EnCana’s third quarter cash flow reaches US$1.93 billion, or $2.20 per share – up 51 percent

Natural gas sales increase 3 percent to 3.2 billion cubic feet per day

CALGARY, Oct. 26 /CNW/ - EnCana Corporation's (TSX & NYSE: ECA) third
quarter 2005 total cash flow per share increased 51 percent to US$2.20 per
share diluted, or $1.93 billion, compared to the third quarter of 2004. Total
operating earnings per share increased 33 percent to 80 cents per share
diluted, or $704 million, compared to the third quarter of 2004. Cash flow and
operating earnings increased due to stronger natural gas and liquids prices
and increased gas sales.
EnCana's third quarter net earnings were 30 cents per share diluted, or
$266 million, which included an unrealized after-tax loss of $604 million due
to mark-to-market accounting of all hedges and an unrealized foreign exchange
after-tax gain of $166 million on translation of Canadian issued U.S. dollar
debt. Of the $604 million unrealized hedging loss, about 60 percent relates to
EnCana's 2004 acquisition of Tom Brown, Inc. All of the Tom Brown hedge
positions expire at the end of 2006. In 2006, 82 percent of EnCana's forecast
sales are fully exposed to price upside. Total third quarter revenues net of
royalties were $3.38 billion.

IMPORTANT NOTE: EnCana reports in U.S. dollars and follows U.S.
protocols, which report sales and reserves on an after-royalties basis. All
dollar figures are U.S. dollars unless otherwise noted. All prior-period share
and per-share references have been adjusted to reflect the two-for-one common
share split which occurred in May 2005. EnCana is treating its Ecuador
operations as discontinued because EnCana is in the process of selling its
Ecuador assets. Total results, which include results from Ecuador, are
reported in the company's financial statements included in this news release
and in supplementary documents posted on its website - www.encana.com.

On September 13, 2005, EnCana announced it had reached an agreement to
sell all of its interests in Ecuador for approximately $1.42 billion, which is
approximately equivalent to the net book value of the assets at July 1, 2005,
the effective date of the transaction. In accordance with Generally Accepted
Accounting Principles for discontinued operations, the carrying value of
EnCanaès investments in Ecuador cannot exceed the expected selling price;
therefore, no net earnings from these assets will be shown subsequent to July
1, 2005.
Total natural gas sales in the third quarter increased to 3.22 billion
cubic feet per day, up 3 percent compared to the third quarter of 2004. Oil
and natural gas liquids (NGLs) sales were 219,200 barrels per day, down 16
percent mainly due to divestitures of conventional oil properties in Canada
and the U.K. North Sea and lower Ecuador sales. Third quarter sales of natural
gas, oil and NGLs from total operations were 4.5 billion cubic feet of gas
equivalent (Bcfe) per day. The impact of divestitures and a delay in the
timing of production additions resulted in total sales being down 3 percent
from the third quarter of 2004.

Third quarter generates strong cash flow, key resource play production up
13 percent
"Our third quarter was marked by strong cash flow and operating earnings,
plus steady growth from continuing operations in North American natural gas
production - up 4 percent, or 126 million cubic feet per day, since the third
quarter of 2004. Record setting wet weather in key Western Canadian producing
regions and industry activity levels in the North American oil and gas service
sector have restricted access to land and equipment in an unprecedented way
this year. As a result, we have drilled fewer wells to date this year than
planned and our gas production volumes are lagging forecast rates. EnCana also
has wells capable of delivering about 225 million cubic feet per day of
natural gas production waiting to be tied in to gathering and sales pipelines.
With more than 120 operated rigs active in our gas fields, we are expecting to
exit 2005 with gas sales of about 3.4 billion to 3.5 billion cubic feet per
day," said Gwyn Morgan, EnCana's President & Chief Executive Officer.
"The difference between our reduced 2005 production outlook and the
midpoint of our original guidance range amounts to about a two-month delay in
the ramp up of gas production. Our 2005 average gas production is now forecast
to be in the range of 3.25 billion to 3.30 billion cubic feet per day,
slightly below our original guidance range, but about 9 percent higher than
average 2004 sales. North American oil and NGLs sales are forecast to be
within original guidance. Despite these challenges, production from our key
resource plays is up 13 percent in the past year. The reservoir performance
across our portfolio of long-life unconventional assets remains strong. At the
same time, EnCana shareholders are benefiting from the market's robust energy
prices and our projects continue to generate strong investment returns,"
Morgan said.

2006 gas sales forecast to rise between 7 and 11 percent
In 2006, EnCana is forecasting gas sales of between 3.50 billion and
3.63 billion cubic feet per day, which represents an increase of between 7 and
11 percent from forecast midpoint for 2005 sales. North American oil and NGLs
sales are expected to be about the same as 2004, in the range of 155,000 to
160,000 barrels of oil per day, which reflects growth from expanding oilsands
projects being offset by declining production in conventional oil properties
and higher royalty rates due to achieving payout status at Pelican Lake around
year-end. Total North American sales are forecast to be between 4.43 billion
and 4.59 billion cubic feet equivalent per day, an increase of between 5 and 9
percent from the midpoint of the updated total North American sales guidance
range for 2005.

Moderated growth in 2006 expected to generate free cash flow
"We expect that 2006 will be characterized by continued high industry
activity levels and inflationary pressures, which are the product of the
strong commodity prices that are generating robust netbacks. Given these
conditions and the learnings we've gained from this year's experience, we have
moderated our North American production growth rate to between 5 and 9 percent
- a measured pace that's aimed at more efficiently converting our proved
reserves into sales growth and our Unbooked Resource Potential into proved
reserves as we generate substantial free cash flow," said Randy Eresman,
EnCana's Chief Operating Officer.

Third quarter milestones: Ecuador sale deal reached, Entrega pipeline
under construction, Brazil discovery
EnCana reached a series of important milestones in the third quarter: an
agreement to sell its Ecuador assets for $1.42 billion and the start of
construction on the Entrega natural gas pipeline out of the Piceance Basin in
the U.S. Rockies. In the waters offshore Brazil, EnCana drilled and tested a
third appraisal well about four kilometres from a promising oil discovery
named Chinook located in block BM-C-7. The test well was recently followed up
by an additional successful appraisal well that also encountered oil and high-
quality reservoir sands. Advancing the company's oilsands market
integration initiative, the company has arranged to import diluent from
overseas markets. In Texas, EnCana has made an initial land purchase in the
Maverick Basin - about 330,000 net acres with multi-zone gas resource play
potential.

Cutbank Doig formation gas discovery underlies Cutbank Ridge resource
play
"In addition, we recently made a substantial natural gas discovery in
British Columbia below our Cutbank Ridge resource play. This Cutbank Doig
find, which we estimate contains 350 billion to 550 billion cubic feet of
original gas in place net to EnCana, is producing about 25 million cubic feet
of gas per day in October from five wells. It is believed to be similar in
characteristics to the nearby Sinclair Doig pool in Alberta, which was
discovered in the late 1970s by an EnCana predecessor company, has produced
more than 250 billion cubic feet to date and is expected to yield more than
400 billion cubic feet during its life. Cutbank Doig is a clear illustration
of the exploration upside potential of deeper formations underlying the
extensive lands of our key resource plays.
"Alongside our continued strong resource play performance, all of these
third quarter achievements help reinforce EnCana's foundation for expected
sustainable profitable sales growth in future years," Eresman said.

Oilsands resources capable of delivering large, long-term production
expansion
"Our in-situ oilsands developments in northeast Alberta continue to
achieve top-level capital and operating efficiency. Expansion of Foster Creek
from 30,000 to 60,000 barrels per day is proceeding on schedule and should be
fully on stream by the end of 2006. Beyond that, we plan to progressively
develop steam-assisted gravity drainage production to more than 200,000
barrels of oil per day generally with projects and expansions of approximately
30,000 barrel per day increments. This is a size where we believe we have the
opportunity to capture advantages of scale while maintaining control of
execution, schedules and costs," Eresman said.

Nine months cash flow per share up 47 percent
Total cash flow per share in the first nine months increased 47 percent
to $5.50 per share diluted, or $4.92 billion. Total nine months operating
earnings increased 47 percent to $2.20 per share diluted, or $1.97 billion.
EnCana's total nine months net earnings per share increased 19 percent to
$1.19 per share diluted, or $1.06 billion, which includes an unrealized
mark-to-market after-tax loss of $1,023 million due to changes in the value of
commodity hedging positions at September 30, 2005 and an unrealized foreign
exchange gain of $113 million on translation of Canadian issued U.S. dollar
debt.
Nine months sales of natural gas, oil and NGLs from total operations were
4.55 Bcfe per day, about the same as in the first nine months of 2004. Total
natural gas sales increased 8 percent to 3.19 billion cubic feet per day.
Total oil and NGLs sales were 226,300 barrels per day, down 14 percent mainly
due to divestitures of conventional oil properties in Canada and the U.K.
North Sea.

IMPORTANT NOTE: All references in the remaining text of this news release
are on a continuing operations basis, which does not include results of the
Ecuador business, as it has been accounted for as discontinued.

Continuing operations: Cash flow up 45 percent; Operating earnings up
32 percent
Third quarter 2005 cash flow from continuing operations increased 45
percent to $1.82 billion compared to the same period in 2004. Cash taxes
during the third quarter were $169 million. Operating earnings from continuing
operations increased 32 percent to $731 million compared to the third quarter
of 2004. EnCana's third quarter net earnings from continuing operations
decreased 38 percent to $266 million, which included a $631 million after-tax
unrealized mark-to-market loss as a result of changes in the value of
commodity hedging positions at quarter-end compared to the previous quarter
and an after-tax unrealized gain of $166 million due to translation of U.S.
dollar denominated debt issued in Canada.

Natural gas sales from continuing operations up 4 percent, total sales
steady
Third quarter natural gas sales from continuing operations rose 4 percent
to 3.22 billion cubic feet per day compared with the third quarter of 2004,
mainly from resource play growth. Oil and NGLs sales from continuing
operations were 150,500 barrels per day, down 11 percent from the third
quarter one year earlier, due to property divestitures. Third quarter sales of
natural gas, oil and NGLs from continuing operations were 4.13 Bcfe per day,
about the same as during the third quarter of 2004.

Operating costs impacted by inflation and a depreciating U.S. dollar
Operating costs from continuing operations in the third quarter of 2005
were 69 cents per thousand cubic feet of gas equivalent (Mcfe), which is
higher than the company's previous forecast range due mainly to industry
inflation, the impact of a depreciating U.S. dollar, increased long-term,
stock-based compensation expenses and weather delays of planned production
additions. June was the wettest month in recorded history in Alberta and with
the oil and gas service sector running at unprecedented levels, the company
has found that it is unable to make up for lost drilling and completion days
as it has done in the past. To help mitigate these challenges, EnCana is
contracting with drilling companies to build an additional 46 fit-for-purpose
rigs. While EnCana expects full year operating costs to be about 13 percent
higher than the company's previous forecast of 55 to 60 cents per Mcfe, EnCana
expects to continue to be amongst the lowest cost operators in the industry.
EnCana drilled 1,150 net wells during the third quarter. Third quarter core
capital investment was $1.46 billion. The company's recent addition of
approximately $250 million of capital investment in 2005 is directed to
capture key land positions in emerging resource plays. EnCana has updated its
2005 corporate guidance to reflect its most recent sales and operating cost
outlooks, and has posted its 2006 corporate guidance on its website,
www.encana.com.

Nine months operating earnings from continuing operations up 36 percent
Nine months 2005 operating earnings increased 36 percent to
$1.87 billion. Nine months 2005 cash flow from continuing operations increased
46 percent to $4.64 billion. EnCana's nine months net earnings from continuing
operations decreased 9 percent to $927 million, which includes two non-cash
items: an after-tax unrealized mark-to-market hedge loss of $1.06 billion and
an after-tax unrealized mark-to-market gain on foreign exchange on U.S. dollar
denominated debt issued in Canada of $113 million. Nine months 2005 revenues
net of royalties were $9.33 billion. EnCana drilled 3,520 net wells in the
first nine months of 2005.

North American natural gas prices strengthen in the third quarter of 2005
The average third quarter benchmark NYMEX index gas price was $8.49 per
thousand cubic feet, up 47 percent from $5.76 per thousand cubic feet in the
third quarter of 2004. EnCana's North American realized natural gas prices,
excluding financial hedging, averaged $7.29 per thousand cubic feet, up 41
percent from an average of $5.18 per thousand cubic feet in the third quarter
of 2004. Natural gas prices have continued to increase due primarily to high
world oil prices, continued global economic strength, a lack of growth in
domestic natural gas production and hurricane damage to Gulf of Mexico
production facilities.

Third quarter world oil and Canadian heavy oil prices remain strong
Oil and NGLs continued to trade at strong prices during the third quarter
of 2005 due to continued global demand growth, diminished supply due to Gulf
of Mexico hurricane damage and tightening global production and refining
capacity. During the third quarter of 2005, the average benchmark West Texas
Intermediate (WTI) crude oil price was $63.31 per barrel, up 44 percent from
the third quarter 2004 average of $43.89 per barrel. Strong asphalt markets in
Canada in the third quarter helped support Canadian heavy oil prices. The
WTI/Bow River differential was $17.08 per barrel, yielding a Bow River blend
price of $46.23 per barrel, a price that was about 73 percent of WTI prices,
which is about the same in percentage terms as in the third quarter of 2004.
In the third quarter, EnCana's average realized oil and NGLs price was $46.16
per barrel, up 44 percent from the third quarter of 2004.

Price risk management
EnCana's price risk mitigation strategy is intended to provide downside
protection and deliver greater certainty of cash flows and returns on
investments. Detailed risk management positions at September 30, 2005 are
presented in Note 12 to the unaudited third quarter consolidated financial
statements. In the third quarter of 2005, EnCana's financial price risk
management measures resulted in realized losses of approximately $135 million
after-tax, comprised of a $52 million loss on oil hedges, an $88 million loss
on gas hedges and a $5 million gain on other hedges. A review of the company's
hedging strategy in 2004 resulted in more frequent use of put options to
protect downside but which do not limit upside in a rising price environment.
About 80 percent of 2006 forecast gas sales is exposed to price upside,
while about 46 percent has downside price protection. About 91 percent of 2006
forecast oil and NGLs sales is exposed to price upside, while about 46 percent
has downside protection. Overall, on a Mcfe basis, about 82 percent of
EnCana's forecast 2006 sales are exposed to market price upside.


EnCana Continuing Operations Highlights
---------------------------------------
US$ and U.S. protocols
----------------------
-------------------------------------------------------------------------
Financial Highlights
(as at and for the period
ended September 30) Q3 Q3 % 9 months 9 months %
($ millions) 2005 2004 change 2005 2004 change
-------------------------------------------------------------------------
Revenues,
net of royalties 3,089 2,320 + 33 9,331 7,602 + 23
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Pre-tax cash flow 1,992 1,362 + 46 5,120 3,687 + 39
Less:
Cash tax 169 103 + 64 477 511 -7
-------------------------------------------------------------------------
Cash flow 1,823 1,259 + 45 4,643 3,176 + 46
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net acquisitions &
divestitures 166 (901) n/a (1,664)(*) 1,034 n/a
Add:
Core capital 1,456 963 + 51 4,389 3,250 + 35
-------------------------------------------------------------------------
Net capital investment 1,622 62 n/a 2,725 4,284 n/a
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net earnings 266 432 -38 927 1,023 -9

Add (Deduct):
Unrealized mark-to-market
hedging loss, after-tax 631 276 + 129 1,058 561 + 89

Unrealized foreign
exchange (gain) on
translation of U.S.
dollar debt issued in
Canada, after-tax (166) (155) + 7 (113) (98) + 15

Future tax (recovery) due
to tax rate change - - n/a - (109) n/a
-------------------------------------------------------------------------
Operating earnings 731 553 + 32 1,872 1,377 + 36
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) Includes proceeds from Gulf of Mexico sale of $2.1 billion, minus tax
of $591 million


EnCana financial results in U.S. dollars and operating results according
to U.S. protocols

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

-------------------------------------------------------------------------
Operating Highlights
(for the period ended
September 30) Q3 Q3 % 9 months 9 months %
(After royalties) 2005 2004 change 2005 2004 change
-------------------------------------------------------------------------
North America Natural
Gas sales (MMcf/d) 3,222 3,096 + 4 3,193 2,928 + 9
North America Oil and
NGLs (bbls/d) 150,457 169,673 -11 154,892 168,750 - 8
-------------------------------------------------------------------------
Total sales (MMcfe/d) 4,125 4,114 - 4,122 3,941 + 5
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Key resource play production growth up about 13 percent across EnCana's
portfolio
Development capital continues to be focused on turning EnCana's Unbooked
Resource Potential into reserves and production. Third quarter gas and oil
production from key North American resource plays has increased approximately
13 percent since the third quarter of 2004. Year-over-year gas production
growth is driven mainly by the Piceance basin in Colorado, coalbed methane on
the legacy Palliser Block in Alberta and Cutbank Ridge in northeast British
Columbia. Through much of 2005, gas production growth in the Piceance Basin
remained flat as the company expands production in newer and less well-
developed fields. The company has invested in building production
infrastructure in these new areas and bringing efficiencies to drilling
logistics, evidenced by recent production increases. Piceance Basin is
currently producing about 320 million cubic feet per day and expects to grow
2005 average production by more than 17 percent, compared to 2004. The
successful application of a water flood at Pelican Lake in northeast Alberta
helped grow oil production by about 26 percent in the past year. Foster
Creek's steam-assisted gravity drainage project is expanding from 30,000 to
60,000 barrels per day of production over the next year. The first 10,000
barrels per day of additional volumes is scheduled to start late this year.


Growth from key North American resource plays

-----------------------------------------------------------
Resource Play

(After royalties) Daily Production
----------------------------
2005
-----------------------------------------------------------
YTD Q3 Q2 Q1
-----------------------------------------------------------
Natural Gas (MMcf/d)
Jonah 429 440 416 431
Piceance 300 302 302 300
East Texas 87 94 85 82
Fort Worth 64 66 63 61
Greater Sierra 217 225 228 195
Cutbank Ridge 81 105 80 56
CBM 50 62 51 38
Shallow Gas 624 616 633 625
-----------------------------------------------------------
Oil (Mbbls/d)
Foster Creek 27 27 24 30
Pelican Lake 25 27 27 21
-----------------------------------------------------------
-----------------------------------------------------------
Total (MMcfe/d) 2,166 2,235 2,166 2,096
-----------------------------------------------------------
% change from prior year's
quarter 13.1 16.6 23.6
-----------------------------------------------------------
% change from prior period 3.2 3.3 3.0
-----------------------------------------------------------
-----------------------------------------------------------


-------------------------------------------------------------------------
Resource Play

(After royalties) Daily Production
-----------------------------------------
2004 2003
-------------------------------------------------------------------------
Full Full
Year Q4 Q3 Q2 Q1 Year
-------------------------------------------------------------------------
Natural Gas (MMcf/d)
Jonah 389 404 373 387 394 374
Piceance 261 291 282 251 218 151
East Texas 50 83 81 36 - -
Fort Worth 27 34 31 23 21 7
Greater Sierra 230 211 244 247 216 143
Cutbank Ridge 40 50 45 41 22 3
CBM 17 27 19 11 10 4
Shallow Gas 592 629 595 590 554 507
-------------------------------------------------------------------------
Oil (Mbbls/d)
Foster Creek 29 28 29 30 28 22
Pelican Lake 19 23 22 15 15 16
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total (MMcfe/d) 1,892 2,034 1,976 1,858 1,696 1,416
-------------------------------------------------------------------------
% change from prior year's
quarter
-------------------------------------------------------------------------
% change from prior period 33.6 2.9 6.4 9.6 7.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Drilling activity in key North American resource plays

-----------------------------------------------------------
Resource Play Net Wells Drilled
----------------------------
2005
-----------------------------------------------------------
YTD Q3 Q2 Q1
-----------------------------------------------------------
Natural Gas
Jonah 83 25 30 28
Piceance 211 69 65 77
East Texas 64 21 22 21
Fort Worth 39 18 12 9
Greater Sierra 139 33 47 59
Cutbank Ridge 101 40 38 23
CBM 757 216 219 322
Shallow Gas 979 341 365 273
-----------------------------------------------------------
Oil
Foster Creek 26 14 2 10
Pelican Lake 56 3 34 19
-----------------------------------------------------------
-----------------------------------------------------------
Total net wells 2,455 780 834 841
-----------------------------------------------------------
-----------------------------------------------------------


-------------------------------------------------------------------------
Resource Play Net Wells Drilled
------------------------------------------
2004 2003
-------------------------------------------------------------------------
Full Full
year Q4 Q3 Q2 Q1 Year
-------------------------------------------------------------------------
Natural Gas
Jonah 70 21 17 21 11 59
Piceance 250 47 66 66 71 284
East Texas 50 23 20 7 - -
Fort Worth 36 8 10 10 8 5
Greater Sierra 187 18 13 21 135 199
Cutbank Ridge 50 17 12 4 17 20
CBM 760 234 347 98 81 267
Shallow Gas 1,552 222 384 416 530 2,366
-------------------------------------------------------------------------
Oil
Foster Creek 11 7 - - 4 8
Pelican Lake 92 - 33 30 29 134
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total net wells 3,058 597 902 673 886 3,342
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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

EnCana CEO to step down at year-end; COO Randy Eresman to succeed Gwyn
Morgan
On October 25, 2005, EnCana's founding President & Chief Executive
Officer Gwyn Morgan announced his intention to step down at year-end. He will
remain an officer of the company in the role of Executive Vice-Chairman for
the year 2006, working mainly in an advisory capacity to the new Chief
Executive Officer.
EnCana's board of directors also announced the appointment of Randall K.
Eresman as President & Chief Executive Officer and a Director, effective
January 1, 2006. A petroleum engineering graduate from the University of
Wyoming, Eresman joined EnCana predecessor company Alberta Energy Company Ltd.
(AEC) in 1980. He played a key role in the building of AEC and was appointed
Chief Operating Officer of EnCana soon after its creation in 2002.

Quarterly dividend of 7.5 cents per share declared
EnCana's board of directors has declared a quarterly dividend of
7.5 cents per share which is payable on December 30, 2005 to common
shareholders of record as of December 15, 2005.

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 85,603,640 of its common shares,
representing 10 percent of the public float of approximately 856,036,400
common shares outstanding as at October 25, 2005. EnCana plans to fund its
share purchases under the renewed bid with proceeds from planned asset
divestitures and cash flow. In the past 12 months under its previous Normal
Course Issuer Bid, EnCana purchased 84,208,100 common shares, representing
approximately 9.1 percent of the company's outstanding shares on October 22,
2004, at an average price of approximately US$32.05 per common share.
Purchases under the renewed bid may commence on October 31, 2005 and may be
made until October 30, 2006. 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.

-------------------------------------------------------------------------
First 9 Full
Changes in Share Capital months Year %
(millions of shares) 2005 2004 change
-------------------------------------------------------------------------
Common shares outstanding,
beginning of period 900.6 921.2 - 2.2
Shares issued under option plan 13.9 19.4
Shares purchased under Normal Course Issuer Bid (60.7) (40.0)
-------------------------------------------------------------------------
Common shares outstanding, end of period 853.8 900.6 - 5.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------

2006 capital investment
EnCana's 2006 budget is directed towards continuing to achieve strong
production growth from the company's portfolio of sustainable, long-term
resource plays across North America. Capital investment is forecast to
increase in 2006 due to service industry inflation and the high levels of
field activity, both of which are fuelled by the strong commodity price
environment EnCana benefits from. The company's tempered growth rate of
between 5 and 9 percent is a measured pace that's designed to enhance capital
efficiency as the company converts its proved reserves and Unbooked Resource
Potential into sales growth and free cash flow for reinvestment in attractive
shareholder returns.

--------------------------------------------------------------
EnCana capital investment forecast by type ($ billions)
--------------------------------------------------------------
2005 2006
--------------------------------------------------------------
Upstream
Maintain production(1) 2.6 2.9 - 3.1
Achieve current year's growth(1) 1.8 2.1 - 2.2
Oilsands 0.4 0.5 - 0.5
International 0.1 0.1 - 0.1
Other long-lead time growth 0.6 0.6 - 0.6
--------------------------------------------------------------
--------------------------------------------------------------
Sub-total 5.5 6.2 - 6.5
Midstream (Entrega Pipeline)
and Corporate 0.4 0.4 - 0.5
--------------------------------------------------------------
--------------------------------------------------------------
Core Capital Investment 5.9 6.6 - 7.0
--------------------------------------------------------------
--------------------------------------------------------------
Acquisitions(2) 0.4 n/a
Divestitures(3) (3.8 - 4.4) n/a
--------------------------------------------------------------
Net acquisitions and divestitures (3.4 - 4.0) (0.5 - 1.5)
Discontinued Operations 0.2 n/a
--------------------------------------------------------------
--------------------------------------------------------------
Net Capital Investment (forecast) 2.7 - 2.1 6.1 - 5.5
--------------------------------------------------------------
(1) Excludes oilsands
(2) 2005 represents miscellaneous acquisitions including the
Maverick Basin of Texas
(3) 2005 includes sale of Canadian conventional oil, Gulf of Mexico
assets and the pending sale of Ecuador assets

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

At September 30, 2005 the company's net debt-to-capitalization ratio was
40:60. Completion of planned asset divestitures, including EnCana's businesses
in Ecuador, natural gas liquids processing and natural gas storage, is
expected to generate sales proceeds in the range of $2.5 billion to $3.5
billion. EnCana's net debt-to-EBITDA multiple, on a trailing 12-month basis,
was 1.6 times. In the third quarter of 2005, EnCana invested $1.46 billion of
core capital. Acquisitions and divestitures resulted in net investment of $166
million, resulting in net capital investment of $1.62 billion during the third
quarter. Not surprisingly, with strong commodity prices, cash taxes as a
percent of pre-tax cash flow are also expected to be higher in 2006 as
outlined in EnCana's corporate guidance.

Updated corporate guidance
EnCana has updated its 2005 corporate guidance and has posted new
corporate guidance for 2006 on its website: www.encana.com.

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CONFERENCE CALL TODAY
11 a.m. Mountain Time (1 p.m. Eastern Time)

EnCana Corporation will host a conference call today, Wednesday, October
26, 2005 starting at 11 a.m., Mountain Time (1 p.m. Eastern Time), to
discuss EnCana's third quarter 2005 financial and operating results.

To participate, please dial (913) 981-4911 approximately 10 minutes prior
to the conference call. An archived recording of the call will be
available from approximately 3 p.m. MT on October 26 until midnight
November 1, 2005 by dialing (888) 203-1112 or (719) 457-0820 and entering
access code 4309245.

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

EnCana Corporation
With an enterprise value of approximately US$52 billion, EnCana is one of
North America's leading natural gas producers, is among the largest holders of
gas and oil resource lands onshore North America and is a technical and cost
leader in the in-situ recovery of oilsands bitumen. EnCana delivers
predictable, reliable, profitable growth from its portfolio of long- life
resource plays situated in Canada and the United States. Contained in
unconventional reservoirs, resource plays are large contiguous accumulations
of hydrocarbons, located in thick or areally extensive deposits, that
typically have lower geological and commercial development risk, lower average
decline rates and very long producing lives compared to conventional plays.
The application of technology to unlock the huge resource potential of these
plays typically results in continuous increases in production and reserves and
decreases in costs over multiple decades of resource play life. EnCana common
shares trade on the Toronto and New York stock exchanges under the symbol ECA.

NOTE 1: Non-GAAP measures
This news release contains references to cash flow, pre-tax cash flow,
cash flow from continuing operations, operating earnings from continuing
operations, total operating earnings and EBITDA. Total operating earnings is a
non-GAAP measure that shows net earnings excluding non-operating items such as
the after-tax impacts of a gain on the sale of discontinued operations, the
after-tax gain/loss of unrealized mark-to-market accounting for derivative
instruments, the after-tax gain/loss on translation of U.S. dollar denominated
debt issued in Canada and the effect of the reduction in income tax rates.
Management believes these items reduce the comparability of the company's
underlying financial performance between periods. The majority of the
unrealized gains/losses that relate to U.S. dollar debt issued in Canada are
for debt with maturity dates in excess of five years. EBIDTA is a non- GAAP
measure that shows net earnings from continuing operations before gain on
disposition, income taxes, foreign exchange gains or losses, interest net,
accretion of asset retirement obligation and depletion, depreciation and
amortization. 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.

ADVISORY REGARDING RESERVES DATA AND OTHER OIL AND GAS INFORMATION -
EnCana's disclosure of reserves data and other oil and gas information is
made in reliance on an exemption granted to EnCana by Canadian securities
regulatory authorities which permits it to provide such disclosure in
accordance with U.S. disclosure requirements. The information provided by
EnCana may differ from the corresponding information prepared in accordance
with Canadian disclosure standards under National Instrument 51-101
(NI 51-101). EnCana's reserves quantities represent net proved reserves
calculated using the standards contained in Regulation S-X of the U.S.
Securities and Exchange Commission. Further information about the differences
between the U.S. requirements and the NI 51-101 requirements is set forth
under the heading "Note Regarding Reserves Data and Other Oil and Gas
Information" in EnCana's Annual Information Form.
In this news release, certain crude oil and NGLs volumes have been
converted to cubic feet equivalent (cfe) on the basis of one barrel (bbl) to
six thousand cubic feet (Mcf). Also, certain natural gas volumes have been
converted to barrels of oil equivalent (BOE) on the same basis. BOE and cfe
may be misleading, particularly if used in isolation. A conversion ratio of
one bbl to six Mcf is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not necessarily represent
value equivalency at the well head. EnCana defines Unbooked Resource Potential
as quantities of oil and gas on existing land holdings that are not yet
classified as proved reserves, but which EnCana believes may be moved into the
proved reserves category and produced in the future.

ADVISORY REGARDING FORWARD-LOOKING STATEMENTS - In the interests of
providing EnCana shareholders and potential investors with information
regarding EnCana, including management's assessment of EnCana's and its
subsidiaries' future plans and operations, certain statements contained in
this news release are forward-looking statements within the meaning of the
"safe harbour" provisions of the United States Private Securities Litigation
Reform Act of 1995. Forward-looking statements in this news release include,
but are not limited to: future economic and operating performance; anticipated
future cash flow; anticipated cash taxes in 2006; anticipated growth and
success of resource plays and the expected characteristics of resource plays;
the planned sale of interests in Ecuador, the midstream NGLs business unit and
the natural gas storage business and the timing of such potential
transactions; the expected proceeds from planned divestitures and the use of
proceeds from divestitures for share purchases under the company's Normal
Course Issuer Bid program and debt repayment; projections with respect to the
company's Unbooked Resource Potential and projected future production growth;
expected debt levels and debt to capitalization ratios; anticipated expiry of
certain commodity hedge positions; the potential success of projects such as
Entrega, Brazil, Maverick Basin and Cutbank Doig; anticipated production from
the Sinclair Doig; estimates of original gas in place; the belief in the
similarity of characteristics of the Cutbank Doig to the Sinclair Doig;
anticipated effect of EnCana's market risk mitigation strategy and EnCana's
ability to participate in commodity price upside; anticipated purchases
pursuant to the Normal Course Issuer Bid; anticipated production in 2005 and
beyond; anticipated drilling; the capacity of the company's steam-assisted
gravity drainage expansion project at Foster Creek and the timing thereof;
anticipated expansion of the company's oilsands resources; potential capital
expenditures and investment and the impact of inflation; potential oil,
natural gas and NGLs sales in 2005 and beyond; anticipated ability to meet
production, operating cost, cash tax and sales guidance targets; anticipated
costs and the ability to mitigate against drilling costs increases;
anticipated commodity prices; projections relating to project returns from
EnCana's North American resource plays and potential risks associated with
drilling and references to potential exploration. Readers are cautioned not to
place undue reliance on forward-looking statements, as there can be no
assurance that the plans, intentions or expectations upon which they are based
will occur. By their nature, forward-looking statements involve numerous
assumptions, known and unknown risks and uncertainties, both general and
specific, that contribute to the possibility that the predictions, forecasts,
projections and other forward-looking statements will not occur, which may
cause the company's actual performance and financial results in future periods
to differ materially from any estimates or projections of future performance
or results expressed or implied by such forward-looking statements. These
risks and uncertainties include, among other things: volatility of oil and gas
prices; fluctuations in currency and interest rates; product supply and
demand; market competition; risks inherent in the company's marketing
operations, including credit risks; imprecision of reserves estimates and
estimates of recoverable quantities of oil, natural gas and liquids from
resource plays and other sources not currently classified as proved reserves;
the company's ability to replace and expand oil and gas reserves; its ability
to generate sufficient cash flow from operations to meet its current and
future obligations; its ability to access external sources of debt and equity
capital; the timing and the costs of well and pipeline construction; the
company's ability to secure adequate product transportation; changes in
environmental and other regulations or the interpretations of such
regulations; political and economic conditions in the countries in which the
company operates, including Ecuador; the risk of war, hostilities, civil
insurrection and instability affecting countries in which the company operates
and terrorist threats; risks associated with existing and potential future
lawsuits and regulatory actions made against the company; and other risks and
uncertainties described from time to time in the reports and filings made with
securities regulatory authorities by EnCana. Although EnCana believes that the
expectations represented by such forward- looking statements are reasonable,
there can be no assurance that such expectations will prove to be correct.
Readers are cautioned that the foregoing list of important factors is not
exhaustive.
Furthermore, the forward-looking statements contained in this news
release are made as of the date of this news release, and EnCana does not
undertake any obligation to update publicly or to revise any of the included
forward-looking statements, whether as a result of new information, future
events or otherwise. The forward-looking statements contained in this news
release are expressly qualified by this cautionary statement.


CONSOLIDATED STATEMENT OF EARNINGS (unaudited)

Three Months Ended Nine Months Ended
September 30, September 30,
($ millions, except ---------------------------------------
per share amounts) 2005 2004 2005 2004
-------------------------------------------------------------------------

REVENUES, NET OF
ROYALTIES (Note 2)
Upstream $ 2,680 $ 1,861 $ 7,013 $ 5,253
Midstream & Market
Optimization 1,348 889 3,914 3,206
Corporate - Unrealized (loss)
on risk management (939) (430) (1,596) (859)
- Other - - - 2
-------------------------------------------------------------------------
3,089 2,320 9,331 7,602

EXPENSES (Note 2)
Production and mineral taxes 107 79 291 216
Transportation and selling 139 118 406 390
Operating 432 340 1,177 960
Purchased product 1,244 800 3,540 2,909
Depreciation, depletion and
amortization 677 605 2,038 1,761
Administrative 78 43 205 136
Interest, net 218 106 419 284
Accretion of asset retirement
obligation (Note 8) 9 7 27 16
Foreign exchange (gain) (Note 5) (213) (290) (63) (213)
Stock-based compensation 4 5 12 14
(Gain) on divestitures (Note 4) - - - (35)
-------------------------------------------------------------------------
2,695 1,813 8,052 6,438
-------------------------------------------------------------------------
NET EARNINGS BEFORE INCOME TAX 394 507 1,279 1,164
Income tax expense (Note 6) 128 75 352 141
-------------------------------------------------------------------------
NET EARNINGS FROM CONTINUING
OPERATIONS 266 432 927 1,023
NET EARNINGS (LOSS) FROM
DISCONTINUED OPERATIONS (Note 3) - (39) 133 (90)
-------------------------------------------------------------------------
NET EARNINGS $ 266 $ 393 $ 1,060 $ 933
-------------------------------------------------------------------------
-------------------------------------------------------------------------

NET EARNINGS FROM
CONTINUING OPERATIONS
PER COMMON SHARE (Note 11)
Basic $ 0.31 $ 0.47 $ 1.06 $ 1.11
Diluted $ 0.30 $ 0.46 $ 1.04 $ 1.10
-------------------------------------------------------------------------
-------------------------------------------------------------------------

NET EARNINGS PER COMMON
SHARE (Note 11)
Basic $ 0.31 $ 0.43 $ 1.21 $ 1.01
Diluted $ 0.30 $ 0.42 $ 1.19 $ 1.00
-------------------------------------------------------------------------
-------------------------------------------------------------------------



CONSOLIDATED STATEMENT OF RETAINED EARNINGS (unaudited)

Nine Months Ended
September 30,
---------------------
($ millions) 2005 2004
-------------------------------------------------------------------------

RETAINED EARNINGS, BEGINNING OF YEAR $ 7,935 $ 5,276
Net Earnings 1,060 933
Dividends on Common Shares (174) (137)
Charges for Normal Course Issuer Bid (Note 9) (1,495) (126)
Charges for Shares Repurchased and Held (Note 9) (147) -
-------------------------------------------------------------------------
RETAINED EARNINGS, END OF PERIOD $ 7,179 $ 5,946
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.



CONSOLIDATED BALANCE SHEET (unaudited)
As at As at
September December
($ millions) 30, 2005 31, 2004
-------------------------------------------------------------------------

ASSETS
Current Assets
Cash and cash equivalents $ 146 $ 602
Accounts receivable and accrued revenues 2,843 1,898
Risk management (Note 12) 432 336
Inventories 680 513
Assets of discontinued operations (Note 3) 309 156
-------------------------------------------------------------------------
4,410 3,505
Property, Plant and Equipment, net (Note 2) 23,891 23,140
Investments and Other Assets 461 334
Risk Management (Note 12) 316 87
Assets of Discontinued Operations (Note 3) 1,674 1,623
Goodwill 2,599 2,524
-------------------------------------------------------------------------
(Note 2) $ 33,351 $ 31,213
-------------------------------------------------------------------------
-------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued liabilities $ 2,460 $ 1,879
Income tax payable 475 359
Risk management (Note 12) 1,948 241
Liabilities of discontinued operations (Note 3) 331 280
Current portion of long-term debt (Note 7) 219 188
-------------------------------------------------------------------------
5,433 2,947
Long-Term Debt (Note 7) 8,225 7,742
Other Liabilities 116 118
Risk Management (Note 12) 308 192
Asset Retirement Obligation (Note 8) 674 611
Liabilities of Discontinued Operations (Note 3) 177 102
Future Income Taxes 4,615 5,193
-------------------------------------------------------------------------
19,548 16,905
-------------------------------------------------------------------------
Shareholders' Equity
Share capital (Note 9) 5,107 5,299
Share options, net - 10
Paid in surplus 110 28
Retained earnings 7,179 7,935
Foreign currency translation adjustment 1,407 1,036
-------------------------------------------------------------------------
13,803 14,308
-------------------------------------------------------------------------
$ 33,351 $ 31,213
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.



CONSOLIDATED STATEMENT OF CASH FLOWS (unaudited)

Three Months Ended Nine Months Ended
September 30, September 30,
---------------------------------------
($ millions) 2005 2004 2005 2004
-------------------------------------------------------------------------

OPERATING ACTIVITIES
Net earnings from continuing
operations $ 266 $ 432 $ 927 $ 1,023
Depreciation, depletion and
amortization 677 605 2,038 1,761
Future income taxes (Note 6) (41) (28) (716) (370)
Cash tax on sale of
assets (Note 4) - - 591 -
Unrealized loss on risk
management (Note 12) 938 426 1,593 852
Unrealized foreign
exchange (gain) (202) (193) (79) (122)
Accretion of asset retirement
obligation (Note 8) 9 7 27 16
(Gain) on divestitures (Note 4) - - - (35)
Other 176 10 262 51
-------------------------------------------------------------------------
Cash flow from continuing
operations 1,823 1,259 4,643 3,176
Cash flow from discontinued
operations 108 104 273 313
-------------------------------------------------------------------------
Cash flow 1,931 1,363 4,916 3,489
Net change in other assets
and liabilities (160) (25) (174) (71)
Net change in non-cash working
capital from continuing
operations (543) (387) (659) (402)
Net change in non-cash working
capital from discontinued
operations (18) 117 (75) 287
-------------------------------------------------------------------------
1,210 1,068 4,008 3,303
-------------------------------------------------------------------------

INVESTING ACTIVITIES
Business combination with
Tom Brown, Inc. - - - (2,335)
Capital expenditures (Note 2) (1,635) (1,002) (4,606) (3,308)
Proceeds on disposal of
assets (Note 4) 34 940 2,493 1,359
Cash tax on sale of
assets (Note 4) - - (591) -
Equity investments - 8 - 52
Net change in investments
and other 35 (8) 27 (25)
Net change in non-cash working
capital from continuing
operations (355) 14 93 (98)
Discontinued operations (90) (221) (197) (599)
-------------------------------------------------------------------------
(2,011) (269) (2,781) (4,954)
-------------------------------------------------------------------------

FINANCING ACTIVITIES
Net issuance (repayment)
of revolving long-term debt 1,691 (662) 976 (215)
Issuance of long-term debt 428 1,000 428 3,761
Repayment of long-term debt (958) (1,205) (959) (1,754)
Issuance of common
shares (Note 9) 86 30 270 184
Purchase of common
shares (Note 9) (452) - (2,114) (230)
Dividends on common shares (64) (45) (174) (137)
Other (105) (6) (108) (11)
-------------------------------------------------------------------------
626 (888) (1,681) 1,598
-------------------------------------------------------------------------

DEDUCT: FOREIGN EXCHANGE GAIN ON
CASH AND CASH EQUIVALENTS HELD
IN FOREIGN CURRENCY 4 - 2 -
-------------------------------------------------------------------------

DECREASE IN CASH AND CASH
EQUIVALENTS (179) (89) (456) (53)
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD 325 149 602 113
-------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS,
END OF PERIOD $ 146 $ 60 $ 146 $ 60
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.



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

1. BASIS OF PRESENTATION

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

The interim Consolidated Financial Statements have been prepared
following the same accounting policies and methods of computation as the
annual audited Consolidated Financial Statements for the year ended
December 31, 2004. 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, 2004.

2. SEGMENTED INFORMATION

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

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

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

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

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

Operations that have been discontinued are disclosed in Note 3.


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

Midstream & Market
Upstream Optimization
---------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 2,680 $ 1,861 $ 1,348 $ 889
Expenses
Production and mineral taxes 107 79 - -
Transportation and selling 133 114 6 4
Operating 348 262 85 77
Purchased product - - 1,244 800
Depreciation, depletion and
amortization 649 583 9 8
-------------------------------------------------------------------------
Segment Income $ 1,443 $ 823 $ 4 $ -
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Corporate(*) Consolidated
---------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------

Revenues, Net of Royalties $ (939) $ (430) $ 3,089 $ 2,320
Expenses
Production and mineral taxes - - 107 79
Transportation and selling - - 139 118
Operating (1) 1 432 340
Purchased product - - 1,244 800
Depreciation, depletion
and amortization 19 14 677 605
-------------------------------------------------------------------------
Segment Income (Loss) $ (957) $ (445) 490 378
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Administrative 78 43
Interest, net 218 106
Accretion of asset retirement
obligation 9 7
Foreign exchange gain (213) (290)
Stock-based compensation 4 5
Gain on divestitures - -
-------------------------------------------------------------------------
96 (129)
-------------------------------------------------------------------------
Net Earnings Before Income Tax 394 507
Income tax expense 128 75
-------------------------------------------------------------------------
Net Earnings From Continuing Operations $ 266 $ 432
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(*) For the three months ended September 30, the unrealized gain (loss)
on risk management is recorded in the Consolidated Statement of
Earnings as follows (see also Note 12):

2005 2004
-------------------------------------------------------------------------

Revenues, Net of Royalties - Corporate $ (939) $ (429)
Operating Expenses and Other - Corporate (1) 1
-------------------------------------------------------------------------
Total Unrealized Loss on Risk Management -
Continuing Operations $ (938) $ (430)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Upstream Canada United States
---------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 1,807 $ 1,283 $ 797 $ 512
Expenses
Production and mineral taxes 24 23 83 56
Transportation and selling 84 91 49 23
Operating 207 170 56 32
Depreciation, depletion and
amortization 485 445 157 131
-------------------------------------------------------------------------
Segment Income $ 1,007 $ 554 $ 452 $ 270
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Other Total Upstream
---------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 76 $ 66 $ 2,680 $ 1,861
Expenses
Production and mineral taxes - - 107 79
Transportation and selling - - 133 114
Operating 85 60 348 262
Depreciation, depletion and
amortization 7 7 649 583
-------------------------------------------------------------------------
Segment Income (Loss) $ (16) $ (1) $ 1,443 $ 823
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Total Midstream
Midstream & Market Market & Market
Optimization Midstream Optimization Optimization
------------------------------------------------
2005 2004 2005 2004 2005 2004
-------------------------------------------------------------------------

Revenues $ 195 $ 158 $1,153 $ 731 $1,348 $ 889
Expenses
Transportation and
selling - - 6 4 6 4
Operating 67 65 18 12 85 77
Purchased product 115 88 1,129 712 1,244 800
Depreciation, depletion
and amortization 8 8 1 - 9 8
-------------------------------------------------------------------------
Segment Income (Loss) $ 5 $ (3) $ (1) $ 3 $ 4 $ -
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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

Produced Gas Produced Gas
------------------------------------------------
Canada United States Total
------------------------------------------------
2005 2004 2005 2004 2005 2004
-------------------------------------------------------------------------

Revenues, Net of
Royalties $1,317 $ 970 $ 726 $ 462 $2,043 $1,432
Expenses
Production and mineral
taxes 19 18 77 51 96 69
Transportation and
selling 70 72 49 23 119 95
Operating 134 99 56 32 190 131
-------------------------------------------------------------------------
Operating Cash Flow $1,094 $ 781 $ 544 $ 356 $1,638 $1,137
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Oil & NGLs Oil & NGLs
------------------------------------------------
Canada United States Total
------------------------------------------------
2005 2004 2005 2004 2005 2004
-------------------------------------------------------------------------

Revenues, Net of
Royalties $ 490 $ 313 $ 71 $ 50 $ 561 $ 363
Expenses
Production and mineral
taxes 5 5 6 5 11 10
Transportation and
selling 14 19 - - 14 19
Operating 73 71 - - 73 71
-------------------------------------------------------------------------
Operating Cash Flow $ 398 $ 218 $ 65 $ 45 $ 463 $ 263
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Other & Total Upstream Other Total Upstream
---------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 76 $ 66 $ 2,680 $ 1,861
Expenses
Production and mineral taxes - - 107 79
Transportation and selling - - 133 114
Operating 85 60 348 262
-------------------------------------------------------------------------
Operating Cash Flow $ (9) $ 6 $ 2,092 $ 1,406
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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

Midstream & Market
Upstream Optimization
---------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 7,013 $ 5,253 $ 3,914 $ 3,206
Expenses
Production and mineral taxes 291 216 - -
Transportation and selling 390 370 16 20
Operating 936 740 244 224
Purchased product - - 3,540 2,909
Depreciation, depletion
and amortization 1,957 1,657 27 60
-------------------------------------------------------------------------
Segment Income (Loss) $ 3,439 $ 2,270 $ 87 $ (7)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Corporate(*) Consolidated
---------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------

Revenues, Net of Royalties $(1,596) $ (857) $ 9,331 $ 7,602
Expenses
Production and mineral taxes - - 291 216
Transportation and selling - - 406 390
Operating (3) (4) 1,177 960
Purchased product - - 3,540 2,909
Depreciation, depletion
and amortization 54 44 2,038 1,761
-------------------------------------------------------------------------
Segment Income (Loss) $(1,647) $ (897) 1,879 1,366
-------------------------------------------------------------------------
Administrative 205 136
Interest, net 419 284
Accretion of asset retirement
obligation 27 16
Foreign exchange gain (63) (213)
Stock-based compensation 12 14
Gain on divestitures - (35)
-------------------------------------------------------------------------
600 202
-------------------------------------------------------------------------
Net Earnings Before Income Tax 1,279 1,164
Income tax expense 352 141
-------------------------------------------------------------------------
Net Earnings From Continuing
Operations $ 927 $ 1,023
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(*) For the nine months ended September 30, the unrealized loss on risk
management is recorded in the Consolidated Statement of Earnings as
follows (see also Note 12):

2005 2004
-------------------------------------------------------------------------

Revenues, Net of Royalties - Corporate $(1,596) $ (859)
Operating Expenses and Other - Corporate (3) (4)
-------------------------------------------------------------------------
Total Unrealized Loss on Risk Management -
Continuing Operations $(1,593) $ (855)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Upstream Canada United States
---------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 4,747 $ 3,770 $ 2,071 $ 1,313
Expenses
Production and mineral taxes 75 61 216 155
Transportation and selling 256 277 134 93
Operating 599 505 148 80
Depreciation, depletion
and amortization 1,416 1,296 516 330
-------------------------------------------------------------------------
Segment Income $ 2,401 $ 1,631 $ 1,057 $ 655
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Other Total Upstream
---------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 195 $ 170 $ 7,013 $ 5,253
Expenses
Production and mineral taxes - - 291 216
Transportation and selling - - 390 370
Operating 189 155 936 740
Depreciation, depletion
and amortization 25 31 1,957 1,657
-------------------------------------------------------------------------
Segment Income (Loss) $ (19) $ (16) $ 3,439 $ 2,270
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Total Midstream
Midstream & Market Market & Market
Optimization Midstream Optimization Optimization
------------------------------------------------
2005 2004 2005 2004 2005 2004
-------------------------------------------------------------------------

Revenues $ 930 $ 881 $2,984 $2,325 $3,914 $3,206
Expenses
Transportation and
selling - - 16 20 16 20
Operating 204 192 40 32 244 224
Purchased product 630 655 2,910 2,254 3,540 2,909
Depreciation, depletion
and amortization 26 58 1 2 27 60
-------------------------------------------------------------------------
Segment Income (Loss) $ 70 $ (24) $ 17 $ 17 $ 87 $ (7)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Upstream Geographic and Product Information (Continuing Operations)
(For the nine months ended September 30)

Produced Gas Produced Gas
------------------------------------------------
Canada United States Total
------------------------------------------------
2005 2004 2005 2004 2005 2004
-------------------------------------------------------------------------

Revenues, Net of
Royalties $3,634 $2,887 $1,891 $1,198 $5,525 $4,085
Expenses
Production and
mineral taxes 56 46 198 142 254 188
Transportation and
selling 211 222 134 93 345 315
Operating 377 297 148 80 525 377
-------------------------------------------------------------------------
Operating Cash Flow $2,990 $2,322 $1,411 $ 883 $4,401 $3,205
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Oil & NGLs Oil & NGLs
------------------------------------------------
Canada United States Total
------------------------------------------------
2005 2004 2005 2004 2005 2004
-------------------------------------------------------------------------

Revenues, Net of
Royalties $1,113 $ 883 $ 180 $ 115 $1,293 $ 998
Expenses
Production and
mineral taxes 19 15 18 13 37 28
Transportation and
selling 45 55 - - 45 55
Operating 222 208 - - 222 208
-------------------------------------------------------------------------
Operating Cash Flow $ 827 $ 605 $ 162 $ 102 $ 989 $ 707
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Other & Total Upstream Other Total Upstream
---------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 195 $ 170 $ 7,013 $ 5,253
Expenses
Production and mineral taxes - - 291 216
Transportation and selling - - 390 370
Operating 189 155 936 740
-------------------------------------------------------------------------
Operating Cash Flow $ 6 $ 15 $ 5,396 $ 3,927
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Capital Expenditures (Continuing Operations)

Three Months Ended Nine Months Ended
September 30, September 30,
---------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------

Upstream
Canada $ 912 $ 634 $ 2,806 $ 2,337
United States 647 328 1,540 854
Other Countries 10 15 39 49
-------------------------------------------------------------------------
1,569 977 4,385 3,240
Midstream & Market Optimization 32 15 172 40
Corporate 34 10 49 28
-------------------------------------------------------------------------
Total $ 1,635 $ 1,002 $ 4,606 $ 3,308
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Property, Plant and Equipment and Total Assets

Property, Plant
and Equipment Total Assets
-------------------------------------------
As at As at
-------------------------------------------
September December September December
30, 2005 31, 2004 30, 2005 31, 2004
-------------------------------------------------------------------------

Upstream $ 22,670 $ 22,097 $ 27,640 $ 26,118
Midstream & Market Optimization 971 804 2,449 1,904
Corporate 250 239 1,279 1,412
Assets of Discontinued
Operations (Note 3) 1,983 1,779
-------------------------------------------------------------------------
Total $ 23,891 $ 23,140 $ 33,351 $ 31,213
-------------------------------------------------------------------------
-------------------------------------------------------------------------

3. DISCONTINUED OPERATIONS

Ecuador

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

In accordance with Canadian generally accepted accounting principles,
depletion, depreciation and amortization expense has not been recorded in
the Consolidated Statement of Earnings for discontinued operations.

On September 13, 2005, EnCana announced it had reached an agreement to
sell all its interest in its Ecuador properties for $1.42 billion, which
is approximately equivalent to the asset's net book value at July 1,
2005, the referenced effective date of the transaction. Net earnings for
the third quarter were $123 million. However, at September 30, 2005, a
provision of $123 million has been recorded against the net book value to
recognize management's best estimate of the difference between the
selling price and the September 30, 2005 underlying accounting value of
the related investments at the sales date, as required under Canadian
generally accepted accounting principles.

United Kingdom

On December 1, 2004, the Company completed the sale of its 100 percent
interest in EnCana (U.K.) Limited for net cash consideration of
approximately $2.1 billion. EnCana's U.K. operations included crude oil
and natural gas interests in the U.K. central North Sea including the
Buzzard, Scott and Telford oil fields, as well as other satellite
discoveries and exploration licenses. A gain on sale of approximately
$1.4 billion was recorded. Accordingly, these operations have been
accounted for as discontinued operations.

Consolidated Statement of Earnings

The following table presents the effect of the discontinued operations in
the Consolidated Statement of Earnings:

For the three months ended September 30,
------------------------------------------------
Ecuador United Kingdom Total
------------------------------------------------
2005 2004 2005 2004 2005 2004
-------------------------------------------------------------------------

Revenues, Net of
Royalties $ 291 $ 108 $ - $ 30 $ 291 $ 138
-------------------------------------------------------------------------

Expenses
Production and
mineral taxes 49 18 - - 49 18
Transportation and
selling 15 16 - 10 15 26
Operating 38 30 - 12 38 42
Depreciation, depletion
and amortization 123 63 - 26 123 89
Interest, net - - - (3) - (3)
Accretion of asset
retirement obligation - - - 1 - 1
Foreign exchange loss
(gain) (1) 1 - 1 (1) 2
-------------------------------------------------------------------------
224 128 - 47 224 175
-------------------------------------------------------------------------
Net Earnings (Loss)
Before Income Tax 67 (20) - (17) 67 (37)
Income tax expense
(recovery) 67 9 - (7) 67 2
-------------------------------------------------------------------------
Net Loss From Discontinued
Operations $ - $ (29) $ - $ (10) $ - $ (39)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


For the nine months ended September 30,
------------------------------------------------
Ecuador United Kingdom Total
------------------------------------------------
2005 2004 2005 2004 2005 2004
-------------------------------------------------------------------------

Revenues, Net of
Royalties(*) $ 723 $ 298 $ - $ 126 $ 723 $ 424
-------------------------------------------------------------------------

Expenses
Production and mineral
taxes 101 42 - - 101 42
Transportation and
selling 46 49 - 29 46 78
Operating 100 89 - 32 100 121
Depreciation, depletion
and amortization 123 197 - 93 123 290
Interest, net - (1) - (5) - (6)
Accretion of asset
retirement obligation 1 1 - 3 1 4
Foreign exchange
loss (gain) - 1 (3) 3 (3) 4
-------------------------------------------------------------------------
371 378 (3) 155 368 533
-------------------------------------------------------------------------
Net Earnings (Loss)
Before Income Tax 352 (80) 3 (29) 355 (109)
Income tax expense
(recovery) 221 (7) 1 (12) 222 (19)
-------------------------------------------------------------------------
Net Earnings (Loss) From
Discontinued Operations $ 131 $ (73) $ 2 $ (17) $ 133 $ (90)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(*) Revenues, net of royalties in Ecuador include $105 million of
realized losses (2004 - $171 million) and $50 million of unrealized
gains (2004 - $134 million of losses) related to derivative financial
instruments.

Consolidated Balance Sheet

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

As at
--------------------------------------------------------
September 30, 2005 December 31, 2004
--------------------------------------------------------
United United
Ecuador Kingdom Total Ecuador Kingdom Syncrude Total
-------------------------------------------------------------------------
Assets
Cash and cash
equivalents $ 123 $ 5 $ 128 $ 2 $ 12 $ - $ 14
Accounts
receivable and
accrued revenues 159 - 159 111 13 - 124
Risk management - - - 3 - - 3
Inventories 22 - 22 15 - - 15
-------------------------------------------------------------------------
304 5 309 131 25 - 156
Property, plant
and equipment,
net 1,317 - 1,317 1,295 - - 1,295
Investments and
other assets 357 - 357 328 - - 328
-------------------------------------------------------------------------
$1,978 $ 5 $1,983 $1,754 $ 25 $ - $1,779
-------------------------------------------------------------------------
Liabilities
Accounts payable
and accrued
liabilities $ 124 $ 29 $ 153 $ 61 $ 32 $ 3 $ 96
Income tax
payable 153 3 156 101 - - 101
Risk management 22 - 22 72 - - 72
-------------------------------------------------------------------------
299 32 331 234 32 3 269
Asset retirement
obligation 23 - 23 22 - - 22
Future income
taxes 153 1 154 80 11 - 91
-------------------------------------------------------------------------
475 33 508 336 43 3 382
-------------------------------------------------------------------------
Net Assets of
Discontinued
Operations $1,503 $ (28) $1,475 $1,418 $ (18) $ (3) $1,397
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Contingencies

In Ecuador, a subsidiary of EnCana has a 40 percent non-operated economic
interest in relation to Block 15 pursuant to a contract with a subsidiary
of Occidental Petroleum Corporation. In its 2004 filings with Securities
regulatory authorities, Occidental Petroleum Corporation indicated 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 filings, Occidental Petroleum Corporation indicated that it
believes it has complied with all material obligations under the
Participation Contract and that any termination of the Participation
Contract by Ecuador based upon these stated allegations would be
unfounded and would constitute an unlawful expropriation under
international treaties.

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

4. DIVESTITURES

Total proceeds received on sale of assets and investments was
$2,493 million (2004 - $1,359 million) as described below:

Upstream

In 2005, the Company has completed the disposition of mature conventional
oil and natural gas assets for proceeds of $440 million (2004 -
$1,358 million).

In May, the Company completed the sale of its Gulf of Mexico assets for
approximately $2.1 billion resulting in net proceeds of approximately
$1.5 billion after deducting $591 million in tax plus other adjustments.
In accordance with full cost accounting for oil and gas activities,
proceeds were credited to property, plant and equipment.

Other

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

5. FOREIGN EXCHANGE (GAIN)

Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------

Unrealized Foreign Exchange Gains
on Translation of U.S. Dollar
Debt Issued in Canada $ (205) $ (193) $ (140) $ (122)
Other Foreign Exchange (Gain) Loss (8) (97) 77 (91)
-------------------------------------------------------------------------
$ (213) $ (290) $ (63) $ (213)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

6. INCOME TAXES

The provision for income taxes is as follows:

Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------

Current
Canada $ 20 $ 103 $ 330 $ 505
United States 153 3 744 18
Other (4) (3) (6) (12)
-------------------------------------------------------------------------
Total Current Tax 169 103 1,068 511
-------------------------------------------------------------------------

Future (41) (28) (716) (261)
Future Tax Rate Reductions - - - (109)
-------------------------------------------------------------------------
Total Future Tax (41) (28) (716) (370)
-------------------------------------------------------------------------
$ 128 $ 75 $ 352 $ 141
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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,
--------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------

Net Earnings Before Income Tax $ 394 $ 507 $ 1,279 $ 1,164
Canadian Statutory Rate 37.9% 39.1% 37.9% 39.1%
-------------------------------------------------------------------------
Expected Income Tax 150 198 485 455

Effect on Taxes Resulting from:
Non-deductible Canadian crown
payments 53 51 139 154
Canadian resource allowance (51) (63) (141) (186)
Canadian resource allowance on
unrealized risk management losses 13 8 26 27
Statutory and other rate
differences (25) (17) (109) (47)
Effect of tax rate changes - - - (109)
Non-taxable capital gains (43) (55) (27) (41)
Previously unrecognized capital
losses (gains) - (5) - 10
Tax basis retained on dispositions - (59) (68) (162)
Large corporations tax 20 6 24 13
Other 11 11 23 27
-------------------------------------------------------------------------
$ 128 $ 75 $ 352 $ 141
-------------------------------------------------------------------------
Effective Tax Rate 32.5% 14.8% 27.5% 12.1%
-------------------------------------------------------------------------
-------------------------------------------------------------------------

7. LONG-TERM DEBT

As at As at
September 30, December 31,
2005 2004
-------------------------------------------------------------------------

Canadian Dollar Denominated Debt
Revolving credit and term loan borrowings $ 2,166 $ 1,515
Unsecured notes 797 1,309
-------------------------------------------------------------------------
2,963 2,824
-------------------------------------------------------------------------
U.S. Dollar Denominated Debt
Revolving credit and term loan borrowings 776 399
Unsecured notes and debentures 4,640 4,641
-------------------------------------------------------------------------
5,416 5,040
-------------------------------------------------------------------------
Increase in Value of Debt Acquired(*) 65 66
Current Portion of Long-Term Debt (219) (188)
-------------------------------------------------------------------------
$ 8,225 $ 7,742
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) Certain of the notes and debentures of EnCana 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.

During the third quarter, EnCana redeemed a number of unsecured notes
with a total principal of C$1,150 million. On September 21, 2005, EnCana
completed a public offering of unsecured notes in the aggregate principal
amount of C$500 million which bear interest at 3.60% and mature on
September 15, 2008.

8. 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,
2005 2004
-------------------------------------------------------------------------

Asset Retirement Obligation, Beginning of Year $ 611 $ 383
Liabilities Incurred 60 98
Liabilities Settled (29) (16)
Liabilities Disposed (23) (35)
Change in Estimated Future Cash Flows 4 124
Accretion Expense 27 22
Other 24 35
-------------------------------------------------------------------------
Asset Retirement Obligation, End of Period $ 674 $ 611
-------------------------------------------------------------------------
-------------------------------------------------------------------------

9. SHARE CAPITAL

September 30, 2005 December 31, 2004
---------------------------------------
(millions) Number Amount Number Amount
-------------------------------------------------------------------------

Common Shares Outstanding,
Beginning of Year 900.6 $ 5,299 921.2 $ 5,305
Shares Issued under Option Plans 13.9 270 19.4 281
Shares Repurchased (60.7) (462) (40.0) (287)
-------------------------------------------------------------------------
Common Shares Outstanding,
End of Period 853.8 $ 5,107 900.6 $ 5,299
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Information related to common shares and stock options has been restated
to reflect the effect of the common share split approved in April 2005.

Normal Course Issuer Bid

To September 30, 2005, the Company purchased 60,757,198 Common Shares for
total consideration of approximately $2,114 million. Of the amount paid,
$462 million was charged to Share capital, $10 million was charged to
Paid in surplus and $1,642 million was charged to Retained earnings.
Included in the above are 5.5 million Common Shares which have been
purchased by a wholly owned Trust and are held for issuance upon vesting
of units under EnCana's Performance Share Unit plan (see Note 10).

On October 26, 2004, the Company received regulatory approval for a new
Normal Course Issuer Bid commencing October 29, 2004. Under this bid, the
Company may purchase for cancellation up to 46,229,000 of its Common
Shares, representing five percent of the approximately 924.6 million
Common Shares outstanding as of the filing of the bid on October 22,
2004. On February 4, 2005, the Company received regulatory approval for
an amendment to the Normal Course Issuer Bid which increases the number
of shares available for purchase from five percent of the issued and
outstanding Common Shares to ten percent of the public float of Common
Shares (a total of approximately 92.2 million Common Shares). The current
Normal Course Issuer Bid expires on October 28, 2005.

Stock Options

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

The following tables summarize the information about options to purchase
Common Shares that do not have Tandem Share Appreciation Rights
("TSAR's") attached to them at September 30, 2005. Information related to
TSAR's is included in Note 10.

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

Outstanding, Beginning of Year 36.2 23.15
Exercised (13.9) 22.90
Forfeited (0.4) 21.22
-------------------------------------------------------------------------
Outstanding, End of Period 21.9 23.34
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Exercisable, End of Period 17.6 23.19
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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

10.00 to 22.99 1.9 2.4 15.87 1.7 15.24
23.00 to 23.50 1.5 0.9 23.17 1.4 23.16
23.51 to 23.99 7.1 2.5 23.89 3.7 23.89
24.00 to 24.49 10.8 1.5 24.18 10.6 24.18
24.51 to 25.99 0.6 2.8 25.25 0.2 25.31
-------------------------------------------------------------------------
21.9 1.9 23.34 17.6 23.19
-------------------------------------------------------------------------
-------------------------------------------------------------------------

EnCana 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 and 2005 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, 2005 would be unchanged (three months
ended 2004 - $384 million; $0.42 per common share - basic; $0.41 per
common share - diluted). Pro forma Net Earnings and Net Earnings per
Common Share for the nine months ended September 30, 2005 would be
unchanged (2004 - $906 million; $0.98 per common share - basic; $0.97 per
common share diluted).

10. COMPENSATION PLANS

The tables below outline certain information related to EnCana's
compensation plans at September 30, 2005. Additional information is
contained in Note 16 of the Company's annual audited Consolidated
Financial Statements for the year ended December 31, 2004.

A) Pensions

The following table summarizes the net benefit plan expense:

Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------

Current Service Cost $ 1 $ 1 $ 5 $ 4
Interest Cost 4 3 11 9
Expected Return on Plan Assets (3) (2) (10) (8)
Amortization of Net Actuarial Loss 1 1 3 3
Amortization of Transitional
Obligation (1) - (2) (1)
Amortization of Past Service Cost - - 1 1
Expense for Defined Contribution Plan 6 3 16 10
-------------------------------------------------------------------------
Net Benefit Plan Expense $ 8 $ 6 $ 24 $ 18
-------------------------------------------------------------------------
-------------------------------------------------------------------------

EnCana previously disclosed in its annual audited Consolidated Financial
Statements for the year ended December 31, 2004 that it expected to
contribute $6 million to its defined benefit pension plans in 2005. The
Company now anticipates that it will contribute $8 million to the defined
benefit pension plans in 2005. At September 30, 2005, contributions of
$8 million have been made.

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

The following table summarizes the information about SAR's at
September 30, 2005:
Weighted
Average
Outstanding Exercise
SAR's Price
-------------------------------------------------------------------------

Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 930,510 18.31
Exercised (662,847) 16.35
Forfeited (1,530) 23.14
-------------------------------------------------------------------------
Outstanding, End of Period 266,133 23.15
-------------------------------------------------------------------------
Exercisable, End of Period 266,133 23.15
-------------------------------------------------------------------------
-------------------------------------------------------------------------
U.S. Dollar Denominated (US$)
Outstanding, Beginning of Year 771,860 14.40
Exercised (419,589) 14.45
-------------------------------------------------------------------------
Outstanding, End of Period 352,271 14.34
-------------------------------------------------------------------------
Exercisable, End of Period 352,271 14.34
-------------------------------------------------------------------------
-------------------------------------------------------------------------

To September 30, EnCana recorded compensation costs of $19 million
related to the outstanding SAR's (2004 - $4 million).

C) Tandem Share Appreciation Rights ("TSAR's")

The following table summarizes the information about Tandem SAR's at
September 30, 2005:

Weighted
Average
Outstanding Exercise
TSAR's Price
-------------------------------------------------------------------------

Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 1,735,000 27.77
Granted 7,234,012 39.33
Exercised - SARs (136,285) 27.24
Exercised - Options (90,275) 27.26
Forfeited (379,230) 33.95
-------------------------------------------------------------------------
Outstanding, End of Period 8,363,222 37.50
-------------------------------------------------------------------------
Exercisable, End of Period 203,830 27.40
-------------------------------------------------------------------------
-------------------------------------------------------------------------

To September 30, EnCana recorded compensation costs of $86 million
related to the outstanding TSAR's (2004 - $1 million).

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

The following table summarizes the information about DSU's at
September 30, 2005:

Weighted
Average
Outstanding Exercise
DSU's Price
-------------------------------------------------------------------------

Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 750,612 24.81
Granted, Directors 78,827 43.54
Units, in Lieu of Dividends 3,806 52.26
-------------------------------------------------------------------------
Outstanding, End of Period 833,245 26.70
-------------------------------------------------------------------------
Exercisable, End of Period 833,245 26.70
-------------------------------------------------------------------------
-------------------------------------------------------------------------

To September 30, EnCana recorded compensation costs of $26 million
related to the outstanding DSU's (2004 - $6 million).

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

The following table summarizes the information about PSU's at
September 30, 2005:

Weighted
Average
Outstanding Grant
PSU's Price
-------------------------------------------------------------------------

Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 3,294,206 26.71
Granted 1,726,292 38.16
Forfeited (270,008) 30.63
-------------------------------------------------------------------------
Outstanding, End of Period 4,750,490 30.64
-------------------------------------------------------------------------
Exercisable, End of Period - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
U.S. Dollar Denominated (US$)
Outstanding, Beginning of Year 449,230 20.56
Granted 388,928 30.94
Forfeited (56,602) 27.82
-------------------------------------------------------------------------
Outstanding, End of Period 781,556 25.20
-------------------------------------------------------------------------
Exercisable, End of Period - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------

To September 30, EnCana recorded compensation costs of $57 million
related to the outstanding PSU's (2004 - $17 million).

At September 30, 2005, EnCana has approximately 5.5 million Common Shares
held in trust for issuance upon vesting of the PSU's.

11. PER SHARE AMOUNTS

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

Nine Months
Three Months Ended Ended
--------------------------------------------------
March 31, June 30, September 30, September 30,
--------------------------------------------------
(millions) 2005 2005 2005 2004 2005 2004
-------------------------------------------------------------------------

Weighted Average Common
Shares Outstanding -
Basic 891.8 872.0 855.1 923.4 872.9 922.0
Effect of Dilutive
Securities 17.2 19.9 20.7 9.0 21.3 12.2
-------------------------------------------------------------------------
Weighted Average Common
Shares Outstanding -
Diluted 909.0 891.9 875.8 932.4 894.2 934.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------

The amounts above have been restated to reflect the effect of the common
share split approved in April 2005.

12. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

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

Realized and Unrealized (Loss) Gain on Risk Management Activities

The following tables summarize the gains and losses on risk management
activities:

Realized
--------------------------------------
Q1 Q2 Q3 YTD
-------------------------------------------------------------------------

Revenues, Net of Royalites $ (20) $ (114) $ (201) $ (335)
Operating Expenses and Other 5 5 7 17
-------------------------------------------------------------------------
Total Loss on Risk Management -
Continuing Operations (15) (109) (194) (318)
Loss on Risk Management -
Discontinued Operations (23) (32) (50) (105)
-------------------------------------------------------------------------
$ (38) $ (141) $ (244) $ (423)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Unrealized
--------------------------------------
Q1 Q2 Q3 YTD
-------------------------------------------------------------------------

Revenues, Net of Royalites $ (972) $ 315 $ (939) $(1,596)
Operating Expenses and Other 3 (1) 1 3
-------------------------------------------------------------------------
Total (Loss) Gain on Risk Management
- Continuing Operations (969) 314 (938) (1,593)
(Loss) Gain on Risk Management -
Discontinued Operations (20) 31 39 50
-------------------------------------------------------------------------
$ (989) $ 345 $ (899) $(1,543)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Amounts Recognized on Transition

As discussed in Note 2 to the annual audited Consolidated Financial
Statements for the year ended December 31, 2004, on January 1, 2004, the
fair value of all outstanding financial instruments that were not
considered accounting hedges was recorded in the Consolidated Balance
Sheet with an offsetting net deferred loss amount (the "transition
amount"). The transition amount is recognized into net earnings over the
life of the related contracts. Changes in fair value after that time are
recorded in the Consolidated Balance Sheet with an 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.

At September 30, 2005, a net unrealized gain remains to be recognized
over the next four years as follows:

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

2005
Three months ended December 31, 2005 $ 10
-------------------------------------------------------------------------
Total remaining to be recognized in 2005 $ 10
-------------------------------------------------------------------------
2006 $ 24
2007 15
2008 1
-------------------------------------------------------------------------
Total to be recognized in 2006 through to 2008 $ 40
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total to be recognized $ 50
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total to be recognized - Continuing Operations $ 50
Total to be recognized - Discontinued Operations -
-------------------------------------------------------------------------
$ 50
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Fair Value of Outstanding Risk Management Positions

The following table presents a reconciliation of the change in the
unrealized amounts from January 1, 2005 to September 30, 2005:

Total
Transition Fair Market Unrealized
Amounts Value Gain (Loss)
-------------------------------------------------------------------------

Fair Value of Contracts, Beginning
of Year $ (72) $ (189)
Change in Fair Value of Contracts in
Place at Beginning of Year - (1,112) $ (1,112)
Fair Value of Contracts in Place at
Transition Realized in 2005 22 (22) -
Fair Value of Contracts Entered into
Since Beginning of Year - (431) (431)
-------------------------------------------------------------------------
Fair Value of Contracts Outstanding $ (50) $ (1,754) $ (1,543)
-------------------------------------------------------------------------
Unamortized Premiums Paid on Collars
and Options 224
-------------------------------------------------------------------------
Fair Value of Contracts Outstanding
and Premiums Paid, End of Period $ (1,530)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Amounts Allocated to Continuing
Operations $ (50) $ (1,508) $ (1,593)
Amounts Allocated to Discontinued
Operations - (22) 50
-------------------------------------------------------------------------
$ (50) $ (1,530) $ (1,543)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

At September 30, 2005, the net deferred amounts recognized on transition
and the risk management amounts are recorded in the Consolidated Balance
Sheet as follows:
As at
September 30,
2005
-------------------------------------------------------------------------

Remaining Deferred Amounts Recognized on Transition
Accounts receivable and accrued revenues $ 1
Investments and other assets 1

Accounts payable and accrued liabilities 29
Other liabilities 23
-------------------------------------------------------------------------
Net Deferred Gain - Continuing Operations 50
Net Deferred Loss - Discontinued Operations -
-------------------------------------------------------------------------
$ 50
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Risk Management
Current asset $ 432
Long-term asset 316

Current liability 1,948
Long-term liability 308
-------------------------------------------------------------------------
Net Risk Management Liability - Continuing Operations (1,508)
Net Risk Management Liability - Discontinued Operations (22)
-------------------------------------------------------------------------
$ (1,530)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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

As at
September 30,
2005
-------------------------------------------------------------------------

Commodity Price Risk
Natural gas $ (1,412)
Crude oil (117)
Power 4
Interest Rate Risk 17
-------------------------------------------------------------------------
Total Fair Value Positions - Continuing Operations (1,508)
Total Fair Value Positions - Discontinued Operations (22)
-------------------------------------------------------------------------
$ (1,530)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Information with respect to power and interest rate risk contracts in
place at December 31, 2004 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, 2005.

Natural Gas

At September 30, 2005, the Company's gas risk management activities from
financial contracts had an unrealized loss of $1,544 million and a fair
market value position of $(1,412) million. The contracts were as follows:

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

Sales Contracts
Fixed Price Contracts
NYMEX Fixed Price 802 2005 6.74 US$/Mcf $ (533)
Colorado Interstate Gas
(CIG) 114 2005 4.87 US$/Mcf (63)
Other 110 2005 5.21 US$/Mcf (64)
NYMEX Fixed Price 525 2006 5.65 US$/Mcf (1,125)
Colorado Interstate Gas
(CIG) 100 2006 4.44 US$/Mcf (194)
Houston Ship Channel
(HSC) 90 2006 5.08 US$/Mcf (185)
Rockies 35 2006 4.45 US$/Mcf (69)
Waha 30 2006 4.79 US$/Mcf (62)
San Juan 16 2006 4.50 US$/Mcf (32)
NYMEX Fixed Price 240 2007 7.76 US$/Mcf (166)

Collars and Other Options
Purchased NYMEX Put
Options 1,062 2005 5.66 US$/Mcf (24)

5.00/6.69/
NYMEX 3-Way Call Spread 180 2005 7.69 US$/Mcf (19)
Purchased NYMEX Put
Options 987 2006 6.69 US$/Mcf (61)
Purchased NYMEX Put
Options 240 2007 6.00 US$/Mcf (4)

Basis Contracts
Fixed NYMEX to AECO
Basis 908 2005 (0.67) US$/Mcf 182
Fixed NYMEX to Rockies
Basis 263 2005 (0.49) US$/Mcf 62
Fixed NYMEX to CIG Basis 185 2005 (0.81) US$/Mcf 36
Other 267 2005 (0.35) US$/Mcf 43

Fixed NYMEX to AECO
Basis 759 2006 (0.67) US$/Mcf 186
Fixed NYMEX to Rockies
Basis 324 2006 (0.58) US$/Mcf 120
Fixed NYMEX to CIG Basis 301 2006 (0.83) US$/Mcf 99
Other 182 2006 (0.36) US$/Mcf 37

Fixed Rockies to CIG
Basis 12 2007 (0.10) US$/Mcf -
Fixed NYMEX to AECO
Basis 401 2007-2008 (0.69) US$/Mcf 88
Fixed NYMEX to Rockies
Basis 350 2007-2008 (0.63) US$/Mcf 188
Fixed NYMEX to CIG Basis 157 2007-2009 (0.75) US$/Mcf 120

Purchase Contracts
Fixed Price Contracts
Waha Purchase 27 2005 5.90 US$/Mcf 14
Waha Purchase 23 2006 5.32 US$/Mcf 43

Basis Contracts
Fixed NYMEX to Ventura 29 2005 (0.99) US$/Mcf (5)

-------------------------------------------------------------------------
(1,388)
Other Financial Positions(*) (156)
-------------------------------------------------------------------------
Total Unrealized Loss on
Financial Contracts (1,544)
Unamortized Premiums Paid
on Options 132
-------------------------------------------------------------------------
Total Fair Value Positions $ (1,412)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) Other financial positions are part of the ongoing operations of the
Company's proprietary production management and gas storage
optimization activities.

Crude Oil

At September 30, 2005, the Company's oil risk management activities from
financial contracts had an unrealized loss of $231 million and a fair
market value position of $(139) million. The contracts were as follows:

Notional
Volumes Average Price Fair Market
(bbl/d) Term (US$/bbl) Value
-------------------------------------------------------------------------

Fixed WTI NYMEX Price 37,000 2005 28.40 $ (128)
Costless 3-Way Put Spread 9,000 2005 20.00/25.00/28.78 (31)
Unwind WTI NYMEX Fixed
Price (7,200) 2005 42.70 16
Purchased WTI NYMEX Call
Options (38,000) 2005 49.76 55
Purchased WTI NYMEX Put
Options 35,000 2005 40.00 (6)

Fixed WTI NYMEX Price 15,000 2006 34.56 (171)
Unwind WTI NYMEX Fixed
Price (1,300) 2006 52.75 6
Purchased WTI NYMEX Call
Options (13,700) 2006 61.24 32
Purchased WTI NYMEX Put
Options 57,000 2006 50.00 (3)

Purchased WTI NYMEX Put
Options 43,000 2007 44.44 (4)
-------------------------------------------------------------------------
(234)
Other Financial
Positions(*) 3
-------------------------------------------------------------------------
Total Unrealized Loss on
Financial Contracts (231)
Unamortized Premiums
Paid on Options 92
-------------------------------------------------------------------------
Total Fair Value
Positions $ (139)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total Fair Value Positions
- Continuing Operations $ (117)
Total Fair Value Positions
- Discontinued Operations (22)
-------------------------------------------------------------------------
$ (139)
-------------------------------------------------------------------------
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(*) Other financial positions are part of the ongoing operations of the
Company's proprietary production management.

13. RECLASSIFICATION

Certain information provided for prior periods has been reclassified to
conform to the presentation adopted in 2005.

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

For further information:

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

Paul Gagne
Manager, Investor Relations
403-645-4737

Ryder McRitchie
Manager, Investor Relations
403-645-2007

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