EnCana's third quarter cash flow reaches US$1.9 billion, or $2.30 per share - up 5 percent

Natural gas sales increase 4 percent to 3.36 billion cubic feet per day

CALGARY, Oct. 25 /CNW/ - EnCana Corporation (TSX & NYSE: ECA) continued
to generate solid cash flow and earnings during the third quarter of 2006 due
to increased heavy oil prices plus steady natural gas production that
benefited from favourable natural gas price hedges and fixed basis positions.

Third quarter 2006 highlights
-----------------------------
(all year-over-year comparisons are to the third quarter of 2005)

Financial
(all currency figures are in U.S. dollars unless otherwise noted)
- Cash flow of US$2.30 per share diluted, or $1.89 billion
- Operating earnings of $1.31 per share diluted, or $1.08 billion
- Net earnings of $1.65 per share diluted, or $1.36 billion
- Both net earnings and operating earnings include a $255 million
after-tax gain, (31 cents per share diluted) on the sale of
EnCana's interest in an offshore Brazil oil discovery
- Net earnings also include an unrealized $285 million after-tax
gain, (34 cents per share diluted) due to mark-to-market
accounting of commodity price hedges
- Purchased 17.4 million EnCana shares at an average price of
$51.95 under the Normal Course Issuer Bid
- Price risk management measures resulted in a realized after-tax
gain of $133 million

Operational (continuing operations),
(all sales are on an after-royalties basis)
- Natural gas sales increased 4 percent to 3.36 billion cubic feet
per day (Bcf/d)
- Oil and natural gas liquids (NGLs) sales were about the same at
150,565 barrels per day (bbls/d)
- Natural gas and liquids sales of 4.26 billion cubic feet of gas
equivalent per day (Bcfe/d), up 3 percent
- Key resource play production up 12 percent
- Operating and administrative costs of 98 cents per thousand cubic
feet equivalent (Mcfe), compared to 90 cents per Mcfe one year
earlier
- Drilled 1,001 net wells, compared to 1,150 net wells one year
earlier
- Upstream core capital investment of $1.45 billion, which is as
forecast

Strategic events
- On October 5, 2006, EnCana announced it entered into an agreement
with ConocoPhillips to create an integrated North American heavy
oil business consisting of EnCana's Foster Creek and Christina
Lake in-situ oilsands projects in Alberta and ConocoPhillips' Wood
River and Borger refineries in Illinois and Texas respectively.
Effective January 2, 2007, it is expected that EnCana will become
an integrated producer, owning a 50 percent interest in the
integrated business
- Completed the sale of a 50 percent interest in the Chinook oil
discovery offshore Brazil for proceeds of $367 million
- Filed a project description with regulatory authorities for Deep
Panuke natural gas project located offshore Nova Scotia
- In northeast B.C., started up Kakwa gas plant and, in October,
began commissioning the Steeprock gas plant
- Began commissioning latest in-situ oilsands expansion at Foster
Creek

"During the first nine months of 2006, our cash flow per share is up
16 percent compared to one year earlier and operating earnings continue to
grow. Our resource play strategy is continuing to deliver strong performance
toward our core goal - steadily increasing the underlying value of every
EnCana share," said Randy Eresman, EnCana's President & Chief Executive
Officer. "Although we have slowed our natural gas production growth profile
from our original plan, we have achieved year-to-date growth of 5 percent. Our
current production is about 3.4 billion cubic feet per day and with the
planned start up in early November of the new Steeprock gas plant in British
Columbia our gas production should approach 3.5 billion cubic feet per day."
"At a time of commodity price uncertainty and high industry inflation, we
believe it is prudent to temporarily reduce our growth objectives and return
excess cash to shareholders through continued share buybacks rather than
pursue growth at elevated costs. Robust activity in the North American natural
gas industry this year has continued to fuel cost inflation for field
services, while record gas storage levels have resulted in softer realized
prices. In some areas experiencing high inflation and operational
inefficiencies, we have reduced our activity levels by releasing our least
capital efficient rigs and the associated services. This has resulted in
delays in bringing on new production. The released rigs will be replaced by
new fit-for-purpose rigs, which are about 25 percent more efficient, resulting
in an overall high-grading of our fleet. In total we have about 70 rigs
running, which is 55 fewer than one year ago. The number of wells we expect to
drill this year is now forecast to reach about 3,650, about 650 less than
initially forecast," Eresman said.

Jonah production constrained, wet conditions persist in southern Alberta
At Jonah in Wyoming, production growth is about 50 million cubic feet per
day less than forecast due to a combination of operational issues and pipeline
capacity restrictions. This volume represents the largest proportion of our
company's production shortfall. Operational issues are being resolved and
additional gathering pipeline capacity is expected to be added by the second
quarter of 2007. EnCana has slowed drilling to help preserve the value of new
gas production by timing production increases with planned pipeline expansion.
EnCana has reduced its Jonah drilling fleet from 15 to 11 rigs by releasing
four of its least-efficient rigs while it awaits delivery of eight new, highly-
efficient, fit-for-purpose rigs over the next year. In the plains of southern
Alberta, operations in coalbed methane and shallow gas development were slowed
by wet summer weather. Unusually-heavy rains in 2005 left the land saturated
such that even modest rains this year hampered field work.

Natural gas sales guidance updated
With fewer wells and a slower than forecast production ramp up from the
Jonah and southern Alberta projects, 2006 gas production is running slightly
below the low end of the company's previous forecast. EnCana has updated its
2006 natural gas sales guidance to between 3.36 billion and 3.40 billion cubic
feet per day, representing, at the midpoint, a 5 percent increase over 2005
sales. The forecast for oil and NGLs sales is unchanged at between 155,000 and
160,000 bbls/d. Updated guidance is posted on EnCana's website:
www.encana.com.
"In the third quarter, growth from our key resource plays continued at a
strong pace, up 12 percent in the past year. In the first nine months, key
resource play growth is up about 14 percent," Eresman said. "Despite higher
inflation and foreign exchange rates, we are stewarding our 2006 capital
investment to be within guidance of between $5.8 billion and $6.1 billion,
which includes about $600 million directed to growth at our Foster Creek and
Christina Lake oilsands projects."

Higher electricity costs offset by EnCana power plants
While increased electricity prices in Alberta have driven up field
operating costs in recent months, the company has a natural hedge due to its
ownership in three cogeneration power plants. Although power prices increased
third quarter operating costs by about 4 cents per Mcfe compared to the same
period in 2005, increased revenue from the company's power plants has offset
this cost increase.

Focused on generating strong investment returns and free cash flow
"As we look to 2007, we recognize that winter weather will play a strong
role in determining 2007 gas prices and we share investors' concerns for
potential price weakness in the short term. At the same time, energy demand
and the forward prices for natural gas and oil remain strong. We continue to
manage price risk with the use of hedging instruments and we do not plan to
aggressively push new production into a high-cost, low-price environment,"
Eresman said.
"We plan to set our 2007 capital budget in mid December when we will have
a better sense of the environment for the coming year and consistent with
2006, we will target a significant stream of free cash flow for 2007," Eresman
said. "We have hedged about one-third of our expected 2007 gas production:
fixed price contracts on about 975 million cubic feet per day at an average
price of $8.73 per Mcf and put options on 240 million cubic feet per day at a
strike price of $6.00 per Mcf. For 2007, we plan to be even more focused on
maximizing shareholder returns by optimizing capital investment complemented
with a sizable divestiture program and continued farm out activity on lands
not core to EnCana."

EnCana and ConocoPhillips to create integrated heavy oil business in 2007
On October 5, 2006, EnCana announced the signing of a landmark agreement
with ConocoPhillips that will see EnCana become an integrated oil producer,
holding a 50 percent interest in two significant U.S. refineries. The two
companies agreed to create two 50/50 partnerships, one upstream in Canada and
one downstream in the United States. This integrated heavy oil business plans
to increase production from two in-situ oilsands projects to about
400,000 bbls/d of bitumen over the next decade and expand processing capacity
to 275,000 bbls/d for bitumen at refineries in Wood River, Illinois and
Borger, Texas. This transaction, which is subject to the execution of final
definitive agreements and regulatory approvals, is expected to close on
January 2, 2007.
"Under the agreement, EnCana will own about 175,000 bbls/d of refining
capacity effective January 2, 2007, increasing to about 250,000 bbls/d by
2009, in key U.S. markets. This will instantly place EnCana among Canada's
major refinery owners while providing options for future upgrader
development," Eresman said. "These innovative partnerships will strategically
align about two-thirds of our industry-leading oilsands projects with high-
quality refineries. Through this integrated business, we expect to increase
certainty of execution for our oilsands projects by reducing cost and price
risk and increasing confidence in our ability to achieve economic returns
under a wide range of world oil prices."

Bitumen production expansions underway at Foster Creek and Christina Lake
Over the next decade, the upstream partnership plans to invest
$5.4 billion to grow bitumen production capacity at Foster Creek and Christina
Lake from 50,000 bbls/d to approximately 400,000 bbls/d. A Foster Creek
expansion currently under construction is expected to take production to about
60,000 bbls/d by early 2007. The next two Foster Creek expansions,
30,000 bbls/d each, are expected to come on stream in late 2008 and 2009
respectively. At Christina Lake, the current expansion is expected to take
production to about 18,000 bbls/d in the last half of 2008, which means these
near term expansions are expected to take total production to about
138,000 bbls/d before 2010. Subsequent expansions at the two projects are
expected to continue growth to the targeted level of 400,000 bbls/d.

IMPORTANT NOTE: EnCana reports in U.S. dollars unless otherwise noted and
follows U.S. protocols, which report sales and reserves on an after-
royalties basis. EnCana's Ecuador interests and its natural gas liquids
processing business were sold and are discontinued. The company is
reporting its natural gas storage business as discontinued because EnCana
is in the process of selling it. Total results, which include results
from natural gas liquids processing business, Ecuador and natural gas
storage, are reported in the company's financial statements included in
this news release and in supplementary documents posted on its website -
www.encana.com. The company's financial statements are prepared in
accordance with Canadian generally accepted accounting principles (GAAP).

First nine months of 2006 highlights
------------------------------------
(all year-over-year comparisons are to the first nine months of 2005)

Financial
- Cash flow per share diluted increased 16 percent to $6.39, or
$5.4 billion
- Operating earnings per share increased 40 percent to $3.07, or
$2.6 billion
- Net earnings of $5 billion, or $5.90 per share, compared to
$1.19 per share one year earlier
- Return on capital employed of 32 percent, based on the trailing
12 months
- Since December 31, 2005, purchased for cancellation 7.1 percent of
the common shares then outstanding, resulting in a 6.4 percent
decrease, net of dilution due to option exercises.

Operational (continuing operations)
- Key resource play production up 14 percent
- Natural gas sales of 3.35 Bcf/d, up 5 percent
- Oil and NGLs sales about the same at 155,565 bbls/d
- Natural gas and liquids sales increased 4 percent to 4.29 Bcfe/d
- Operating and administrative costs of 98 cents per Mcfe, compared
to 84 cents per Mcfe one year earlier
- Drilled 2,841 net wells, compared to 3,520 net wells one year
earlier
- Upstream core capital investment of $4.96 billion, which is as
forecast

<<
-------------------------------------------------------------------------
Financial Summary - Total Consolidated
-------------------------------------------------------------------------
(for the period ended
September 30) 9 9
($ millions, except per Q3 Q3 % months months %
share amounts) 2006 2005 change 2006 2005 change
-------------------------------------------------------------------------
Cash flow 1,894 1,931 - 2 5,400 4,916 + 10
Per share diluted 2.30 2.20 + 5 6.39 5.50 + 16
-------------------------------------------------------------------------
Net earnings 1,358 266 n/a 4,989 1,060 n/a
Per share diluted 1.65 0.30 n/a 5.90 1.19 n/a
-------------------------------------------------------------------------
Operating earnings 1,078 704 + 53 2,596 1,970 + 32
Per share diluted 1.31 0.80 + 64 3.07 2.20 + 40
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings Reconciliation Summary - Total Consolidated
-------------------------------------------------------------------------
Net earnings from
continuing operations 1,343 348 n/a 4,408 960 n/a
Net earnings (loss) from
discontinued operations 15 (82) n/a 581 100 n/a
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net earnings 1,358 266 n/a 4,989 1,060 n/a
(Add back losses &
deduct gains)
Unrealized mark-to-market
hedging gain (loss),
after-tax 285 (604) n/a 1,275 (1,023) n/a

Unrealized foreign
exchange gain (loss)
on translation
of U.S. dollar debt
issued in Canada,
after-tax (3) 166 n/a 128 113 n/a

Future tax recovery due
to Canada and Alberta tax
rates reductions - - n/a 457 - n/a

Gain (loss) on sale of
discontinued operations,
(1) after-tax (2) - n/a 533 - n/a
-------------------------------------------------------------------------
Operating earnings 1,078 704 + 53 2,596 1,970 + 32
Per share diluted 1.31 0.80 + 64 3.07 2.20 + 40
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Year to date includes $812 million gain on natural gas storage sale
and $279 million loss on sale of Ecuador interests

-------------------------------------------------------------------------
Sales & Drilling Summary
-------------------------------------------------------------------------
Total Consolidated
-------------------------------------------------------------------------
(for the period ended
September 30) 9 9
(After royalties) Q3 Q3 % months months %
2006 2005 change 2006 2005 change
-------------------------------------------------------------------------
Natural Gas sales
(MMcf/d) 3,359 3,222 + 4 3,354 3,193 + 5
-------------------------------------------------------------------------
Natural gas sales per
1,000 shares (Mcf) 382 347 + 10 1,104 999 + 11
-------------------------------------------------------------------------
Oil and NGLs sales
(bbls/d)(2) 150,565 219,167 - 31 172,098 226,335 - 24
-------------------------------------------------------------------------
Oil and NGLs sales
per 1,000 shares
(Mcfe)(2) 103 141 - 27 340 425 - 20
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total sales
(MMcfe/d)(2) 4,262 4,537 - 6 4,387 4,551 - 4
-------------------------------------------------------------------------
Total sales per
1,000 shares (Mcfe)(2) 484 488 - 1 1,445 1,423 + 2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net wells drilled 1,001 1,152 - 13 2,848 3,531 - 19
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Continuing Operations
-------------------------------------------------------------------------
North America Natural
Gas sales (MMcf/d) 3,359 3,222 + 4 3,354 3,193 + 5
-------------------------------------------------------------------------
North America Oil and
NGLs (bbls/d) 150,565 150,457 0 155,565 154,892 0
-------------------------------------------------------------------------
Total sales (MMcfe/d) 4,262 4,125 + 3 4,287 4,122 + 4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net wells drilled 1,001 1,150 - 13 2,841 3,520 - 19
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(2) Sales down due primarily to sale of Ecuador interests, which had
sales of about 71,400 bbls/d in the first nine months of 2005

Key resource play production up 12 percent in past year
Third quarter 2006 oil and gas production from key North American
resource plays increased 12 percent compared to the third quarter of 2005.
This was driven mainly by increases in gas production from coalbed methane
projects in central and southern Alberta, Bighorn in west-central Alberta,
Cutbank Ridge in northeast British Columbia, Piceance in Colorado and the
Barnett Shale play in the Fort Worth basin.


Growth from key North American resource plays
-------------------------------------------------------------------------
Daily Production
----------------------------
Resource Play 2006
----------------------------
(After royalties) YTD Q3 Q2 Q1
-------------------------------------------------------------------------
Natural Gas (MMcf/d)
Jonah 455 455 450 461
Piceance 324 331 324 316
East Texas 100 106 93 99
Fort Worth 102 104 108 93
Greater Sierra 214 209 224 208
Cutbank Ridge 160 167 173 140
Bighorn 88 97 95 72
CBM Integrated(1) 189 209 179 177
Shallow Gas 599 593 590 615
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Oil (Mbbls/d)
Foster Creek 36 37 33 36
Christina Lake 6 6 6 6
Pelican Lake 25 23 22 29
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total (MMcfe/d) 2,628 2,668 2,601 2,609
-------------------------------------------------------------------------
% change from Q3 2005 14.4 12.1
-------------------------------------------------------------------------
% change from prior period 2.6 (0.3) 1.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------


-------------------------------------------------------------------------
Daily Production
-----------------------------------------
Resource Play 2005 2004
-----------------------------------------
Full Full
(After royalties) Year Q4 Q3 Q2 Q1 Year
-------------------------------------------------------------------------
Natural Gas (MMcf/d)
Jonah 435 454 440 416 431 389
Piceance 307 326 302 302 300 261
East Texas 90 98 94 85 82 50
Fort Worth 70 88 66 63 61 27
Greater Sierra 219 226 225 228 195 230
Cutbank Ridge 92 125 105 80 56 40
Bighorn 55 56 57 53 56 42
CBM Integrated(1) 112 165 117 104 59 28
Shallow Gas 625 625 616 633 625 592
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Oil (Mbbls/d)
Foster Creek 29 35 27 24 30 29
Christina Lake 5 5 6 7 4 4
Pelican Lake 26 28 27 27 21 19
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total (MMcfe/d) 2,366 2,567 2,381 2,312 2,197 1,971
-------------------------------------------------------------------------
% change from Q3 2005
-------------------------------------------------------------------------
% change from prior period 20.0 7.8 3.0 5.2 8.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Starting this quarter, CBM production from wells drilled as part of
the CBM program includes production from coal and other formations,
which reflects commingling rulings from regulators and is consistent
with the method used to report production for EnCana's other resource
plays. Volumes for all periods have been adjusted to comply with this
categorization.



Drilling activity in key North American resource plays
-------------------------------------------------------------------------
Net Wells Drilled
---------------------------
Resource Play 2006
---------------------------
YTD Q3 Q2 Q1
-------------------------------------------------------------------------
Natural Gas
Jonah 122 48 48 26
Piceance 170 48 59 63
East Texas 48 12 17 19
Fort Worth 78 22 27 29
Greater Sierra 110 16 34 60
Cutbank Ridge 97 35 36 26
Bighorn 45 7 18 20
CBM Integrated(1) 572 156 35 381
Shallow Gas 838 442 199 197
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Oil
Foster Creek 6 - - 6
Christina Lake 2 - - 2
Pelican Lake - - - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total 2,088 786 473 829
-------------------------------------------------------------------------
-------------------------------------------------------------------------


-------------------------------------------------------------------------
Resource Play Net Wells Drilled
-----------------------------------------
2005 2004
-----------------------------------------
Full Full
year Q4 Q3 Q2 Q1 Year
-------------------------------------------------------------------------
Natural Gas
Jonah 104 21 25 30 28 70
Piceance 266 55 69 65 77 250
East Texas 84 20 21 22 21 50
Fort Worth 59 20 18 12 9 36
Greater Sierra 164 25 33 47 59 187
Cutbank Ridge 135 34 40 38 23 50
Bighorn 51 20 10 10 11 20
CBM Integrated(1) 1,245 344 314 242 345 1,086
Shallow Gas 1,267 288 341 365 273 1,552
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Oil
Foster Creek 39 13 14 2 10 11
Christina Lake - - - - - 2
Pelican Lake 52 - 3 33 16 92
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total 3,466 840 888 866 872 3,406
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Third quarter realized natural gas prices, including hedging,
down 5 percent
EnCana's third quarter realized gas price, including the impact of
financial hedging, averaged $6.57 per thousand cubic feet (Mcf), down 5
percent from the comparable price of $6.90 per Mcf in the third quarter of
2005. EnCana's natural gas prices, excluding financial hedging, averaged $5.75
per Mcf, down 21 percent from an average of $7.29 per Mcf in the third quarter
of 2005. North American gas storage levels remain well above long- term
averages for this time of year, a market condition that is expected to put
downward pressure on short-term gas prices. The third quarter benchmark NYMEX
index gas price averaged $6.58 per Mcf, down 22 percent from $8.49 per Mcf in
the third quarter of 2005. The third quarter Canadian benchmark gas price was
down 26 percent to C$6.03 per Mcf while U.S. Rockies benchmark gas prices were
21 percent lower to $5.30 per Mcf, compared to last year.

About 1.2 Bcf/d of expected 2007 gas sales hedged, as of
September 30, 2006
EnCana has entered into financial contracts, put options and fixed price
agreements, for 93 percent of the company's forecast gas sales during the last
quarter of 2006 at an average minimum price of NYMEX $7.28 per Mcf. For 2007,
the company has 975 million cubic feet per day of expected 2007 gas sales
under fixed price contracts at an average price of $8.73 per Mcf and has put
options with a strike price of $6.00 per Mcf on an additional 240 million
cubic feet per day. This gas price hedging strategy helps assure that cash
flow is adequate to fund capital programs.

Managing transportation risk to gas prices
Natural gas transportation constraints between producing regions in the
U.S. Rockies and Western Canada and consuming regions increase the volatility
in gas prices. To help add further certainty of cash flow, EnCana has entered
into basis hedges to reduce this volatility. For the remainder of 2006, EnCana
has hedged 100 percent of its anticipated U.S. Rockies basis differential
exposure at an average of 64 cents per Mcf. For 2007, EnCana has 100 percent
of expected U.S. Rockies basis differential exposure hedged at an average of
67 cents per Mcf. In Canada for 2006, EnCana has hedged about 34 percent of
its anticipated AECO basis differential exposure at an average of 70 cents per
Mcf and has an additional 39 percent of anticipated production subject to
transport and aggregator contracts. For 2007 in Canada, EnCana has hedged
about 30 percent of its anticipated AECO basis differential exposure at an
average of 72 cents per Mcf and has an additional 37 percent of anticipated
production subject to transport and aggregator contracts.

Third quarter realized liquids prices, including hedging, up 16 percent
During the third quarter of 2006, higher prices for West Texas
Intermediate (WTI) oil, increased market reach via new pipelines to the
southern U.S. refining region and strong asphalt demand during the summer
paving season resulted in substantially higher prices for Canadian heavy oil
than in the prior year. Third quarter realized liquids prices, including
financial hedging, increased 16 percent to average $46.92 per barrel, compared
to $40.46 per barrel in the same period in 2005. Excluding financial hedging,
realized liquids prices increased 9 percent averaging $50.37 per barrel. In
the third quarter, the WTI/Western Canada Select differential averaged $18.83
per barrel, up 4 percent from $18.07 per barrel in the same 2005 period.
Concerns over geopolitical events and U.S. gasoline supplies combined to
propel the WTI oil price to more than $70 per barrel for most of the third
quarter. During the third quarter of 2006, the benchmark WTI crude oil price
averaged $70.54 per barrel, up 11 percent from the third quarter 2005 price of
$63.31 per barrel.

Risk management strategy
Detailed risk management positions at September 30, 2006 are presented in
Note 14 to the unaudited third quarter consolidated financial statements. In
the third quarter of 2006, EnCana's financial price risk management measures
resulted in a realized after-tax gain of approximately $133 million, comprised
of a $167 million gain on gas hedges, a $35 million loss on crude oil hedges
and a $1 million gain on other hedges.

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

Quarterly dividend of 10 cents per share approved
EnCana's board of directors has approved a quarterly dividend of 10 cents
per share, which is payable on December 29, 2006 to common shareholders of
record as of December 15, 2006.

Divestitures update
During the third quarter, EnCana closed the sale of its 50 percent
interest in the Chinook heavy oil discovery offshore Brazil. EnCana continues
to hold non-operated interests in 10 deep water exploration blocks offshore
Brazil. Nine of these blocks are operated by Petrobras.
Before the end of 2006, EnCana expects to close the sale of its Wild
Goose storage facility in California, which is the second and final phase of
the company's $1.5 billion sale of its natural gas storage business. The Wild
Goose sale requires approval of the California Public Utilities Commission.
The first phase of the gas storage sale to Carlyle/Riverstone Global Energy
and Power Fund, an energy private equity fund managed by Riverstone Holdings
LLC and The Carlyle Group, included EnCana's Alberta, Oklahoma and Louisiana
storage assets and generated proceeds of about $1.3 billion.
EnCana recently initiated processes to sell its interests in Northern
Canada and Chad. These exploration properties, which have generated some
encouraging natural gas and oil drilling results, are conventional properties
and have been deemed non-core.

Normal Course Issuer Bid
To date in 2006, EnCana has purchased for cancellation approximately 61.1
million of its shares at an average price of $48.67 per share, including
commissions, under its current Normal Course Issuer Bid. The company intends
to file a renewal notice of intention to make a Normal Course Issuer Bid with
the Toronto Stock Exchange (TSX) for approval.

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

EnCana maintains a strong balance sheet. At September 30, 2006 the
company's net debt-to-capitalization ratio was 25:75. EnCana's net debt-to-
adjusted-EBITDA multiple, on a trailing 12-month basis, was 0.5 times. These
ratios are below the company's targeted range for net debt-to-capitalization
of between 30 and 40 percent and 1.0 to 2.0 times for net debt-to-adjusted-
EBITDA.
In the third quarter of 2006, EnCana invested $1,474 million of core
capital. Net divestitures were $365 million, resulting in net capital
investment in total operations of $1,109 million. EnCana's 2006 capital
program is expected to be within the company's forecast range of between $5.8
billion and $6.1 billion and is expected to be funded by cash flow.

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

EnCana will host a conference call and webcast to discuss its third
quarter results today, Wednesday, October 25, 2006, at 11:00 a.m. MT
(1:00 p.m. ET). To participate, please dial (800) 811-0667 (toll-free in
North America) or (913) 981-4900 approximately 10 minutes prior to the
conference call. An archived recording of the call will be available from
approximately 3:00 p.m. MT on October 25 until midnight October 29, 2006
by dialing (888) 203-1112 or (719) 457-0820 and entering access code
7859214.

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$45 billion, EnCana is one of
North America's leading natural gas producers, the largest holder of gas and
oil resource lands onshore North America and is a technical and cost leader in
the in-situ recovery of oilsands bitumen. EnCana delivers predictable,
reliable, profitable growth from its portfolio of long-life resource plays
situated in Canada and the United States. Contained in unconventional
reservoirs, resource plays are large contiguous accumulations of hydrocarbons,
located in thick or areally extensive deposits, that typically have lower
geological and commercial development risk, lower average decline rates and
longer producing lives than conventional plays. 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, total operating
earnings and adjusted 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 or loss 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.
- Adjusted EBITDA is a non-GAAP measure that is defined as net
earnings from continuing operations before gain on disposition,
income taxes, foreign exchange gains or losses, interest net,
accretion of asset retirement obligation, and depreciation,
depletion and amortization.
Management believes that the inclusion of total operating earnings
enhances the comparability of the company's underlying financial performance
between periods. The majority of the unrealized gains/losses that relate to
U.S. dollar debt issued in Canada are for debt with maturity dates in excess
of five years. These measures have been described and presented in this news
release in order to provide shareholders and potential investors with
additional information regarding EnCana's liquidity and its ability to
generate funds to finance its operations.

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.

Unbooked resource potential
EnCana defines unbooked resource potential as quantities of oil and
natural gas on existing landholdings 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. EnCana employs a probability-weighted
approach in the calculation of these quantities, including statistical
distributions of resource play performance and areal extent. Consequently,
EnCana's unbooked resource potential necessarily includes quantities of
probable and possible reserves and contingent resources, as these terms are
defined in the Canadian Oil and Gas Evaluation Handbook.

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 or information within the
meaning of applicable securities legislation, collectively referred to herein
as "forward-looking statements." Forward-looking statements in this news
release include, but are not limited to: future economic and operating
performance (including per share growth, cash flow and increase in net asset
value); anticipated life of proved reserves; anticipated unbooked resource
potential; anticipated conversion of unbooked resource potential to proved
reserves; anticipated growth and success of resource plays and the expected
characteristics of resource plays; anticipated bitumen production expansion
including expansions of and production from Foster Creek and Christina Lake
and the timing thereof; anticipated expansion of refining capacity at Wood
River and Borger; anticipated success of the partnership with ConocoPhillips,
including its potential impact on cost and price risk and economic returns;
anticipated closing date of the transaction with ConocoPhillips, expected
proportion of total production and cash flows contributed by natural gas;
anticipated impact and success of EnCana's market risk mitigation strategy;
anticipated filing and receiving TSX approval of, and purchases pursuant to, a
Normal Course Issuer Bid; potential demand for gas; anticipated production in
2006 and beyond; anticipated drilling; potential divestitures and farm outs
planned for 2007 and beyond; potential capital expenditures and investment
projections relating to the 2006 and 2007 capital budget and the expected date
for the setting of the 2007 capital budget; potential oil, natural gas and
NGLs sales in 2006 and beyond; forecast natural gas, crude oil and NGLs sales
guidance for 2006 and anticipated ability to meet production, operating cost
and sales guidance targets; potential pipeline capacity increases in 2007 and
2008 and its impact on the Jonah project; the expected dates for the delivery
of new rigs to the Jonah project and their projected impact on costs; the
projected on-stream date and capacity of the Steeprock processing plant;
anticipated costs, including costs associated with developing unbooked
resource potential and expected costs to develop the company's drilling
inventory; the potential for reduced industry activity in the future and the
impact thereof on costs; anticipated prices for crude oil and natural gas and
the impact of winter weather and natural gas storage levels on natural gas
prices; projections of expected cost inflation levels; the expected date for
receipt of California regulatory approvals in respect of the sale of the
company's remaining gas storage assets and the expected timing for closing
this transaction; projections for future debt to capitalization ratios and
cash tax expense percentages; 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 and assumptions
regarding oil and gas prices; assumptions based upon the company's current
guidance; 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 reserve estimates and
estimates of recoverable quantities of oil, bitumen, natural gas and liquids
from resource plays and other sources not currently classified as proved; the
company's ability to replace and expand oil and gas reserves; the ability of
the company and ConocoPhillips to successfully negotiate and execute final
definitive agreements relating to the integrated North American heavy oil
business and the ability of the parties to obtain necessary regulatory
approvals; refining and marketing margins; potential disruption or unexpected
technical difficulties in developing new products and manufacturing processes;
potential failure of new products to achieve acceptance in the market;
unexpected cost increases or technical difficulties in constructing or
modifying manufacturing or refining facilities; unexpected difficulties in
manufacturing, transporting or refining synthetic crude oil; risks associated
with technology; the company's ability to generate sufficient cash flow from
operations to meet its current and future obligations; the company's 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; the risk of
international 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, except as required
by law, EnCana does not undertake any obligation to update publicly or to
revise any of the included forward-looking statements, whether as a result of
new information, future events or otherwise. The forward-looking statements
contained in this news release are expressly qualified by this cautionary
statement.


Interim Consolidated Financial Statements
(unaudited)
For the period ended September 30, 2006


EnCana Corporation


U.S. DOLLARS


CONSOLIDATED STATEMENT OF EARNINGS (unaudited)

Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------------------------
($ millions, except per
share amounts) 2006 2005 2006 2005
-------------------------------------------------------------------------

REVENUES, NET OF ROYALTIES
(Note 3)
Upstream $ 2,762 $ 2,680 $ 8,202 $ 7,013
Market Optimization 731 1,112 2,272 2,850
Corporate - Unrealized
gain (loss) on risk
management 428 (810) 1,921 (1,457)
-------------------------------------------------------------------------
3,921 2,982 12,395 8,406
EXPENSES (Note 3)
Production and mineral
taxes 79 107 269 291
Transportation and
selling 163 137 467 400
Operating 420 371 1,227 986
Purchased product 677 1,083 2,160 2,783
Depreciation, depletion
and amortization 791 670 2,346 2,018
Administrative 54 78 187 205
Interest, net (Note 6) 83 219 254 420
Accretion of asset
retirement obligation
(Note 10) 13 9 37 27
Foreign exchange (gain)
loss, net (Note 7) - (212) (158) (61)
Stock-based
compensation - options - 4 - 12
(Gain) on dispositions
(Note 5) (304) - (321) -
-------------------------------------------------------------------------
1,976 2,466 6,468 7,081
-------------------------------------------------------------------------
NET EARNINGS BEFORE
INCOME TAX 1,945 516 5,927 1,325
Income tax expense
(Note 8) 602 168 1,519 365
-------------------------------------------------------------------------
NET EARNINGS FROM
CONTINUING OPERATIONS 1,343 348 4,408 960
NET EARNINGS (LOSS) FROM
DISCONTINUED OPERATIONS
(Note 4) 15 (82) 581 100
-------------------------------------------------------------------------
NET EARNINGS $ 1,358 $ 266 $ 4,989 $ 1,060
-------------------------------------------------------------------------
-------------------------------------------------------------------------

NET EARNINGS FROM
CONTINUING OPERATIONS
PER COMMON SHARE (Note 13)
Basic $ 1.66 $ 0.41 $ 5.32 $ 1.10
Diluted $ 1.63 $ 0.40 $ 5.21 $ 1.07
-------------------------------------------------------------------------
-------------------------------------------------------------------------

NET EARNINGS PER COMMON
SHARE (Note 13)
Basic $ 1.68 $ 0.31 $ 6.02 $ 1.21
Diluted $ 1.65 $ 0.30 $ 5.90 $ 1.19
-------------------------------------------------------------------------
-------------------------------------------------------------------------



CONSOLIDATED STATEMENT OF RETAINED EARNINGS (unaudited)

Nine Months Ended
September 30,
----------------------
($ millions) 2006 2005
-------------------------------------------------------------------------

RETAINED EARNINGS, BEGINNING OF YEAR $ 9,481 $ 7,935
Net Earnings 4,989 1,060
Dividends on Common Shares (226) (174)
Charges for Normal Course Issuer Bid (Note 11) (2,450) (1,495)
Charges for Shares Repurchased and Held - (147)
-------------------------------------------------------------------------
RETAINED EARNINGS, END OF PERIOD $ 11,794 $ 7,179
-------------------------------------------------------------------------
-------------------------------------------------------------------------

See accompanying Notes to Consolidated Financial Statements.



CONSOLIDATED BALANCE SHEET (unaudited)

As at As at
September 30, December 31,
($ millions) 2006 2005
-------------------------------------------------------------------------

ASSETS
Current Assets
Cash and cash equivalents $ 134 $ 105
Accounts receivable and accrued revenues 1,467 1,851
Risk management (Note 14) 1,293 495
Inventories 152 103
Assets of discontinued operations (Note 4) 203 1,050
-------------------------------------------------------------------------
3,249 3,604
Property, Plant and Equipment, net (Note 3) 28,489 24,881
Investments and Other Assets 580 496
Risk Management (Note 14) 243 530
Assets of Discontinued Operations (Note 4) - 2,113
Goodwill 2,617 2,524
-------------------------------------------------------------------------
(Note 3) $ 35,178 $ 34,148
-------------------------------------------------------------------------
-------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued liabilities $ 2,163 $ 2,741
Income tax payable 989 392
Risk management (Note 14) 60 1,227
Liabilities of discontinued operations (Note 4) 71 438
Current portion of long-term debt (Note 9) - 73
-------------------------------------------------------------------------
3,283 4,871
Long-Term Debt (Note 9) 6,227 6,703
Other Liabilities 86 93
Risk Management (Note 14) 5 102
Asset Retirement Obligation (Note 10) 929 816
Liabilities of Discontinued Operations (Note 4) - 267
Future Income Taxes 6,162 5,289
-------------------------------------------------------------------------
16,692 18,141
-------------------------------------------------------------------------
Shareholders' Equity
Share capital (Note 11) 4,748 5,131
Paid in surplus 151 133
Retained earnings 11,794 9,481
Foreign currency translation adjustment 1,793 1,262
-------------------------------------------------------------------------
18,486 16,007
-------------------------------------------------------------------------
$ 35,178 $ 34,148
-------------------------------------------------------------------------
-------------------------------------------------------------------------

See accompanying Notes to Consolidated Financial Statements.



CONSOLIDATED STATEMENT OF CASH FLOWS (unaudited)

Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------------------------
($ millions) 2006 2005 2006 2005
-------------------------------------------------------------------------

OPERATING ACTIVITIES
Net earnings from
continuing operations $ 1,343 $ 348 $ 4,408 $ 960
Depreciation, depletion
and amortization 791 670 2,346 2,018
Future income taxes
(Note 8) 401 13 690 (661)
Cash tax on sale of
assets (Note 5) 49 - 49 591
Unrealized (gain) loss
on risk management
(Note 14) (428) 809 (1,919) 1,454
Unrealized foreign
exchange (gain) loss 4 (202) (79) (79)
Accretion of asset
retirement obligation
(Note 10) 13 9 37 27
(Gain) on dispositions (304) - (321) -
Other 14 176 90 262
-------------------------------------------------------------------------
Cash flow from continuing
operations 1,883 1,823 5,301 4,572
Cash flow from
discontinued operations 11 108 99 344
-------------------------------------------------------------------------
Cash flow 1,894 1,931 5,400 4,916
Net change in other
assets and liabilities 21 (160) 48 (174)
Net change in non-cash
working capital from
continuing operations (247) (579) 3,305 (652)
Net change in non-cash
working capital from
discontinued operations (13) 23 (2,476) (76)
-------------------------------------------------------------------------
1,655 1,215 6,277 4,014
-------------------------------------------------------------------------

INVESTING ACTIVITIES
Capital expenditures
(Note 3) (1,486) (1,617) (5,350) (4,563)
Proceeds on disposal of
assets (Note 5) 377 34 634 2,493
Cash tax on sale of
assets (Note 5) (49) - (49) (591)
Net change in investments
and other (56) 35 (38) 27
Net change in non-cash
working capital from
continuing operations (18) (352) (169) 99
Discontinued operations - (111) 2,377 (246)
-------------------------------------------------------------------------
(1,232) (2,011) (2,595) (2,781)
-------------------------------------------------------------------------

FINANCING ACTIVITIES
Net issuance (repayment)
of revolving long-term
debt 470 1,691 (512) 976
Issuance of long-term
debt - 428 - 428
Repayment of long-term
debt (73) (958) (73) (959)
Issuance of common
shares (Note 11) 39 86 140 270
Purchase of common
shares (Note 11) (900) (452) (2,973) (2,114)
Dividends on common
shares (80) (64) (226) (174)
Other 2 (105) (9) (108)
-------------------------------------------------------------------------
(542) 626 (3,653) (1,681)
-------------------------------------------------------------------------

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

INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS (119) (174) 29 (450)
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD 253 317 105 593
-------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS,
END OF PERIOD $ 134 $ 143 $ 134 $ 143
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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, 2005, except as noted below. The disclosures provided below
are incremental to those included with the annual audited Consolidated
Financial Statements. The interim Consolidated Financial Statements
should be read in conjunction with the annual audited Consolidated
Financial Statements and the notes thereto for the year ended
December 31, 2005.

2. CHANGE IN ACCOUNTING POLICIES AND PRACTICES

On January 1, 2006, the Company adopted Emerging Issues Task Force
("EITF") Abstract No. 04-13 - Accounting for Purchases and Sales of
Inventory with the Same Counterparty. As of January 1, 2006, purchases
and sales of inventory with the same counterparty that are entered into
in contemplation of each other are recorded on a net basis in the
Consolidated Statement of Earnings. This change has been adopted
prospectively and has no effect on the net earnings of the reported
periods.

3. 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 Chad, Brazil, the Middle East, Greenland and France.

- Market Optimization is conducted by the Midstream & Marketing
division. 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
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.

Market Optimization purchases substantially all of the Company's
North American Upstream production for sale to third party customers.
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 4.


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

Upstream Market Optimization
------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 2,762 $ 2,680 $ 731 $ 1,112
Expenses
Production and mineral taxes 79 107 - -
Transportation and selling 159 133 4 4
Operating 401 348 18 24
Purchased product - - 677 1,083
Depreciation, depletion and
amortization 770 649 3 2
-------------------------------------------------------------------------
Segment Income (Loss) $ 1,353 $ 1,443 $ 29 $ (1)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Corporate(*) Consolidated
------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 428 $ (810) $ 3,921 $ 2,982
Expenses
Production and mineral taxes - - 79 107
Transportation and selling - - 163 137
Operating 1 (1) 420 371
Purchased product - - 677 1,083
Depreciation, depletion and
amortization 18 19 791 670
-------------------------------------------------------------------------
Segment Income (Loss) $ 409 $ (828) 1,791 614
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Administrative 54 78
Interest, net 83 219
Accretion of asset retirement
obligation 13 9
Foreign exchange (gain)
loss, net - (212)
Stock-based compensation
- options - 4
(Gain) on divestitures (Note 5) (304) -
-------------------------------------------------------------------------
(154) 98
-------------------------------------------------------------------------
Net Earnings Before Income Tax 1,945 516
Income tax expense 602 168
-------------------------------------------------------------------------
Net Earnings From Continuing Operations $ 1,343 $ 348
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(*) For the three months ended September 30, the pre-tax unrealized gain
(loss) on risk management is recorded in the Consolidated Statement
of Earnings as follows (see Note 14):

2006 2005
-------------------------------------------------------------------------

Revenues, Net of Royalties - Corporate $ 428 $ (810)
Operating Expenses and Other - Corporate - 1
-------------------------------------------------------------------------
Total Unrealized Gain (Loss) on Risk
Management before-tax - Continuing Operations $ 428 $ (809)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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

Upstream Canada United States
------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 1,876 $ 1,807 $ 811 $ 797
Expenses
Production and mineral taxes 27 24 52 83
Transportation and selling 95 84 64 49
Operating 266 207 64 56
Depreciation, depletion and
amortization 541 485 222 157
-------------------------------------------------------------------------
Segment Income $ 947 $ 1,007 $ 409 $ 452
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Other Total Upstream
------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 75 $ 76 $ 2,762 $ 2,680
Expenses
Production and mineral taxes - - 79 107
Transportation and selling - - 159 133
Operating 71 85 401 348
Depreciation, depletion and
amortization 7 7 770 649
-------------------------------------------------------------------------
Segment Income (Loss) $ (3) $ (16) $ 1,353 $ 1,443
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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

Produced Gas
----------------------------------------------------
Canada United States Total
----------------------------------------------------
2006 2005 2006 2005 2006 2005
-------------------------------------------------------------------------

Revenues, Net of
Royalties $ 1,302 $ 1,317 $ 735 $ 726 $ 2,037 $ 2,043
Expenses
Production and
mineral taxes 18 19 47 77 65 96
Transportation
and selling 74 70 64 49 138 119
Operating 157 134 64 56 221 190
-------------------------------------------------------------------------
Operating Cash Flow $ 1,053 $ 1,094 $ 560 $ 544 $ 1,613 $ 1,638
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Oil & NGLs
----------------------------------------------------
Canada United States Total
----------------------------------------------------
2006 2005 2006 2005 2006 2005
-------------------------------------------------------------------------

Revenues, Net of
Royalties $ 574 $ 490 $ 76 $ 71 $ 650 $ 561
Expenses
Production and
mineral taxes 9 5 5 6 14 11
Transportation and
selling 21 14 - - 21 14
Operating 109 73 - - 109 73
-------------------------------------------------------------------------
Operating Cash Flow $ 435 $ 398 $ 71 $ 65 $ 506 $ 463
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Other Total Upstream
-----------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 75 $ 76 $ 2,762 $ 2,680
Expenses
Production and mineral taxes - - 79 107
Transportation and selling - - 159 133
Operating 71 85 401 348
-------------------------------------------------------------------------
Operating Cash Flow $ 4 $ (9) $ 2,123 $ 2,092
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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

Market
Upstream Optimization
-----------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 8,202 $ 7,013 $ 2,272 $ 2,850
Expenses
Production and mineral taxes 269 291 - -
Transportation and selling 450 390 17 10
Operating 1,177 936 49 53
Purchased product - - 2,160 2,783
Depreciation, depletion and
amortization 2,282 1,957 8 7
-------------------------------------------------------------------------
Segment Income (Loss) $ 4,024 $ 3,439 $ 38 $ (3)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Corporate(*) Consolidated
-----------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 1,921 $(1,457) $12,395 $ 8,406
Expenses
Production and mineral taxes - - 269 291
Transportation and selling - - 467 400
Operating 1 (3) 1,227 986
Purchased product - - 2,160 2,783
Depreciation, depletion and
amortization 56 54 2,346 2,018
-------------------------------------------------------------------------
Segment Income (Loss) $ 1,864 $(1,508) 5,926 1,928
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Administrative 187 205
Interest, net 254 420
Accretion of asset retirement
obligation 37 27
Foreign exchange (gain) loss,
net (158) (61)
Stock-based compensation
- options - 12
(Gain) on dispositions (Note 5) (321) -
-------------------------------------------------------------------------
(1) 603
-------------------------------------------------------------------------
Net Earnings Before
Income Tax 5,927 1,325
Income tax expense 1,519 365
-------------------------------------------------------------------------
Net Earnings From
Continuing Operations $ 4,408 $ 960
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(*) For the nine months ended September 30, the pre-tax unrealized gain
(loss) on risk management is recorded in the Consolidated Statement
of Earnings as follows (see Note 14):


2006 2005
-------------------------------------------------------------------------

Revenues, Net of Royalties
- Corporate $ 1,921 $(1,457)
Operating Expenses and Other
- Corporate (2) 3
-------------------------------------------------------------------------
Total Unrealized Gain (Loss)
on Risk Management before-tax
- Continuing Operations $ 1,919 $(1,454)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Upstream Canada United States
-----------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 5,617 $ 4,747 $ 2,356 $ 2,071
Expenses
Production and mineral taxes 96 75 173 216
Transportation and selling 268 256 182 134
Operating 753 599 207 148
Depreciation, depletion and
amortization 1,606 1,416 648 516
-------------------------------------------------------------------------
Segment Income $ 2,894 $ 2,401 $ 1,146 $ 1,057
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Transportation and selling for the United States includes a one time
payment in the first quarter of 2006 of $14 million to terminate a
long-term physical delivery contract.

Other Total Upstream
-----------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 229 $ 195 $ 8,202 $ 7,013
Expenses
Production and mineral taxes - - 269 291
Transportation and selling - - 450 390
Operating 217 189 1,177 936
Depreciation, depletion and
amortization 28 25 2,282 1,957
-------------------------------------------------------------------------
Segment Income (Loss) $ (16) $ (19) $ 4,024 $ 3,439
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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

Produced Gas
----------------------------------------------------
Canada United States Total
----------------------------------------------------
2006 2005 2006 2005 2006 2005
-------------------------------------------------------------------------

Revenues, Net of
Royalties $ 4,039 $ 3,634 $ 2,148 $ 1,891 $ 6,187 $ 5,525
Expenses
Production and
mineral taxes 69 56 159 198 228 254
Transportation and
selling 212 211 182 134 394 345
Operating 463 377 207 148 670 525
-------------------------------------------------------------------------
Operating Cash Flow $ 3,295 $ 2,990 $ 1,600 $ 1,411 $ 4,895 $ 4,401
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Transportation and selling for the United States includes a one time
payment in the first quarter of 2006 of $14 million to terminate a long-
term physical delivery contract.

Oil & NGLs
----------------------------------------------------
Canada United States Total
----------------------------------------------------
2006 2005 2006 2005 2006 2005
-------------------------------------------------------------------------

Revenues, Net of
Royalties $ 1,578 $ 1,113 $ 208 $ 180 $ 1,786 $ 1,293
Expenses
Production and
mineral taxes 27 19 14 18 41 37
Transportation and
selling 56 45 - - 56 45
Operating 290 222 - - 290 222
-------------------------------------------------------------------------
Operating Cash Flow $ 1,205 $ 827 $ 194 $ 162 $ 1,399 $ 989
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Other Total Upstream
-----------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 229 $ 195 $ 8,202 $ 7,013
Expenses
Production and mineral taxes - - 269 291
Transportation and selling - - 450 390
Operating 217 189 1,177 936
-------------------------------------------------------------------------
Operating Cash Flow $ 12 $ 6 $ 6,306 $ 5,396
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Capital Expenditures (Continuing Operations)

Three Months Nine Months
Ended Ended
September 30, September 30,
-----------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------

Upstream Core Capital
Canada $ 864 $ 909 $ 3,166 $ 2,780
United States 576 471 1,746 1,349
Other Countries 12 10 51 39
-------------------------------------------------------------------------
1,452 1,390 4,963 4,168
-------------------------------------------------------------------------

Upstream Acquisition Capital
Canada 1 3 30 26
United States 11 176 268 191
-------------------------------------------------------------------------
12 179 298 217
-------------------------------------------------------------------------

Market Optimization 2 14 40 129
Corporate 20 34 49 49
-------------------------------------------------------------------------
Total $ 1,486 $ 1,617 $ 5,350 $ 4,563
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Property, Plant and Equipment and Total Assets

Property, Plant and Equipment Total Assets
---------------------------------------------------------
As at As at
---------------------------------------------------------
September 30, December 31, September 30, December 31,
2006 2005 2006 2005
-------------------------------------------------------------------------

Upstream $ 28,051 $ 24,247 $ 32,512 $ 28,858
Market Optimization 161 371 387 597
Corporate 277 263 2,076 1,530
Assets of Discontinued
Operations (Note 4) 203 3,163
-------------------------------------------------------------------------
Total $ 28,489 $ 24,881 $ 35,178 $ 34,148
-------------------------------------------------------------------------
-------------------------------------------------------------------------

4. DISCONTINUED OPERATIONS

Midstream

On December 13, 2005, EnCana completed the sale of its Midstream natural
gas liquids processing operations for total proceeds of $625 million
(C$720 million). The natural gas liquids processing operations included
various interests in a number of processing and related facilities as
well as a marketing entity. A gain on sale of approximately $370 million,
after-tax, was recorded.

During the fourth quarter of 2005, EnCana decided to divest of its
natural gas storage operations. EnCana's natural gas storage operations
include the 100 percent interest in the AECO storage facility as well as
facilities in the United States. On March 6, 2006, EnCana announced that
it had reached an agreement to sell the gas storage operations for
$1.5 billion. The sale, to a single purchaser, which is subject to
closing conditions and applicable regulatory approvals, is expected to
close in two stages. On May 12, 2006, the first stage of the sale was
closed for proceeds of $1.3 billion. The second stage will close
following receipt of regulatory approvals, expected to be later in 2006.

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 relation to 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.

On February 28, 2006, EnCana completed the sale of its interest in its
Ecuador operations for $1.4 billion before indemnifications which are
discussed further in this note.

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.


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,
-------------------------------------------------------
United
Ecuador Kingdom Midstream Total
-------------------------------------------------------
2006 2005 2006 2005 2006 2005 2006 2005
-------------------------------------------------------------------------

Revenues, Net
of Royalties $ - $ 291 $ - $ - $ 14 $ 107 $ 14 $ 398
-------------------------------------------------------------------------

Expenses
Production and
mineral taxes - 49 - - - - - 49
Transportation
and selling - 15 - - - 2 - 17
Operating - 38 - - - 61 - 99
Purchased
product - - - - - 161 - 161
Depreciation,
depletion and
amortization - 123 - - - 7 - 130
Interest, net - - - - - (1) - (1)
Foreign exchange
(gain) loss, net - (1) - - (4) (1) (4) (2)
(Gain) loss on
discontinuance - - - - 2 - 2 -
-------------------------------------------------------------------------
- 224 - - (2) 229 (2) 453
-------------------------------------------------------------------------
Net Earnings (Loss)
Before Income Tax - 67 - - 16 (122) 16 (55)
Income tax expense
(recovery) - 67 (7) - 8 (40) 1 27
-------------------------------------------------------------------------
Net Earnings (Loss)
From
Discontinued
Operations $ - $ - $ 7 $ - $ 8 $ (82) $ 15 $ (82)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


For the nine months ended September 30,
-------------------------------------------------------
United
Ecuador Kingdom Midstream Total
-------------------------------------------------------
2006 2005 2006 2005 2006 2005 2006 2005
-------------------------------------------------------------------------
Revenues, Net
of Royalties(*) $ 200 $ 723 $ - $ - $ 477 $ 925 $ 677 $1,648
-------------------------------------------------------------------------
Expenses
Production and
mineral taxes 23 101 - - - - 23 101
Transportation
and selling 10 46 - - - 6 10 52
Operating 25 100 - - 29 191 54 291
Purchased
product - - - - 354 757 354 757
Depreciation,
depletion and
amortization 84 123 - - - 20 84 143
Interest, net (2) - - - - (1) (2) (1)
Accretion of
asset
retirement
obligation - 1 - - - - - 1
Foreign
exchange
(gain) loss,
net 1 - - (3) 5 (2) 6 (5)
(Gain) loss on
discontinuance 279 - - - (766) - (487) -
-------------------------------------------------------------------------
420 371 - (3) (378) 971 42 1,339
-------------------------------------------------------------------------
Net Earnings (Loss)
Before Income Tax (220) 352 - 3 855 (46) 635 309
Income tax
expense
(recovery) 59 221 (5) 1 - (13) 54 209
-------------------------------------------------------------------------
Net Earnings
(Loss) From
Discontinued
Operations $ (279)$ 131 $ 5 $ 2 $ 855 $ (33)$ 581 $ 100
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(*) Revenues, net of royalties in Ecuador include realized losses of
$1 million related to derivative financial instruments. In 2005,
revenues, net of royalties included realized losses of $105 million
and unrealized mark-to-market gains of $50 million.


Consolidated Balance Sheet

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

As at
-------------------------------------------------------
September 30, 2006 December 31, 2005
-------------------------------------------------------
United United
Ecu- Kin- Mids- Ecu- Kin- Mids-
ador gdom tream Total ador gdom tream Total
-------------------------------------------------------------------------
Assets
Cash and cash
equivalents $ - $ 6 $ 1 $ 7 $ 207 $ 8 $ (7)$ 208
Accounts
receivable
and accrued
revenues - - 10 10 137 - 271 408
Risk
management - - 7 7 - - 21 21
Inventories - - 20 20 23 - 390 413
-------------------------------------------------------------------------
- 6 38 44 367 8 675 1,050
Property, plant
and equipment,
net 1 - 158 159 1,166 - 520 1,686
Investments
and other
assets - - - - 360 - - 360
Goodwill - - - - - - 67 67
-------------------------------------------------------------------------
$ 1 $ 6 $ 196 $ 203 $1,893 $ 8 $1,262 $3,163
-------------------------------------------------------------------------
Liabilities
Accounts
payable and
accrued
liabilities $ - $ 27 $ - $ 27 $ 91 $ 27 $ 49 $ 167
Income tax
payable - - 19 19 184 6 40 230
Risk
management - - - - - - 41 41
-------------------------------------------------------------------------
- 27 19 46 275 33 130 438
Asset
retirement
obligation - - - - 21 - - 21
Future income
taxes
(recovery) - - 25 25 162 (2) 86 246
-------------------------------------------------------------------------
- 27 44 71 458 31 216 705
-------------------------------------------------------------------------
Net Assets of
Discontinued
Operations $ 1 $ (21)$ 152 $ 132 $1,435 $ (23)$1,046 $2,458
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Contingencies

EnCana has agreed to indemnify the purchaser of its Ecuador interests
against losses that may arise in certain circumstances which are defined
in the share sale agreements. The obligation to indemnify will arise
should losses exceed amounts specified in the sale agreements and is
limited to maximum amounts which are set forth in the share sale
agreements.

During the second quarter, the Government of Ecuador seized the Block 15
assets, in relation to which EnCana previously held a 40 percent economic
interest, from the operator which is an event requiring indemnification
under the terms of EnCana's sale agreement with Andes Petroleum Company.
The purchaser requested payment and EnCana paid the maximum amount in the
third quarter, calculated in accordance with the terms of the agreements,
of approximately $265 million. EnCana does not expect that any further
significant indemnification payments relating to any other business
matters addressed in the share sale agreements will be required to be
made to the purchaser.

5. DIVESTITURES

Total proceeds received on sale of assets and investments was
$634 million (2005 - $2,493 million) as described below:

Upstream

In 2006, the Company has completed the disposition of mature conventional
oil and natural gas assets for proceeds of $23 million (2005 -
$440 million).

In August 2006, the Company completed the sale of its 50 percent interest
in the Chinook heavy oil discovery offshore Brazil for approximately
$367 million which resulted in a gain on sale of $304 million. After
recording income tax of $49 million, EnCana recorded an after-tax gain of
$255 million.

In May 2005, 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.

Market Optimization

In February 2006, the Company sold its investment in Entrega Gas Pipeline
LLC for approximately $244 million which resulted in a gain on sale of
$17 million.

6. INTEREST, NET

Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------

Interest Expense
- Long-Term
Debt $ 88 $ 104 $ 269 $ 310
Early Retirement
of Long-Term Debt - 121 - 121
Interest Expense
- Other 9 5 19 12
Interest Income (14) (11) (34) (23)
-------------------------------------------------------------------------
$ 83 $ 219 $ 254 $ 420
-------------------------------------------------------------------------
-------------------------------------------------------------------------

7. FOREIGN EXCHANGE (GAIN) LOSS, NET

Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------

Unrealized
Foreign Exchange
(Gain) Loss on
Translation of
U.S. Dollar Debt
Issued from
Canada $ 4 $ (205) $ (155) $ (140)
Other Foreign
Exchange (Gain)
Loss (4) (7) (3) 79
-------------------------------------------------------------------------
$ - $ (212) $ (158) $ (61)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

8. INCOME TAXES

The provision for income taxes is as follows:

Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------

Current
Canada $ 105 $ 6 $ 694 $ 288
United States 51 153 87 744
Other 45 (4) 48 (6)
-------------------------------------------------------------------------
Total Current Tax 201 155 829 1,026
-------------------------------------------------------------------------

Future 401 13 690 (661)
-------------------------------------------------------------------------
$ 602 $ 168 $ 1,519 $ 365
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Current income tax in the United States for the nine months ended
September 30, 2005 of $591 million relates to income tax on the sale of
the Gulf of Mexico assets.

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,
-------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------

Net Earnings
Before Income
Tax $ 1,945 $ 516 $ 5,927 $ 1,325
Canadian
Statutory Rate 34.7% 37.9% 34.7% 37.9%
-------------------------------------------------------------------------
Expected Income
Tax 674 196 2,055 502

Effect on Taxes
Resulting from:
Non-deductible
Canadian crown
payments 23 53 75 139
Canadian
resource
allowance (1) (51) (20) (141)
Canadian
resource
allowance on
unrealized risk
management
losses 1 13 2 26
Statutory and
other rate
differences (63) (31) (80) (111)
Effect of tax
rate changes(*) - - (457) -
Non-taxable
capital (gains)
losses 3 (43) (30) (27)
Tax basis
retained on
dispositions - - - (68)
Large
corporations
tax - 20 - 24
Other (35) 11 (26) 21
-------------------------------------------------------------------------
$ 602 $ 168 $ 1,519 $ 365
-------------------------------------------------------------------------
Effective Tax
Rate 31.0% 32.6% 25.6% 27.5%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) During the second quarter, the Canadian federal and Alberta
governments substantively enacted income tax rate reductions.

9. LONG-TERM DEBT

As at As at
September 30, December 31,
2006 2005
-------------------------------------------------------------------------

Canadian Dollar Denominated Debt
Revolving credit and term loan borrowings $ 838 $ 1,425
Unsecured notes 829 793
-------------------------------------------------------------------------
1,667 2,218
-------------------------------------------------------------------------

U.S. Dollar Denominated Debt
Revolving credit and term loan borrowings 75 -
Unsecured notes 4,421 4,494
-------------------------------------------------------------------------
4,496 4,494
-------------------------------------------------------------------------

Increase in Value of Debt Acquired(*) 64 64
Current Portion of Long-Term Debt - (73)
-------------------------------------------------------------------------
$ 6,227 $ 6,703
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) 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
21 years.

10. ASSET RETIREMENT OBLIGATION

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

As at As at
September 30, December 31,
2006 2005
-------------------------------------------------------------------------

Asset Retirement Obligation, Beginning of
Year $ 816 $ 611
Liabilities Incurred 54 77
Liabilities Settled (37) (42)
Liabilities Disposed - (23)
Change in Estimated Future Cash Flows 21 135
Accretion Expense 37 37
Other 38 21
-------------------------------------------------------------------------
Asset Retirement Obligation, End of Period $ 929 $ 816
-------------------------------------------------------------------------
-------------------------------------------------------------------------

11. SHARE CAPITAL

September 30, 2006 December 31, 2005
-------------------------------------------------------
(millions) Number Amount Number Amount
-------------------------------------------------------------------------

Common Shares
Outstanding,
Beginning of
Year 854.9 $ 5,131 900.6 $ 5,299
Common Shares
Issued under
Option Plans 6.3 140 15.0 294
Common Shares
Repurchased (61.1) (523) (60.7) (462)
-------------------------------------------------------------------------
Common Shares
Outstanding,
End of Period 800.1 $ 4,748 854.9 $ 5,131
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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, 2006, the Company purchased 61.1 million Common Shares
for total consideration of approximately $2,973 million. Of the amount
paid, $523 million was charged to Share capital and $2,450 million was
charged to Retained earnings.

EnCana has obtained regulatory approval each year under Canadian
securities laws to purchase Common Shares under four consecutive Normal
Course Issuer Bids ("Bids") which commenced in October 2002 and may
continue until October 30, 2006. EnCana is entitled to purchase, for
cancellation, up to approximately 85.6 million Common Shares under the
renewed Bid which commenced on October 31, 2005 and will terminate no
later than October 30, 2006.

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, 2006. Information related to
TSAR's is included in Note 12.

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

Outstanding, Beginning of Year 20.7 23.36
Exercised (6.3) 23.58
Forfeited (0.3) 23.80
-------------------------------------------------------------------------
Outstanding, End of Period 14.1 23.25
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Exercisable, End of Period 13.9 23.24
-------------------------------------------------------------------------
-------------------------------------------------------------------------



Outstanding Options Exercisable Options
-----------------------------------------------------------

Weighted
Average Number of
Number of Remaining Weighted Options Weighted
Range of Options Contrac- Average Out- Average
Exercise Outstanding tual Life Exercise standing Exercise
Price (C$) (millions) (years) Price (C$) (millions) Price (C$)
-------------------------------------------------------------------------

11.00 to 22.99 1.2 2.1 14.48 1.2 14.26
23.00 to 23.49 0.2 1.4 23.21 0.2 23.23
23.50 to 23.99 5.5 1.6 23.89 5.4 23.89
24.00 to 24.49 6.8 0.6 24.17 6.8 24.17
24.50 to 25.99 0.4 1.9 25.23 0.3 25.27
-------------------------------------------------------------------------
14.1 1.1 23.25 13.9 23.24
-------------------------------------------------------------------------
-------------------------------------------------------------------------

At September 30, 2006, the balance in Paid in surplus relates to Stock-
Based Compensation programs.

12. COMPENSATION PLANS

The tables below outline certain information related to EnCana's
compensation plans at September 30, 2006. Additional information is
contained in Note 15 of the Company's annual audited Consolidated
Financial Statements for the year ended December 31, 2005.

A) Pensions

The following table summarizes the net benefit plan expense:

Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------

Current Service
Cost $ 3 $ 1 $ 10 $ 5
Interest Cost 5 5 13 11
Expected Return
on Plan Assets (4) (4) (12) (10)
Expected Actuarial
Loss on Accrued
Benefit
Obligation 1 2 4 3
Expected
Amortization of
Past Service
Costs - - 1 1
Amortization of
Transitional
Obligation - (2) (1) (2)
Expense for
Defined
Contribution
Plan 9 6 20 16
-------------------------------------------------------------------------
Net Benefit Plan
Expense $ 14 $ 8 $ 35 $ 24
-------------------------------------------------------------------------
-------------------------------------------------------------------------

For the period ended September 30, 2006, contributions of $9 million have
been made to the defined benefit pension plans.

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

The following table summarizes the information about SAR's at
September 30, 2006:

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

Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 246,739 23.13
Exercised (242,739) 23.18
-------------------------------------------------------------------------
Outstanding, End of Period 4,000 20.25
-------------------------------------------------------------------------
Exercisable, End of Period 4,000 20.25
-------------------------------------------------------------------------
-------------------------------------------------------------------------

U.S. Dollar Denominated (US$)
Outstanding, Beginning of Year 319,511 14.33
Exercised (307,423) 14.41
-------------------------------------------------------------------------
Outstanding, End of Period 12,088 12.37
-------------------------------------------------------------------------
Exercisable, End of Period 12,088 12.37
-------------------------------------------------------------------------
-------------------------------------------------------------------------

For the period ended September 30, 2006, EnCana has recorded a reduction
of $1 million to compensation costs related to the outstanding SAR's
(2005 - costs of $19 million).

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

The following table summarizes the information about Tandem SAR's at
September 30, 2006:

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

Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 8,403,967 38.41
Granted 11,006,350 48.92
Exercised - SAR's (519,696) 34.66
Exercised - Options (29,484) 32.97
Forfeited (1,017,452) 42.84
-------------------------------------------------------------------------
Outstanding, End of Period 17,843,685 44.75
-------------------------------------------------------------------------
Exercisable, End of Period 2,018,553 37.23
-------------------------------------------------------------------------
-------------------------------------------------------------------------

For the period ended September 30, 2006, EnCana recorded compensation
costs of $28 million related to the outstanding TSAR's (2005 -
$86 million).

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

The following table summarizes the information about DSU's at
September 30, 2006:

Average
Outstanding Share
DSU's Price
-------------------------------------------------------------------------

Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 836,561 26.81
Granted, Directors 70,000 56.71
Exercised (52,562) 27.92
Units, in Lieu of Dividends 8,980 55.11
-------------------------------------------------------------------------
Outstanding, End of Period 862,979 29.46
-------------------------------------------------------------------------
Exercisable, End of Period 862,979 29.46
-------------------------------------------------------------------------
-------------------------------------------------------------------------

For the period ended September 30, 2006, EnCana recorded compensation
costs of $3 million related to the outstanding DSU's (2005 -
$26 million).

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

The following table summarizes the information about PSU's at
September 30, 2006:

Average
Outstanding Share
PSU's Price
-------------------------------------------------------------------------

Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 4,704,348 30.65
Granted 27,557 30.11
Exercised (239,794) 23.26
Forfeited (282,021) 31.35
-------------------------------------------------------------------------
Outstanding, End of Period 4,210,090 31.03
-------------------------------------------------------------------------
-------------------------------------------------------------------------

U.S. Dollar Denominated (US$)
Outstanding, Beginning of Year 739,649 25.22
Granted 3,621 25.56
Forfeited (156,652) 23.79
-------------------------------------------------------------------------
Outstanding, End of Period 586,618 25.61
-------------------------------------------------------------------------
-------------------------------------------------------------------------

For the period ended September 30, 2006, EnCana recorded compensation
costs of $14 million related to the outstanding PSU's (2005 -
$57 million).

At September 30, 2006, EnCana has approximately 5.5 million Common Shares
held in trust for issuance upon vesting of the PSU's.

13. PER SHARE AMOUNTS

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

Three Months Ended Nine Months Ended
-------------------------------------------------------
March 31, June 30, September 30, September 30,
-------------------------------------------------------
(millions) 2006 2006 2006 2005 2006 2005
-------------------------------------------------------------------------

Weighted Average
Common Shares
Outstanding - Basic 847.9 829.6 809.7 855.1 829.1 872.9
Effect of Dilutive
Securities 16.9 15.5 14.6 20.7 16.5 21.3
-------------------------------------------------------------------------
Weighted Average
Common Shares
Outstanding
- Diluted 864.8 845.1 824.3 875.8 845.6 894.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------

14. 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 Gain (Loss) on Risk Management Activities

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

Realized Gain (Loss)
-------------------------------------------------------
Three Months Ended Nine Months Ended
-------------------------------------------------------
September 30, September 30,
-------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------

Revenues, Net of
Royalties $ 199 $ (196) $ 153 $ (329)
Operating
Expenses and
Other 1 7 4 17
-------------------------------------------------------------------------
Gain (Loss) on
Risk Management
- Continuing
Operations 200 (189) 157 (312)
Gain (Loss) on
Risk Management
- Discontinued
Operations - (55) 4 (111)
-------------------------------------------------------------------------
$ 200 $ (244) $ 161 $ (423)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Unrealized Gain (Loss)
-------------------------------------------------------
Three Months Ended Nine Months Ended
-------------------------------------------------------
September 30, September 30,
-------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------

Revenues, Net
of Royalties $ 428 $ (810) $ 1,921 $ (1,457)
Operating
Expenses and
Other - 1 (2) 3
-------------------------------------------------------------------------
Gain (Loss) on
Risk Management
- Continuing
Operations 428 (809) 1,919 (1,454)
Gain (Loss) on
Risk Management
- Discontinued
Operations 5 (90) 27 (89)
-------------------------------------------------------------------------
$ 433 $ (899) $ 1,946 $ (1,543)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Amounts Recognized on Transition

Upon initial adoption of the current accounting policy for risk
management instruments 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.

At September 30, 2006, a net unrealized gain remains to be recognized
over the next three years as follows:

Unrealized
Gain
-------------------------------------------------------------------------
2006
Three months ended December 31, 2006 $ 6
-------------------------------------------------------------------------
Total remaining to be recognized in 2006 $ 6
-------------------------------------------------------------------------
-------------------------------------------------------------------------

2007 $ 15
2008 1
-------------------------------------------------------------------------
Total to be recognized $ 22
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Fair Value of Outstanding Risk Management Positions

The following table presents a reconciliation of the change in the
unrealized amounts from January 1, 2006 to September 30, 2006:

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

Fair Value of Contracts,
Beginning of Year $ (40) $ (640) $ -
Change in Fair Value of
Contracts in Place at
Beginning of Year and
Contracts Entered into
During 2006 - 2,089 2,089
Fair Value of Contracts in
Place at Transition Expired
During 2006 18 - 18
Fair Value of Contracts
Realized During 2006 - (161) (161)
-------------------------------------------------------------------------
Fair Value of Contracts
Outstanding $ (22) $ 1,288 $ 1,946
Unamortized Premiums Paid on
Options 190
-------------------------------------------------------------------------
Fair Value of Contracts and
Premiums Paid, End of Period $ 1,478
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Amounts Allocated to Continuing
Operations $ (22) $ 1,471 $ 1,919
Amounts Allocated to
Discontinued Operations - 7 27
-------------------------------------------------------------------------
$ (22) $ 1,478 $ 1,946
-------------------------------------------------------------------------
-------------------------------------------------------------------------

At September 30, 2006, the remaining net deferred amounts recognized on
transition and the risk management amounts are recorded in the
Consolidated Balance Sheet as follows:

As at
September 30,
2006
-------------------------------------------------------------------------

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

Accounts payable and accrued liabilities 18
Other liabilities 5
-------------------------------------------------------------------------
Net Deferred Gain - Continuing Operations $ 22
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Risk Management
Current asset $ 1,293
Long-term asset 243

Current liability 60
Long-term liability 5
-------------------------------------------------------------------------
Net Risk Management Asset - Continuing Operations 1,471
Net Risk Management Asset - Discontinued Operations 7
-------------------------------------------------------------------------
$ 1,478
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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

As at
September 30,
2006
-------------------------------------------------------------------------

Commodity Price Risk
Natural gas $ 1,420
Crude oil 47
Credit Derivatives (2)
Interest Rate Risk 6
-------------------------------------------------------------------------
Total Fair Value Positions - Continuing Operations 1,471
Total Fair Value Positions - Discontinued Operations 7
-------------------------------------------------------------------------
$ 1,478
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Information with respect to credit derivatives and interest rate risk
contracts in place at December 31, 2005 is disclosed in Note 16 to the
Company's annual audited Consolidated Financial Statements. No
significant new contracts have been entered into as at September 30,
2006.

Natural Gas

At September 30, 2006, the Company's gas risk management activities from
financial contracts had an unrealized gain of $1,332 million and a fair
market value position of $1,427 million. The contracts were as follows:

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

Sales Contracts
Fixed Price Contracts

NYMEX Fixed Price 495 2006 5.63 US$/Mcf $ (1)
Colorado
Interstate Gas
(CIG) 100 2006 4.44 US$/Mcf -
Houston Ship
Channel (HSC) 90 2006 5.08 US$/Mcf (2)
Other 91 2006 5.07 US$/Mcf 2

NYMEX Fixed Price 945 2007 8.85 US$/Mcf 390
Other 8 2007 8.97 US$/Mcf 5

Options
Purchased NYMEX
Put Options 2,687 2006 7.77 US$/Mcf 474

Purchased NYMEX
Put Options 240 2007 6.00 US$/Mcf 21

Basis Contracts
Fixed NYMEX to
AECO Basis 780 2006 (0.70) US$/Mcf (8)
Fixed NYMEX to
Rockies Basis 254 2006 (0.59) US$/Mcf 18
Fixed NYMEX to
CIG Basis 259 2006 (0.84) US$/Mcf 11
Other 145 2006 (0.29) US$/Mcf 2

Fixed NYMEX to
AECO Basis 747 2007 (0.72) US$/Mcf 75
Fixed NYMEX to
Rockies Basis 538 2007 (0.65) US$/Mcf 170
Fixed NYMEX to
CIG Basis 390 2007 (0.76) US$/Mcf 107
Fixed Rockies to
CIG Basis 12 2007 (0.10) US$/Mcf (1)

Fixed NYMEX to
AECO Basis 191 2008 (0.78) US$/Mcf 10
Fixed NYMEX to
Rockies Basis 162 2008 (0.59) US$/Mcf 39
Fixed NYMEX to
Rockies Basis 17% of NYMEX
(NYMEX Adjusted) 210 2008 US$/Mcf -
Fixed NYMEX to
CIG Basis 40 2008-2009 (0.68) US$/Mcf 13

Purchase Contracts
Fixed Price
Contracts
Waha Purchase 23 2006 5.32 US$/Mcf -
Other 10 2006 7.84 US$/Mcf (2)

Other 8 2007 7.84 US$/Mcf (1)
-------------------------------------------------------------------------
1,322
Other Financial Positions(*) 10
-------------------------------------------------------------------------
Total Unrealized Gain on Financial Contracts 1,332
Unamortized Premiums Paid on Options 95
-------------------------------------------------------------------------
Total Fair Value Positions $ 1,427
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Total Fair Value Positions - Continuing Operations $ 1,420
Total Fair Value Positions - Discontinued Operations 7
-------------------------------------------------------------------------
Total Fair Value Positions $ 1,427
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) Other financial positions are part of the ongoing operations of the
Company's proprietary production management activities.

Crude Oil

At September 30, 2006, the Company's oil risk management activities from
financial contracts had an unrealized loss of $(48) million and a fair
market value position of $47 million. The contracts were as follows:

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

Fixed WTI NYMEX
Price 15,000 2006 34.56 US$/bbl $ (41)
Unwind WTI NYMEX
Fixed Price (1,300) 2006 52.75 US$/bbl 1
Purchased WTI NYMEX
Put Options 59,000 2006 50.44 US$/bbl (8)
Purchased WTI NYMEX
Call Options (13,700) 2006 61.24 US$/bbl 1

Purchased WTI NYMEX
Put Options 91,500 2007 55.34 US$/bbl (10)
-------------------------------------------------------------------------
(57)
Other Financial Positions(*) 9
-------------------------------------------------------------------------
Total Unrealized Loss on Financial Contracts (48)
Unamortized Premiums Paid on Options 95
-------------------------------------------------------------------------
Total Fair Value Positions $ 47
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Total Fair Value Positions - Continuing Operations $ 47
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) Other financial positions are part of the ongoing operations of the
Company's proprietary production management.

15. CONTINGENCIES

Legal Proceedings

The Company is involved in various legal claims associated with the
normal course of operations. The Company believes it has made adequate
provision for such legal claims.

Discontinued Merchant Energy Operations

California

As disclosed previously, in July 2003, the Company's indirect wholly
owned U.S. marketing subsidiary, WD Energy Services Inc. ("WD"),
concluded a settlement with the U.S. Commodity Futures Trading Commission
("CFTC") of a previously disclosed CFTC investigation whereby WD agreed
to pay a civil monetary penalty in the amount of $20 million without
admitting or denying the findings in the CFTC's order.

EnCana Corporation and WD are defendants in a lawsuit filed by E. & J.
Gallo Winery in the United States District Court in California, further
described below. The Gallo lawsuit claims damages in excess of
$30 million. California law allows for the possibility that the amount of
damages assessed could be tripled.

Along with other energy companies, EnCana Corporation and WD are
defendants in several other lawsuits relating to sales of natural gas in
California from 1999 to 2002 (some of which are class actions and some of
which are brought by individual parties on their own behalf). As is
customary, these lawsuits do not specify the precise amount of damages
claimed. The Gallo and other California lawsuits contain allegations that
the defendants engaged in a conspiracy with unnamed competitors in the
natural gas and derivatives market in California in violation of U.S. and
California anti-trust and unfair competition laws.

In the Gallo action, the decision dealing with the issue of whether the
scope of the Federal Energy Regulatory Commission's exclusive
jurisdiction over natural gas prices precludes the plaintiffs from
maintaining their claims is on appeal to the United States Court of
Appeals for the Ninth Circuit. The Gallo lawsuit is stayed pending this
appeal.

Without admitting any liability in the lawsuits, WD has paid
$20.5 million to settle the class action lawsuits that were consolidated
in San Diego Superior Court. WD has also agreed to pay $2.4 million to
settle the class action lawsuits filed in the United States District
Court in California, without admitting any liability in the lawsuits,
subject to approval by the United States District Court. The individual
parties who had brought their own actions are not parties to this
settlement.

New York

WD was a defendant in a consolidated class action lawsuit filed in the
United States District Court in New York. The consolidated New York
lawsuit claims that the defendants' alleged manipulation of natural gas
price indices affected natural gas futures and option contracts traded on
the NYMEX from 2000 to 2002. EnCana Corporation was dismissed from the
New York lawsuit, leaving WD and several other companies unrelated to
EnCana Corporation as the remaining defendants. Without admitting any
liability in the lawsuit, WD agreed to pay $8.2 million to settle the New
York class action lawsuit. Final documentation and approval by the New
York District Court have been obtained and WD has paid the stated
settlement amount.

Based on the aforementioned settlements, a total of $31 million has been
expensed. EnCana Corporation and WD intend to vigorously defend against
the remaining outstanding claims; however, the Company cannot predict the
outcome of these proceedings or any future proceedings against the
Company, whether these proceedings would lead to monetary damages which
could have a material adverse effect on the Company's financial position,
or whether there will be other proceedings arising out of these
allegations.

Investor contact:
EnCana Corporate Finance


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 -0.540

NYSE $11.11 USD -0.510

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