 1,743,314 53.46
-------------------------------------------------------------------------
Exercisable, End of Period - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------

U.S. Dollar Denominated (US$)
Outstanding, Beginning of Year - -
Granted 249,830 41.12
Forfeited (19,547) 41.12
-------------------------------------------------------------------------
Outstanding, End of Period 230,283 41.12
-------------------------------------------------------------------------
Exercisable, End of Period - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------

13. PER SHARE AMOUNTS

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

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

Weighted Average
Common Shares
Outstanding
- Basic 460.9 460.3 461.7 473.4 461.0 478.0
Effect of Dilutive
Securities 6.2 5.2 4.5 4.5 6.1 5.7
-------------------------------------------------------------------------
Weighted Average
Common Shares
Outstanding
- Diluted 467.1 465.5 466.2 477.9 467.1 483.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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. 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 on the Consolidated Balance Sheet with an offsetting
net deferred loss amount. The deferred loss is recognized into net
earnings over the life of the related contracts. Changes in fair value
after that time are recorded on the Consolidated Balance Sheet with the
associated unrealized gain or loss recorded in net earnings. The
estimated fair value of all derivative instruments is based on quoted
market prices or, in their absence, third party market indications and
forecasts.

The following table presents a reconciliation of the change in the
unrealized amounts from January 1, 2004 to September 30, 2004:

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

Fair Value of
Contracts,
January 1, 2004 (Note 2) $ - $ 235 $ (235) $ -
Fair Value of
Contracts Acquired
with Tom Brown, Inc.,
Net of Amortization 5 - (5) -
Change in Fair Value
of Contracts Still
Outstanding at
September 30, 2004 - - (328) (328)
Fair Value of
Contracts Realized
During the Period - (242) 242 -
Fair Value of
Contracts Entered
into During the
Period - - (700) (700)
-------------------------------------------------------------------------
Fair Value of
Contracts Outstanding $ 5 $ (7) $ (1,026) $ (1,028)
-------------------------------------------------------------------------
Premiums Paid on
Collars and Options 24
-------------------------------------------------------------------------
Fair Value of Contracts
Outstanding and
Premiums Paid, End
of Period $ (1,002)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

The total realized loss recognized in net earnings for the quarter and
year-to-date ended September 30, 2004 was $256 million ($173 million, net
of tax) and $664 million ($449 million, net of tax), respectively.

At September 30, 2004, the net deferred amounts recognized on transition
and the risk management amounts are recorded on the Consolidated Balance
Sheet as follows:
As at
September 30,
2004
-------------------------------------------------------------------------

Deferred Amounts Recognized on Transition
Accounts receivable and accrued revenues $ 72
Investments and other assets 3

Accounts payable and accrued liabilities 30
Other liabilities 52
-------------------------------------------------------------------------
Total Net Deferred Loss $ (7)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Risk Management
Current asset $ 84
Long-term asset 46

Current liability 800
Long-term liability 332
-------------------------------------------------------------------------
Total Net Risk Management Liability $ (1,002)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

A summary of all unrealized estimated fair value financial positions is
as follows:
As at
September 30,
2004
-------------------------------------------------------------------------

Commodity Price Risk
Natural gas $ (500)
Crude oil (537)
Power 6
Foreign Currency Risk -
Interest Rate Risk 29
-------------------------------------------------------------------------
$ (1,002)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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 September 30,
2004.

Natural Gas

At September 30, 2004, the Company's gas risk management activities for
financial contracts had an unrealized loss of $(495) million and a fair
market value position of $(500) million. The contracts were as follows:

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

Sales Contracts
Fixed Price Contracts
Fixed AECO price 454 2004 6.19 C$/Mcf $ (34)
NYMEX Fixed price 702 2004 5.15 US$/Mcf (96)
Colorado Interstate
Gas (CIG) 52 2004 5.55 US$/Mcf (1)
Other(1) 162 2004 5.57 US$/Mcf (10)

NYMEX Fixed Price 180 2005 5.66 US$/Mcf (79)
Colorado Interstate
Gas (CIG) 113 2005 4.87 US$/Mcf (51)
Other(1) 110 2005 5.21 US$/Mcf (50)

NYMEX Fixed Price 525 2006 5.66 US$/Mcf (99)
Colorado Interstate
Gas (CIG) 100 2006 4.44 US$/Mcf (35)
Other(1) 171 2006 4.85 US$/Mcf (60)

Collars and Other
Options
AECO Collars 73 2004 5.36-7.54 C$/Mcf (3)
NYMEX Collars 24 2004 4.45-5.95 US$/Mcf (1)
Purchased NYMEX
Put Options 33 2004 5.00 US$/Mcf -
Other(2) 57 2004 4.31-6.53 US$/Mcf (1)

Purchased NYMEX
Put Options 474 2005 5.00 US$/Mcf (17)
Other(2) 5 2005 4.56-7.23 US$/Mcf (2)

NYMEX 3-Way Call
Spread 180 2005 5.00/6.69/7.69 US$/Mcf (28)

Basis Contracts
Fixed NYMEX to
AECO Basis 325 2004 (0.54) US$/Mcf 9
Fixed NYMEX to
Rockies Basis 303 2004 (0.50) US$/Mcf 12
Other(3) 240 2004 (0.39) US$/Mcf 3

Fixed NYMEX to
AECO Basis 877 2005 (0.66) US$/Mcf 38
Fixed NYMEX to
Rockies Basis 268 2005 (0.49) US$/Mcf 21
Other(3) 442 2005 (0.47) US$/Mcf 2

Fixed NYMEX to
AECO Basis 464 2006-2008 (0.65) US$/Mcf 22
Fixed NYMEX to
Rockies Basis 249 2006-2008 (0.57) US$/Mcf 6
Fixed NYMEX to
CIG Basis 150 2006-2008 (0.76) US$/Mcf (10)
Fixed Rockies to
CIG Basis 31 2006-2008 (0.10) US$/Mcf -
Other(3) 132 2006 (0.45) US$/Mcf (1)

Purchase Contracts
Fixed Price Contracts
Waha Purchase 30 2004 6.18 US$/Mcf (1)
Waha Purchase 27 2005 5.90 US$/Mcf 5
Waha Purchase 23 2006 5.32 US$/Mcf 4

Premiums Paid on
3-Way Call Spread 3
-------------------------------------------------------------------------
Total Natural Gas
Financial Positions (454)
Gas Storage Financial
Positions (49)
Gas Marketing Financial
Positions(4) 3
-------------------------------------------------------------------------
Total Fair Value
Positions (500)
Contracts Acquired 5
-------------------------------------------------------------------------
Total Unrealized Loss
on Financial Contracts $ (495)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Other Fixed Price Contracts relate to various price points at
Chicago, San Juan, Waha, Houston Ship Channel (HSC), Mid-Continent,
Rockies and Texas Oklahoma.
(2) Other Collars and Other Options relate to collars at Permian,
San Juan, Waha, Colorado Interstate Gas (CIG), HSC, Mid-Continent,
Rockies and Texas Oklahoma.
(3) Other Basis Contracts relate to Chicago, 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 September 30, 2004, the Company's oil risk management activities for
all financial contracts had an unrealized loss of $(558) million and a
fair market value position of $(537) million. The contracts were as
follows:
Notional Fair
Volumes Average Price Market
(bbl/d) Term (US$/bbl) Value
-------------------------------------------------------------------------

Fixed WTI NYMEX Price 62,500 2004 23.13 $(148)
Collars on WTI NYMEX 62,500 2004 20.00-25.69 (133)
Unwind WTI NYMEX Fixed Price (9,000) 2004 39.22 8
Purchased WTI NYMEX
Call Options (111,000) 2004 46.64 29

Fixed WTI NYMEX Price 45,000 2005 28.41 (260)
Costless 3-Way Put Spread 10,000 2005 20.00/25.00/28.78 (56)
Unwind WTI NYMEX Fixed Price (4,500) 2005 35.90 14
Purchased WTI NYMEX
Call Options (38,000) 2005 49.76 18

Fixed WTI NYMEX Price 15,000 2006 34.56 (27)
Purchased WTI NYMEX
Put Options 17,000 2006 26.59 (3)
-------------------------------------------------------------------------
(558)
Crude Oil Marketing Financial
Positions(1) -
-------------------------------------------------------------------------
Total Unrealized Loss on
Financial Contracts (558)
Premiums Paid on Call Options 21
-------------------------------------------------------------------------
Total Fair Value Positions $(537)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) The crude oil marketing activities are part of the daily ongoing
operations of the Company's proprietary production management.

15. COMMITMENTS AND CONTINGENCIES

Ecuador

In Ecuador, a subsidiary of the Company has a 40 percent 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.

16. RECLASSIFICATION

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

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 $14.27 Can 0

NYSE $11.11 USD 0

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