EnCana generates 2005 cash flow of US$7.4 billion, or $8.35 per share – up 57 percent; Net earnings reach $3.43 billion

EnCana proved reserves additions replace 271% of production Proved reserves increase 18 percent with addition of 4.5 trillion cubic feet of gas equivalent

CALGARY, Feb. 15 /CNW/ - EnCana Corporation (TSX & NYSE: ECA) today
reports a 57 percent increase in 2005 cash flow per share to US$8.35 per share
diluted, or $7.4 billion, compared to 2004. Total operating earnings per share
in 2005 increased 73 percent to $3.64 per share diluted, or $3.24 billion. Net
earnings per share increased 3 percent to $3.85 per share diluted, or
$3.43 billion.
EnCana replaced 271 percent of its 2005 production and increased total
proved reserves by 18 percent to 18.5 trillion cubic feet of gas equivalent
(Tcfe) by adding 4.5 Tcfe, compared to production of 1.7 Tcfe.
"EnCana achieved record natural gas production, strong financial results,
solid operating performance and tremendous proved reserves additions in a year
characterized by robust prices and tough operating conditions," said Randy
Eresman, EnCana's President & Chief Executive Officer. "Our 2005 natural gas
sales were up 8 percent, while our key resource plays achieved 18 percent
year-over-year production growth."

Three-year reserves replacement cost averages $1.22 per thousand cubic
feet equivalent
"The difficult operating conditions that existed during most of 2005
continued through year-end. Despite these challenges, we continued to achieve
significant long-term value creation. Over the past three years, we have
sharpened our focus on North American unconventional resources through
increased investment in land and drilling, and by high-grading our portfolio
of assets through acquisitions and divestitures. With all the portfolio
changes we've undertaken, we believe the best indicator of our value creation
is our reserve replacement cost, which accounts for all of the reserves we
bought, sold and found with the drill bit, and best reflects the value
creation of our option value exploration program. In the past three years that
reserve replacement cost averaged a very attractive $1.22 per thousand cubic
feet equivalent. In 2005, we also had extremely strong reserves additions with
the drill bit alone, which averaged a finding and development cost of $1.29
per thousand cubic feet equivalent. Excluding bitumen additions, our 2005
finding and development costs averaged $1.93 per thousand cubic feet
equivalent. With our solid sales growth and double-digit reserves growth in
2005, EnCana is continuing to build momentum in the growth rate of net asset
value in every share by strengthening its unconventional resource base,"
Eresman said.

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. All prior-period share and per-share references have been adjusted to
reflect the two-for-one common share split which occurred in May 2005.
EnCana's natural gas liquids business was sold and is discontinued. The
company is reporting its Ecuador operations and its natural gas storage
business as discontinued because EnCana is in the process of selling them.
Total results, which include results from natural gas liquids, 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).

2005 Highlights

Financial
- Cash flow per share diluted increased 57 percent to $8.35
- Operating earnings per share diluted up 73 percent to $3.64
- Net earnings per share diluted up 3 percent to $3.85
- Generated $2.7 billion in free cash flow (as defined in Note 1 on
page 11)
- Return on capital employed of 17 percent
- Purchased 55.2 million EnCana shares at an average share price of
$34.85 under the Normal Course Issuer Bid
- Reduced shares outstanding by 4.5 percent

Operating
- Natural gas sales of 3.23 billion cubic feet per day (Bcf/d), up 8
percent
- Oil and natural gas liquids (NGLs) sales of 227,100 barrels per day
(bbls/d), down 13 percent
- Key resource play production up 18 percent; oilsands production
exceeded 50,000 bbls/d in December 2005
- Operating costs of 68 cents per thousand cubic feet equivalent (Mcfe)
- Upstream capital investment in continuing operations of $6.2 billion
- Net divestitures of $2.1 billion in non-core upstream assets,
resulting in net upstream capital investment of $4.1 billion

Reserves
- Drill bit additions and revisions of 4.8 Tcfe of proved reserves,
including 1.9 Tcfe of bitumen
- Proved reserves increased 18 percent to 18.5 Tcfe
- Reinstated 363 million barrels of bitumen to proved reserves
- Finding and development (F&D) costs averaged $1.29 per Mcfe,
excluding bitumen reinstatement
- Production replacement of 271 percent, excluding bitumen
reinstatement
- Average three-year reserve replacement cost of $1.22 per Mcfe

Strategic events
- Sold Gulf of Mexico assets for $2.1 billion
- Sold natural gas liquids business for $625 million
- Agreements reached to sell Ecuador assets for $1.42 billion and
Brazil oil discovery for $350 million
- Announced plans to expand in-situ oilsands production to more than
500,000 barrels per day by 2015

2006 objectives
- Grow sales from continuing operations between 4 and 9 percent,
natural gas sales between 6 and 10 percent
- Complete downstream initiative in support of high-growth in-situ
oilsands production to more than 500,000 barrels per day by 2015
- Complete sales of Ecuador and Brazil assets
- Complete the sale of natural gas storage business

2006 capital forecast trimmed $800 million; gas sales forecast reduced by
75 million cubic feet per day
Looking to 2006, the North American oil and gas industry continues to run
at a fevered pace. The inflationary pressures of 2005 are expected to continue
this year with cost inflation once again above 15 percent. Given these
circumstances, EnCana has decided to reduce drilling in areas where costs have
increased the most, resulting in a $500 million reduction in its previously-
announced 2006 upstream capital investment forecast. In addition, EnCana's
2005 gas sales exit rate was lower than planned due to fewer wells drilled by
year-end. The combined impact on 2006 gas sales is a reduction of about 75
million cubic feet per day from EnCana's previous forecast. The changes are
reflected in EnCana's updated corporate guidance. The $500 million upstream
capital reduction includes $200 million invested in late 2005 for acceleration
of drilling coalbed methane wells and expansion of in-situ oilsands programs,
and in 2006, $100 million for exploration and $200 million for development
programs. A further $300 million of capital previously assigned to building
the second segment of the Entrega Pipeline is not expected to be required as
EnCana has entered into an agreement to sell Entrega, which is expected to
close in the first quarter of 2006. In total, the company is reducing its 2006
capital investment plans by about $800 million, or 12 percent.

EnCana's 2006 natural gas sales expected to increase by about 8 percent
With fewer wells planned this year, EnCana's 2006 natural gas sales are
expected to increase 8 percent, at the midpoint of revised guidance - a growth
rate similar to what was achieved in 2005. EnCana's North American oil and
NGLs sales forecast is unchanged and remains about the same as 2005, with
additional volumes expected to come on stream near year-end from an expansion
of steam-assisted gravity drainage (SAGD) production at Foster Creek.

More than 90 percent of 2006 gas sales has floor price protection
To help assure strong financial performance, EnCana put in place, during the
fourth quarter of 2005, put options on about 1.6 billion cubic feet per day
of 2006 planned gas sales at an average strike price of NYMEX $8.42 per
thousand cubic feet. All in, about 93 percent of EnCana’s forecast 2006 gas
sales is hedged with a combination of put options and fixed price hedges with
an average price of NYMEX $7.30 per thousand cubic feet.

Net capital investment in 2006 forecast at $2.8 billion
EnCana has a series of non-core asset divestitures well underway that are
expected to generate between $3 billion and $3.4 billion this year, with
proceeds designated to share purchases and debt reduction. With a capital
investment forecast between $5.8 billion and $6.2 billion, the company expects
its 2006 net capital investment to be about $2.8 billion.

Corporate guidance updated
EnCana has updated its 2006 corporate guidance on its website:
www.encana.com. In addition to reflecting the most recent sales and capital
outlooks, the guidance indicates a reduction in cash tax expense, expressed as
percentage of pre-tax cash flow from continuing operations.

<<
-------------------------------------------------------------------------
Financial Summary - Total Consolidated
-------------------------------------------------------------------------
(for the period
ended December 31)
($ millions, except Q4 Q4 % %
per share amounts) 2005 2004 change 2005 2004 change
-------------------------------------------------------------------------
Cash flow 2,510 1,491 + 68 7,426 4,980 + 49
Per share diluted 2.88 1.60 + 80 8.35 5.32 + 57
-------------------------------------------------------------------------
Net earnings 2,366 2,580 - 8 3,426 3,513 - 2
Per share diluted 2.71 2.77 - 2 3.85 3.75 + 3
-------------------------------------------------------------------------
Operating earnings(1) 1,271 573 + 122 3,241 1,976 + 64
Per share diluted 1.46 0.62 + 135 3.64 2.11 + 73
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings Reconciliation Summary - Total Consolidated
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net earnings from
continuing
operations 1,869 1,055 + 77 2,829 2,093 + 35
Net earnings from
discontinued
operations 497 1,525 - 67 597 1,420 - 58
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Earnings 2,366 2,580 - 8 3,426 3,513 - 2
(Add back losses &
deduct gains)
Unrealized mark-to-
market hedging gain
(loss), after-tax 746 512 (277) (165)

Unrealized foreign
exchange gain (loss)
on translation of
U.S. dollar debt
issued in Canada,
after-tax (21) 131 92 229

Tax rate change - - - 109

Gain on divestitures
after-tax (2)370 (3)1,364 (2)370 (3)1,364
-------------------------------------------------------------------------
Operating earnings 1,271 573 + 122 3,241 1,976 + 64
Per share 1.46 0.62 + 135 3.64 2.11 + 73
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Total operating earnings is a non-GAAP measure that shows net
earnings excluding non-operating items such as the after-tax impacts
of a gain on the sale of discontinued operations, the after-tax
gain/loss of unrealized mark-to-market accounting for derivative
instruments, the after-tax gain/loss on translation of U.S. dollar
denominated debt issued in Canada and the effect of the reduction in
income tax rates.
(2) Gain on sale of natural gas liquids business
(3) Gain on sale of U.K. North Sea assets

Net earnings note:
The 2005 financial results include a one-time interest charge in the
third quarter of $79 million after-tax for the retirement of debt instruments
with an interest rate higher than current rates. Also, on September 13, 2005,
EnCana announced it had reached an agreement to sell all of its interest in
its Ecuador operations for approximately $1.42 billion, which is approximately
equivalent to the asset's net book value at July 1, 2005, the referenced
effective date of the transaction. All economic benefits occurring after the
July 1, 2005 effective date accrue to the purchaser. Included in net earnings
for 2005 is a provision of $234 million which has been recorded against the
net book value to recognize management's best estimate of the difference
between the selling price and the December 31, 2005 underlying accounting
value of the related investments, as required under Canadian generally
accepted accounting principles.

-------------------------------------------------------------------------
Sales & Drilling Summary
-------------------------------------------------------------------------
Total Consolidated
-------------------------------------------------------------------------
(for the period
ended December 31) Q4 Q4 % %
(After royalties) 2005 2004 change 2005 2004 change
-------------------------------------------------------------------------
Natural Gas sales
(MMcf/d) 3,326 3,109 + 7 3,227 2,998 + 8
-------------------------------------------------------------------------
Natural gas sales
per 1,000 shares
(Mcf) 358 312 + 15 1,356 1,192 + 14
-------------------------------------------------------------------------
Oil and NGLs sales
(bbls/d) 229,232 247,606 - 7 227,065 260,383 - 13
-------------------------------------------------------------------------
Oil and NGLs sales
per 1,000 shares
(Mcfe) 148 149 - 1 573 621 - 8
-------------------------------------------------------------------------
Total sales
(MMcfe/d) 4,701 4,595 + 2 4,589 4,560 + 1
-------------------------------------------------------------------------
Total sales per
1,000 shares (Mcfe) 506 461 + 10 1,929 1,813 + 6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net wells drilled 1,150 958 + 20 4,676 4,956 - 6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Continuing Operations
-------------------------------------------------------------------------
North America Natural
Gas sales (MMcf/d) 3,326 3,087 + 8 3,227 2,968 + 9
-------------------------------------------------------------------------
North America Oil
and NGLs (bbls/d) 159,289 159,470 - 156,000 166,417 - 6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total sales
(MMcfe/d) 4,282 4,044 + 6 4,163 3,966 + 5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net wells drilled 1,142 952 + 20 4,658 4,923 - 5
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Resource play growth
--------------------

Key resource play production growth up about 18 percent in 2005
EnCana's resource play production is approaching 80 percent of EnCana's
total production from continuing operations. The company's growth continues to
be led by the core of its operations, 10 key resource plays located from
northern British Columbia to Texas, which now represent about 55 percent of
total production from continuing operations. In 2005, gas and oil production
from these key resource plays increased about 18 percent compared to 2004.
Production from EnCana's Foster Creek steam-assisted gravity drainage project
averaged about 40,000 barrels per day in December, while total in-situ
oilsands production exceeded 50,000 barrels per day in December. Expansion at
Foster Creek during 2006 is expected to increase productive capacity to 60,000
barrels per day by year-end.


Growth from key North American resource plays

-------------------------------------------------------------------------

Daily Production
-----------------------------------------------------------
Resource Play 2005
-----------------------------------------------------------
2005 Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Natural Gas (MMcf/d)
Jonah 435 454 440 416 431
Piceance 307 326 302 302 300
East Texas 90 98 94 85 82
Fort Worth 70 88 66 63 61
Greater Sierra 219 226 225 228 195
Cutbank Ridge 92 125 105 80 56
CBM 57 77 62 51 38
Shallow Gas 625 625 616 633 625
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Oil (Mbbls/d)
Foster Creek 29 35 27 24 30
Pelican Lake 26 28 27 27 21
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total (MMcfe/d) 2,224 2,392 2,235 2,166 2,096
-------------------------------------------------------------------------
% change from prior
year's quarter 17.6 13.1 16.6 23.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
% change from prior period 17.5 7.0 3.2 3.3 3.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------


-------------------------------------------------------------------------

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


Drilling activity in key North American resource plays

----------------------------------------------------------
Resource Play Net Wells Drilled
------------------------------------------
2005 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
CBM 1,084 327 216 219 322 760
Shallow Gas 1,267 288 341 365 273 1,552
----------------------------------------------------------
----------------------------------------------------------
Oil
Foster Creek 39 13 14 2 10 11
Pelican Lake 52 - 3 33 16 92
----------------------------------------------------------
----------------------------------------------------------
Total net wells 3,254 803 780 833 838 3,058
----------------------------------------------------------
----------------------------------------------------------

Year-end 2005 proved reserves
-----------------------------

NOTE: Due to low commodity prices at the end of 2004 and in accordance
with regulatory requirements, EnCana removed its proved bitumen reserves from
its books. At the end of 2005, prices improved and all of those previously-
removed reserves were reinstated. The following reserves descriptions exclude
the impact of the 2004 bitumen revision.

EnCana achieved 18 percent proved reserves growth at competitive cost

Total proved reserves
- Proved reserves increased 18 percent to 18.5 Tcfe
- Proved reserves, excluding bitumen, increased 8 percent to 14.6 Tcfe
- Total proved reserves additions were 4.5 Tcfe, compared to production
of 1.7 Tcfe
- Total proved reserves additions, excluding bitumen, were 2.7 Tcfe,
compared to production of 1.6 Tcfe

Natural gas reserves
- Proved gas reserves increased 13 percent to 11.8 Tcf
- Proved gas additions were 2.5 Tcf, 100 percent organic
- Gas production replacement of 213 percent

Oil and NGLs reserves
- Proved oil and NGLs reserves increased 30 percent to 1.1 billion bbls,
100 percent organic
- Proved oil and NGLs additions were 340 million bbls compared to
production of 84 million bbls
- Oil and NGLs production replacement of 406 percent

Bitumen reserves (included in crude oil and NGLs)
- Bitumen reserves up 81 percent to 657 million bbls
- Proved bitumen additions were 309 million bbls compared to production
of 14 million bbls
- Reinstated 363 million bbls of bitumen reserves that were removed due
to low bitumen prices at year-end 2004

Reserves additions costs
- Three-year reserve replacement costs averages $1.22 per Mcfe
- Finding and development costs of $1.29 per Mcfe
- Finding and development costs excluding bitumen reserves additions of
$1.93 per Mcfe
- Reserve replacement costs of 91 cents per Mcfe
- Reserve replacement costs excluding bitumen reserves additions of
$1.37 per Mcfe

All of EnCana's proved reserves are evaluated by independent qualified
reserves evaluators.


-------------------------------------------------------------------------
2005 Proved Reserves Reconciliation
-------------------------------------------------------------------------
Crude oil and
Natural Gas
Natural gas Liquids
(Bcf) (MMbbls)

Canada
Canada USA Total Conven- Canada
tional Bitumen
-------------------------------------------------------------------------
Start of 2005 5,824 4,636 10,460 266.9 0.0
Revisions & improved
recovery 202 (260) (58) 47.5 174.6
Extensions & discoveries 1,289 1,252 2,541 14.1 134.0
Acquisitions 7 76 83 - -
Divestitures (30) (37) (67) (15.1) -
Production (775) (400) (1,175) (38.3) (13.9)
-------------------------------------------------------------------------
End of year before bitumen
reinstatement 6,517 5,267 11,784 275.1 294.7
Reinstatement of bitumen - - - - 362.7
-------------------------------------------------------------------------
End of 2005 6,517 5,267 11,784 275.1 657.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Developed 4,513 2,718 7,231 215.9 102.8
-------------------------------------------------------------------------
Undeveloped 2,004 2,549 4,553 59.2 554.6
-------------------------------------------------------------------------
Total 6,517 5,267 11,784 275.1 657.4
-------------------------------------------------------------------------
2005 Reserves Growth
-------------------------------------------------------------------------
Start of 2005 plus
reinstated bitumen reserves 5,824 4,636 10,460 266.9 362.7
-------------------------------------------------------------------------
End of 2005 6,517 5,267 11,784 275.1 657.4
-------------------------------------------------------------------------
% Change(1) + 12 + 14 + 13 + 3 + 81
-------------------------------------------------------------------------


-------------------------------------------------------------------------
2005 Proved Reserves Reconciliation
-------------------------------------------------------------------------
Crude oil and Natural Gas Liquids Total
(MMbbls) Bcfe

Canada USA Ecuador Total
Total
------------------------------------------------------------------------
Start of 2005 266.9 91.0 143.3 501.2 13,467
Revisions & improved
recovery 222.1 (3.2) 8.1 227.0 1,305
Extensions & discoveries 148.1 8.9 10.2 167.2 3,544
Acquisitions - 0.4 - 0.4 85
Divestitures (15.1) (39.0) - (54.1) (392)
Production (52.2) (5.0) (26.6) (83.8) (1,678)
------------------------------------------------------------------------
End of year before bitumen
reinstatement 569.8 53.1 135.0 757.9 16,331
Reinstatement of bitumen 362.7 - - 362.7 2,176
------------------------------------------------------------------------
End of 2005 932.5 53.1 135.0 1,120.6 18,507
------------------------------------------------------------------------
------------------------------------------------------------------------
Developed 318.7 32.2 104.0 454.9 9,960
------------------------------------------------------------------------
Undeveloped 613.8 20.9 31.0 665.7 8,547
------------------------------------------------------------------------
Total 932.5 53.1 135.0 1,120.6 18,507
-------------------------------------------------------------------------
2005 Reserves Growth
-------------------------------------------------------------------------
Start of 2005 plus
reinstated bitumen reserves 629.6 91.0 143.3 863.9(1) 15,643
-------------------------------------------------------------------------
End of 2005 932.5 53.1 135.0 1,120.6 18,507
-------------------------------------------------------------------------
% Change(1) + 48 - 42 - 6 + 30 + 18
-------------------------------------------------------------------------

(1) EnCana's growth in proved reserves in 2005 is expressed as the
percentage change from the start to the end of the year. For bitumen
reserves reporting, all of the reserves that were revised downward at
the end of 2004 were reinstated at the end of 2005, due to favourable
commodity prices. Therefore, EnCana's 2005 growth in crude oil and
NGLs reserves is based on a start of year balance that includes its
conventional oil reserves of 501.2 million barrels, plus its
362.7 million barrels of reinstated bitumen reserves for a total oil
start of year balance of 863.9 million barrels.


Bitumen reserves add to long life potential
EnCana's proved bitumen reserves of 657 million barrels are estimated to
be sufficient to sustain approximately 30 years of anticipated production at
Foster Creek's forecast 2006 year-end productive capacity of 60,000 barrels
per day. The company believes that significant future reserve addition
potential exists associated with EnCana's previously announced in-situ
oilsands development plans, which have the potential to increase current
production about 10-fold to more than 500,000 barrels per day by 2015.

EnCana continues to grow reserves at competitive costs
"EnCana continues to deliver solid reserves growth at competitive costs.
For the past three years, EnCana's production replacement has averaged more
than 200 percent and even in 2005's high cost environment, our year-end
finding and development costs were $1.29 per thousand cubic feet equivalent.
When you look at this performance in light of our 2005 netback of $5.21 per
thousand cubic feet equivalent, you can see that EnCana's significant proved
reserves have added substantial value," Eresman said.

-------------------------------------------------------------------------
Proved Reserves Costs
-------------------------------------------------------------------------
Cumulative
Capital investment ($ millions) 2005 2004 2003 2003-05
-------------------------------------------------------------------------
Finding and development 6,231 4,792 4,095 15,118
Acquisitions 472 3,469 558 4,499
Divestitures (2,552) (3,827) (312) (6,691)
-------------------------------------------------------------------------
Net capital investment 4,151 4,434 4,341 12,926
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total reserve additions (Bcfe) 4,542 3,163 2,893 10,598
-------------------------------------------------------------------------
-------------------------------------------------------------------------
3-year
average
-------------------------------------------------------------------------
Reserve replacement cost ($/Mcfe) 0.91 1.40 1.50 1.22
-------------------------------------------------------------------------
Finding and development cost 1.29 1.44 1.43 1.37
-------------------------------------------------------------------------
Finding, development and
acquisition cost 1.36 1.70 1.46 1.51
-------------------------------------------------------------------------
-------------------------------------------------------------------------

NOTE: This table excludes the impact of the bitumen reserves revisions of
2004 and bitumen reserves reinstatement in 2005.

2005 natural gas and oil prices
-------------------------------

-------------------------------------------------------------------------
2005 Natural Gas and Oil Prices
(excludes financial hedging)
-------------------------------------------------------------------------
Q4 Q4 % %
Natural gas ($/Mcf) 2005 2004 Change 2005 2004 Change
NYMEX Price 12.96 7.10 + 83 8.62 6.14 + 40
Realized Gas Price 10.29 6.08 + 69 7.46 5.47 + 36
-------------------------------------------------------------------------
Oil and NGLs ($/bbl)
WTI Price 60.05 48.27 + 24 56.70 41.47 + 37
Bow River Differential 22.79 19.14 + 19 19.64 12.82 + 53
Realized Liquids Price 37.16 30.20 + 23 36.17 28.77 + 26
NAPO Differential 23.38 19.17 + 22 18.37 14.33 + 28
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Price risk management
Detailed risk management positions at December 31, 2005 are presented in
Note 13 to the 2005 unaudited consolidated financial statements. In 2005,
EnCana's financial price risk management measures resulted in realized losses
of approximately $527 million after-tax, comprised of a $288 million loss on
oil hedges, a $261 million loss on gas hedges and a $22 million gain on other
hedges. The company's hedging strategy currently employs primarily put options
to protect against downside risk without limiting upside in a rising price
environment.

More than 90 percent of 2006 gas sales has downside price protection
In the fourth quarter of 2005, EnCana added approximately 1.6 billion
cubic feet per day of NYMEX put options at an average strike price of $8.42
per thousand cubic feet. EnCana now has approximately 71 percent of 2006
forecast gas sales hedged with put options with an average strike price of
$7.76 per thousand cubic feet. Another 22 percent of 2006 forecast gas
production is hedged with fixed price instruments with an average price of
$5.83 per thousand cubic feet. Most of these fixed price positions relate to
hedges initiated in 2004 when EnCana acquired Tom Brown, Inc. (TBI). The TBI
hedges expire at the end of 2006. Of EnCana's 2006 forecast oil and NGLs
sales, about 91 percent is exposed to price upside, while about 45 percent has
downside protection.
North American natural gas prices are impacted by volatile pricing
disconnects caused primarily by transportation constraints between producing
regions and consuming regions. These price discounts are called basis
differentials. For 2006 EnCana has hedged 100 percent of its U.S. Rockies
basis differential at $0.65 per thousand cubic feet. In Canada for 2006,
EnCana has hedged 35 percent of its AECO basis differential at $0.69 per
thousand cubic feet and has an additional 39 percent subject to transport and
aggregator contracts.

Operations
----------

Operational challenges in 2005
Throughout 2005, the operational challenges facing the North American
natural gas and oil industry intensified. With record prices for each
commodity, the drive for new supplies increased the demand and prices for
rigs. This high activity level sparked industry inflation of 15 to 30 percent
for overall goods and services. With EnCana's large volume purchasing power
and longer term planning initiatives, the company contained its inflation to
the low end of the industry range in 2005.
On top of a hectic industry came unusual weather events rarely seen in
Alberta, the heartland of EnCana's Canadian operations. Three major rain
storms in June flooded rivers, homes and businesses and brought many of
EnCana's drilling operations to a standstill. The wettest June ever recorded
in Alberta caused delays through the year - a total of about two to three
months of down time in field operations. The activity-related operational
delays were widespread in 2005, whereas the poorer operating conditions
affected EnCana more specifically in some of its most active areas. By
year-end, EnCana had drilled about 80 percent of its planned gas wells and
achieved about 80 percent of its forecast gas production additions (additions
to offset decline plus additions to create planned growth). Although the
company was unable to complete its entire gas drilling program in 2005 due to
the highly unusual conditions, the estimated outlook for the company's base
production and new well additions remains solid and predictable.

2005 capital investment
EnCana's upstream capital investment of about $6.2 billion was
approximately $600 million higher than EnCana's corporate guidance. This
increase in capital was due principally to the following: a $100 million
increase in land acquisitions, largely Central Alberta lands purchased in
December; $200 million due to acceleration of drilling of coalbed methane
wells and the expansion of in-situ oilsands projects; $200 million due to
higher inflation and inefficiencies generated by the pace of field activity
and weather related delays; and $100 million due to the impact of foreign
exchange.

Bringing new drilling equipment to market
"As we move into 2006, the North American operating market remains
robust. We currently have about 145 rigs drilling across the continent. In an
effort to help alleviate the pressure on equipment, we have negotiated
long-term contracts that are intended to add about 60 new fit-for-purpose rigs
to our contract fleet. We also have contracted fixed prices for about
50 percent of our planned 2006 expenditures. And we are investing in the human
resources to help staff the equipment with financial support to post-secondary
institutions training new field workers," Eresman said.

EnCana expands resource play concept to Europe
On February 7, 2006, the Government of France granted EnCana a
100 percent interest in a permit to explore about 860,000 acres of land in
southwest France. EnCana plans a multi-well exploration drilling program on
the Foix Permit lands to identify the potential for natural gas resource play
development.

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

Randy Eresman takes over as President & Chief Executive Officer; Brian
Ferguson named CFO
On January 1, 2006, Randy Eresman became President & Chief Executive
Officer and a Director of EnCana. On December 14, 2005, EnCana announced that
effective March 1, 2006, Brian Ferguson, currently Executive Vice-President,
Corporate Development, will succeed John Watson as Executive Vice-President &
Chief Financial Officer.

Additional EnCana executive appointments
On January 1, 2006, Hayward Walls, previously EnCana's Vice-President of
Information Technology and Chief Information Officer (CIO), was appointed
Executive Vice-President, Corporate Services, replacing Drude Rimell, who
retired. Walls continues as CIO.
In early January, Randy Eresman announced other executive team
appointments. In order to expand expertise across the organization and broaden
the knowledge and experience among the company's leaders, as of March 1, 2006,
Roger Biemans, currently President of EnCana Oil & Gas (USA) Inc., is
appointed President of the Canadian Plains Region. Jeff Wojahn, currently
President of Canadian Plains Region, is appointed President, EnCana Oil & Gas
(USA) Inc. Don Swystun, currently President of Ecuador Region, is appointed
Executive Vice-President, Corporate Development, where he will lead
acquisitions, divestitures and reserves. Sherri Brillon, Vice-President,
Strategic Planning and Portfolio Management, joined EnCana's executive team on
January 1, 2006.

Quarterly dividend of 7.5 cents per share declared
EnCana's board of directors has declared a quarterly dividend of
7.5 cents per share which is payable on March 31, 2006 to common shareholders
of record as of March 15, 2006.

EnCana Normal Course Issuer Bid purchases
In 2005, under its previous Normal Course Issuer Bid, EnCana purchased
about 55.2 million common shares, representing approximately 6.1 percent of
the company's outstanding shares on December 31, 2004, at an average price of
approximately $34.85 per common share. To date in 2006, EnCana has purchased
6.8 million common shares under its current Normal Course Issuer Bid, which
was renewed in October 2005, for approximately $314 million at an average
price of $46.34 per share. Under the renewed bid, EnCana may purchase for
cancellation over a period ending October 30, 2006 up to 85,603,640 of its
common shares, representing 10 percent of the public float of approximately
856,036,400 common shares outstanding as at October 25, 2005.

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

EnCana targets a net debt-to-capitalization ratio between 30 and
40 percent. At December 31, 2005, the company's net debt-to-capitalization
ratio was 33:67. EnCana's net debt-to-EBITDA multiple, on a trailing 12-month
basis, was 1.1 times.

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

EnCana Corporation will host a conference call today, Wednesday,
February 15, 2006 starting at 11 a.m., Mountain Time (1 p.m. Eastern
Time), to discuss EnCana's fourth quarter and year-end 2005 financial and
operating results.

To participate, please dial (913) 981-4911 approximately 10 minutes prior
to the conference call. An archived recording of the call will be
available from approximately 3 p.m. MT on February 15 until midnight
February 22, 2006 by dialling (888) 203-1112 or (719) 457-0820 and
entering access code 8924369.

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.
-------------------------------------------------------------------------


NOTE 1: Non-GAAP measures
This news release contains references to cash flow, total operating
earnings and free cash flow.

- Total operating earnings is a non-GAAP measure that shows net
earnings excluding non-operating items such as the after-tax
impacts of a gain on the sale of discontinued operations, the
after-tax gain/loss of unrealized mark-to-market accounting for
derivative instruments, the after-tax gain/loss on translation of
U.S. dollar denominated debt issued in Canada and the effect of
the reduction in income tax rates.

Management believes these items reduce the comparability of the company's
underlying financial performance between periods. The majority of the
unrealized gains/losses that relate to U.S. dollar debt issued in Canada are
for debt with maturity dates in excess of five years.

- Free cash flow is a non-GAAP measure that EnCana defines as cash
flow in excess of capital investment and net acquisitions and
divestitures.

These measures have been described and presented in this news release in
order to provide shareholders and potential investors with additional
information regarding EnCana's liquidity and its ability to generate funds to
finance its operations.

EnCana Corporation
With an enterprise value of approximately US$43 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. The application of technology
to unlock the huge resource potential of these plays typically results in
continuous increases in production and reserves and decreases in costs over
multiple decades of resource play life. EnCana common shares trade on the
Toronto and New York stock exchanges under the symbol ECA.

RESERVE COST DEFINITIONS - Production replacement is calculated by
dividing reserve additions by production in the same period. Reserve additions
over a given period, in this case 2005, are calculated by summing one or more
of revisions and improved recovery, extensions and discoveries, acquisitions
and divestitures. Reserve replacement cost is calculated by dividing total
capital invested in finding, development and acquisitions net of divestitures
by reserve additions in the same period. Finding and development cost is
calculated by dividing total capital invested in finding and development
activities by additions to proved reserves, before acquisitions and
divestitures, which is the sum of revisions, extensions and discoveries.
Finding, development and acquisition cost is calculated by dividing total
capital invested in finding, development and acquisition activities by
additions to proved reserves, before divestitures, which is the sum of
revisions, extensions, discoveries and acquisitions. Proved reserves added in
2005 included both developed and undeveloped quantities. Additions to EnCana's
proved undeveloped reserves were consistent with EnCana's resource play focus.
The company estimates that approximately two-thirds of its proved undeveloped
reserves will be developed within the next three years. 2005 finding,
development and acquisition capital includes investment in long lead time
projects. EnCana uses the aforementioned metrics as indicators of relative
performance, along with a number of other measures. Many performance measures
exist, all measures have limitations and historical measures are not
necessarily indicative of future performance.

ADVISORY REGARDING RESERVES DATA AND OTHER OIL AND GAS INFORMATION -
EnCana's disclosure of reserves data and other oil and gas information is made
in reliance on an exemption granted to EnCana by Canadian securities
regulatory authorities which permits it to provide such disclosure in
accordance with U.S. disclosure requirements. The information provided by
EnCana may differ from the corresponding information prepared in accordance
with Canadian disclosure standards under National Instrument 51-101
(NI 51-101). EnCana's reserves quantities represent net proved reserves
calculated using the standards contained in Regulation S-X of the U.S.
Securities and Exchange Commission. Further information about the differences
between the U.S. requirements and the NI 51-101 requirements is set forth
under the heading "Note Regarding Reserves Data and Other Oil and Gas
Information" in EnCana's Annual Information Form.

In this news release, certain crude oil and NGLs volumes have been
converted to cubic feet equivalent (cfe) on the basis of one barrel (bbl) to
six thousand cubic feet (Mcf). Also, certain natural gas volumes have been
converted to barrels of oil equivalent (BOE) on the same basis. BOE and cfe
may be misleading, particularly if used in isolation. A conversion ratio of
one bbl to six Mcf is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not represent 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; planned divestitures of the Ecuador assets
and other non-core assets and the company's natural gas storage business; the
expected proceeds from planned divestitures; planned expansion of in-situ
oilsands production; anticipated crude oil and natural gas prices; anticipated
expansion and production at Foster Creek; anticipated drilling on the Foix
Permit lands; anticipated drilling inventory; expected proportion of total
production and cash flows contributed by natural gas; anticipated success of
EnCana's market risk mitigation strategy and EnCana's ability to participate
in commodity price upside and to protect against high U.S. Rockies gas price
basis differentials; anticipated purchases pursuant to the Normal Course
Issuer Bid; estimated recycle ratios; potential demand for natural gas;
anticipated production in 2006 and beyond; anticipated drilling; potential
capital expenditures and investment; potential oil, natural gas and NGLs sales
in 2006 and beyond; anticipated costs and inflationary pressures; 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 reserves estimates and
estimates of recoverable quantities of oil, natural gas and liquids from
resource plays and other sources not currently classified as proved reserves;
risks associated with technology; the company's ability to replace and expand
oil and gas reserves; its ability to generate sufficient cash flow from
operations to meet its current and future obligations; its ability to access
external sources of debt and equity capital; the timing and the costs of well
and pipeline construction; the company's ability to secure adequate product
transportation; changes in environmental and other regulations or the
interpretations of such regulations; political and economic conditions in the
countries in which the company operates, including Ecuador; the risk of war,
hostilities, civil insurrection and instability affecting countries in which
the company operates and terrorist threats; risks associated with existing and
potential future lawsuits and regulatory actions made against the company; and
other risks and uncertainties described from time to time in the reports and
filings made with securities regulatory authorities by EnCana. Although EnCana
believes that the expectations represented by such forward-looking statements
are reasonable, there can be no assurance that such expectations will prove to
be correct. Readers are cautioned that the foregoing list of important factors
is not exhaustive.
Furthermore, the forward-looking statements contained in this news
release are made as of the date of this news release, and EnCana does not
undertake any obligation to update publicly or to revise any of the included
forward-looking statements, whether as a result of new information, future
events or otherwise. The forward-looking statements contained in this news
release are expressly qualified by this cautionary statement.


Interim Consolidated Financial Statements
(unaudited)
For the period ended December 31, 2005


EnCana Corporation

U.S. DOLLARS

Notice to Reader

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



CONSOLIDATED STATEMENT OF EARNINGS (unaudited)

Three Months Ended Twelve Months Ended
December 31, December 31,
($ millions, except -------------------------------------------
per share amounts) 2005 2004 2005 2004
-------------------------------------------------------------------------

REVENUES,
NET OF ROYALTIES (Note 2)
Upstream $ 3,452 $ 2,003 $ 10,465 $ 7,256
Market Optimization 1,417 929 4,267 3,200
Corporate
- Unrealized gain
(loss) on risk
management 991 610 (466) (198)
- Other - - - 1
-------------------------------------------------------------------------
5,860 3,542 14,266 10,259

EXPENSES (Note 2)
Production and
mineral taxes 162 95 453 311
Transportation
and selling 138 106 538 490
Operating 452 309 1,438 1,099
Purchased product 1,376 905 4,159 3,092
Depreciation,
depletion and
amortization 751 636 2,769 2,379
Administrative 63 61 268 197
Interest, net (Note 5) 104 114 524 398
Accretion of
asset retirement
obligation (Note 9) 10 6 37 22
Foreign exchange
(gain) loss, net (Note 6) 37 (199) (24) (412)
Stock-based
compensation -
options (Note 10) 3 3 15 17
(Gain) on
divestitures (Note 4) - (24) - (59)
-------------------------------------------------------------------------
3,096 2,012 10,177 7,534
-------------------------------------------------------------------------
NET EARNINGS BEFORE
INCOME TAX 2,764 1,530 4,089 2,725
Income tax
expense (Note 7) 895 475 1,260 632
-------------------------------------------------------------------------
NET EARNINGS FROM
CONTINUING
OPERATIONS 1,869 1,055 2,829 2,093
NET EARNINGS FROM
DISCONTINUED
OPERATIONS (Note 3) 497 1,525 597 1,420
-------------------------------------------------------------------------
NET EARNINGS $ 2,366 $ 2,580 $ 3,426 $ 3,513
-------------------------------------------------------------------------
-------------------------------------------------------------------------

NET EARNINGS FROM
CONTINUING
OPERATIONS PER
COMMON SHARE (Note 12)
Basic $ 2.19 $ 1.15 $ 3.26 $ 2.27
Diluted $ 2.14 $ 1.13 $ 3.18 $ 2.24
-------------------------------------------------------------------------
-------------------------------------------------------------------------

NET EARNINGS PER
COMMON SHARE (Note 12)
Basic $ 2.77 $ 2.81 $ 3.95 $ 3.82
Diluted $ 2.71 $ 2.77 $ 3.85 $ 3.75
-------------------------------------------------------------------------
-------------------------------------------------------------------------


CONSOLIDATED STATEMENT OF RETAINED EARNINGS (unaudited)

Twelve Months Ended
December 31,
---------------------
($ millions) 2005 2004
-------------------------------------------------------------------------

RETAINED EARNINGS, BEGINNING OF YEAR $ 7,935 $ 5,276
Net Earnings 3,426 3,513
Dividends on Common Shares (238) (183)
Charges for Normal Course Issuer Bid (Note 10) (1,642) (671)
-------------------------------------------------------------------------
RETAINED EARNINGS, END OF YEAR $ 9,481 $ 7,935
-------------------------------------------------------------------------
-------------------------------------------------------------------------

See accompanying Notes to Consolidated Financial Statements.



CONSOLIDATED BALANCE SHEET (unaudited)

As at As at
December 31, December 31,
($ millions) 2005 2004
-------------------------------------------------------------------------

ASSETS
Current Assets
Cash and cash equivalents $ 105 $ 593
Accounts receivable and accrued
revenues 1,851 1,566
Risk management (Note 13) 495 317
Inventories 103 58
Assets of discontinued operations (Note 3) 1,050 971
-------------------------------------------------------------------------
3,604 3,505
Property, Plant and Equipment, net (Note 2) 24,881 22,503
Investments and Other Assets 496 334
Risk Management (Note 13) 530 87
Assets of Discontinued Operations (Note 3) 2,113 2,325
Goodwill 2,524 2,459
-------------------------------------------------------------------------
(Note 2) $ 34,148 $ 31,213
-------------------------------------------------------------------------
-------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued
liabilities $ 2,741 $ 1,742
Income tax payable 392 357
Risk management (Note 13) 1,227 224
Liabilities of discontinued
operations (Note 3) 438 436
Current portion of long-term debt (Note 8) 73 188
-------------------------------------------------------------------------
4,871 2,947
Long-Term Debt (Note 8) 6,703 7,742
Other Liabilities 93 118
Risk Management (Note 13) 102 192
Asset Retirement Obligation (Note 9) 816 611
Liabilities of Discontinued
Operations (Note 3) 267 213
Future Income Taxes 5,289 5,082
-------------------------------------------------------------------------
18,141 16,905
-------------------------------------------------------------------------
Shareholders' Equity
Share capital (Note 10) 5,131 5,299
Share options, net - 10
Paid in surplus 133 28
Retained earnings 9,481 7,935
Foreign currency translation
adjustment 1,262 1,036
-------------------------------------------------------------------------
16,007 14,308
-------------------------------------------------------------------------
$ 34,148 $ 31,213
-------------------------------------------------------------------------
-------------------------------------------------------------------------

See accompanying Notes to Consolidated Financial Statements.



CONSOLIDATED STATEMENT OF CASH FLOWS (unaudited)

Three Months Ended Twelve Months Ended
December 31, December 31,
-------------------------------------------
($ millions) 2005 2004 2005 2004
-------------------------------------------------------------------------

OPERATING ACTIVITIES
Net earnings from
continuing
operations $ 1,869 $ 1,055 $ 2,829 $ 2,093
Depreciation,
depletion and
amortization 751 636 2,769 2,379
Future income
taxes (Note 7) 717 422 56 73
Cash tax on sale
of assets (13) - 578 -
Unrealized (gain)
loss on risk
management (Note 13) (985) (610) 469 191
Unrealized
foreign exchange
loss (gain) 28 (163) (50) (285)
Accretion of
asset retirement
obligation (Note 9) 10 6 37 22
(Gain) on
divestitures (Note 4) - (24) - (59)
Other 13 36 274 88
-------------------------------------------------------------------------
Cash flow from
continuing
operations 2,390 1,358 6,962 4,502
Cash flow from
discontinued
operations 120 133 464 478
-------------------------------------------------------------------------
Cash flow 2,510 1,491 7,426 4,980
Net change in
other assets
and liabilities (108) (105) (281) (176)
Net change in
non-cash working
capital from
continuing
operations 1,165 1,936 497 1,565
Net change in
non-cash working
capital from
discontinued
operations (140) (2,034) (212) (1,778)
-------------------------------------------------------------------------
3,427 1,288 7,430 4,591
-------------------------------------------------------------------------

INVESTING ACTIVITIES
Business
combination with
Tom Brown, Inc. - - - (2,335)
Capital
expenditures (Note 2) (2,362) (1,489) (6,925) (4,763)
Proceeds on
disposal of
assets (Note 4) 30 94 2,523 1,456
Cash tax on
sale of assets 13 - (578) -
Equity investments - (5) - 47
Net change in
investments
and other (161) 73 (109) 44
Net change in
non-cash working
capital from
continuing
operations 165 71 330 (29)
Discontinued
operations 572 1,951 239 1,321
-------------------------------------------------------------------------
(1,743) 695 (4,520) (4,259)
-------------------------------------------------------------------------

FINANCING ACTIVITIES
Net (repayment)
issuance of
revolving
long-term debt (1,513) 287 (538) 72
Repayment of
long-term debt (145) (1,005) (1,104) (2,759)
Issuance of
long-term debt - - 429 3,761
Issuance of
common shares (Note 10) 24 97 294 281
Purchase of
common shares (Note 10) - (774) (2,114) (1,004)
Dividends on
common shares (64) (46) (238) (183)
Other (17) 6 (125) (5)
-------------------------------------------------------------------------
(1,715) (1,435) (3,396) 163
-------------------------------------------------------------------------

DEDUCT: FOREIGN
EXCHANGE LOSS ON
CASH AND CASH
EQUIVALENTS HELD
IN FOREIGN CURRENCY 1 6 2 6
-------------------------------------------------------------------------

(DECREASE) INCREASE
IN CASH AND CASH
EQUIVALENTS (32) 542 (488) 489
CASH AND CASH
EQUIVALENTS,
BEGINNING OF YEAR 137 51 593 104
-------------------------------------------------------------------------
CASH AND CASH
EQUIVALENTS,
END OF YEAR $ 105 $ 593 $ 105 $ 593
-------------------------------------------------------------------------
-------------------------------------------------------------------------

See accompanying Notes to Consolidated Financial Statements.



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

1. BASIS OF PRESENTATION

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

The interim Consolidated Financial Statements have been prepared
following the same accounting policies and methods of computation as the
annual audited Consolidated Financial Statements for the year ended
December 31, 2004. The disclosures provided below are incremental to
those included with the annual audited Consolidated Financial Statements.
The interim Consolidated Financial Statements should be read in
conjunction with the annual audited Consolidated Financial Statements and
the notes thereto for the year ended December 31, 2004.

2. SEGMENTED INFORMATION

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

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

- 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 3.

Results of Continuing Operations (For the three months ended December 31)


Upstream Market Optimization
-------------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 3,452 $ 2,003 $ 1,417 $ 929
Expenses
Production and mineral taxes 162 95 - -
Transportation and selling 135 102 3 4
Operating 415 286 32 20
Purchased product - - 1,376 905
Depreciation, depletion
and amortization 731 614 1 5
-------------------------------------------------------------------------
Segment Income (Loss) $ 2,009 $ 906 $ 5 $ (5)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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

Revenues, Net of Royalties $ 991 $ 610 $ 5,860 $ 3,542
Expenses
Production and mineral taxes - - 162 95
Transportation and selling - - 138 106
Operating 5 3 452 309
Purchased product - - 1,376 905
Depreciation, depletion
and amortization 19 17 751 636
-------------------------------------------------------------------------
Segment Income (Loss) $ 967 $ 590 2,981 1,491
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Administrative 63 61
Interest, net 104 114
Accretion of asset
retirement obligation 10 6
Foreign exchange loss
(gain), net 37 (199)
Stock-based compensation -
options 3 3
(Gain) on divestitures - (24)
-------------------------------------------------------------------------
217 (39)
-------------------------------------------------------------------------
Net Earnings Before Income Tax 2,764 1,530
Income tax expense 895 475
-------------------------------------------------------------------------
Net Earnings From Continuing
Operations $ 1,869 $ 1,055
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(*) For the three months ended December 31, the pre-tax unrealized gain
(loss) on risk management is recorded in the Consolidated Statement
of Earnings as follows (see Note 13):

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

Revenues, Net of Royalties - Corporate $ 991 $ 610
Operating Expenses and Other - Corporate 6 -
-------------------------------------------------------------------------
Total Unrealized Gain on Risk Management
before-tax - Continuing Operations $ 985 $ 610
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Results of Continuing Operations (For the three months ended December 31)


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

Revenues, Net of Royalties $ 2,258 $ 1,313 $ 1,106 $ 628
Expenses
Production and mineral taxes 29 26 133 69
Transportation and selling 87 75 48 27
Operating 227 180 64 39
Depreciation, depletion and
amortization 511 455 166 145
-------------------------------------------------------------------------
Segment Income $ 1,404 $ 577 $ 695 $ 348
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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

Revenues, Net of Royalties $ 88 $ 62 $ 3,452 $ 2,003
Expenses
Production and mineral taxes - - 162 95
Transportation and selling - - 135 102
Operating 124 67 415 286
Depreciation, depletion
and amortization 54 14 731 614
-------------------------------------------------------------------------
Segment Income (Loss) $ (90) $ (19) $ 2,009 $ 906
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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


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

Revenues, Net
of Royalties $ 1,852 $ 1,041 $ 1,041 $ 578 $ 2,893 $ 1,619
Expenses
Production and
mineral taxes 20 19 127 63 147 82
Transportation
and selling 72 74 48 27 120 101
Operating 144 103 64 39 208 142
-------------------------------------------------------------------------
Operating Cash
Flow $ 1,616 $ 845 $ 802 $ 449 $ 2,418 $ 1,294
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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

Revenues, Net
of Royalties $ 406 $ 272 $ 65 $ 50 $ 471 $ 322
Expenses
Production and
mineral taxes 9 7 6 6 15 13
Transportation
and selling 15 1 - - 15 1
Operating 83 77 - - 83 77
-------------------------------------------------------------------------
Operating Cash
Flow $ 299 $ 187 $ 59 $ 44 $ 358 $ 231
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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

Revenues, Net of Royalties $ 88 $ 62 $ 3,452 $ 2,003
Expenses
Production and mineral taxes - - 162 95
Transportation and selling - - 135 102
Operating 124 67 415 286
-------------------------------------------------------------------------
Operating Cash Flow $ (36) $ (5) $ 2,740 $ 1,520
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Results of Continuing Operations
(For the twelve months ended December 31)


Upstream Market Optimization
-------------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 10,465 $ 7,256 $ 4,267 $ 3,200
Expenses
Production and mineral taxes 453 311 - -
Transportation and selling 525 472 13 18
Operating 1,351 1,026 85 74
Purchased product - - 4,159 3,092
Depreciation, depletion
and amortization 2,688 2,271 8 47
-------------------------------------------------------------------------
Segment Income (Loss) $ 5,448 $ 3,176 $ 2 $ (31)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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

Revenues, Net of Royalties $ (466) $ (197) $ 14,266 $ 10,259
Expenses
Production and mineral taxes - - 453 311
Transportation and selling - - 538 490
Operating 2 (1) 1,438 1,099
Purchased product - - 4,159 3,092
Depreciation, depletion
and amortization 73 61 2,769 2,379
-------------------------------------------------------------------------
Segment Income (Loss) $ (541) $ (257) 4,909 2,888
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Administrative 268 197
Interest, net 524 398
Accretion of asset
retirement obligation 37 22
Foreign exchange (gain), net (24) (412)
Stock-based compensation -
options 15 17
(Gain) on divestitures - (59)
-------------------------------------------------------------------------
820 163
-------------------------------------------------------------------------
Net Earnings Before Income Tax 4,089 2,725
Income tax expense 1,260 632
-------------------------------------------------------------------------
Net Earnings From Continuing
Operations $ 2,829 $ 2,093
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(*) For the twelve months ended December 31, the pre-tax unrealized loss
on risk management is recorded in the Consolidated Statement of
Earnings as follows (see Note 13):

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

Revenues, Net of Royalties - Corporate $ (466) $ (197)
Operating Expenses and Other - Corporate 3 (6)
-------------------------------------------------------------------------
Total Unrealized (Loss) on Risk Management
before-tax - Continuing Operations $ (469) $ (191)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Results of Continuing Operations
(For the twelve months ended December 31)


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

Revenues, Net of Royalties $ 7,005 $ 5,083 $ 3,177 $ 1,941
Expenses
Production and mineral taxes 104 87 349 224
Transportation and selling 343 352 182 120
Operating 826 685 212 119
Depreciation, depletion
and amortization 1,927 1,751 682 475
-------------------------------------------------------------------------
Segment Income $ 3,805 $ 2,208 $ 1,752 $ 1,003
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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

Revenues, Net of Royalties $ 283 $ 232 $ 10,465 $ 7,256
Expenses
Production and mineral taxes - - 453 311
Transportation and selling - - 525 472
Operating 313 222 1,351 1,026
Depreciation, depletion
and amortization 79 45 2,688 2,271
-------------------------------------------------------------------------
Segment Income (Loss) $ (109) $ (35) $ 5,448 $ 3,176
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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


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

Revenues, Net
of Royalties $ 5,486 $ 3,928 $ 2,932 $ 1,776 $ 8,418 $ 5,704
Expenses
Production and
mineral taxes 76 65 325 205 401 270
Transportation
and selling 283 296 182 120 465 416
Operating 521 400 212 119 733 519
-------------------------------------------------------------------------
Operating Cash
Flow $ 4,606 $ 3,167 $ 2,213 $ 1,332 $ 6,819 $ 4,499
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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

Revenues, Net
of Royalties $ 1,519 $ 1,155 $ 245 $ 165 $ 1,764 $ 1,320
Expenses
Production and
mineral taxes 28 22 24 19 52 41
Transportation
and selling 60 56 - - 60 56
Operating 305 285 - - 305 285
-------------------------------------------------------------------------
Operating Cash
Flow $ 1,126 $ 792 $ 221 $ 146 $ 1,347 $ 938
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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

Revenues, Net of Royalties $ 283 $ 232 $ 10,465 $ 7,256
Expenses
Production and mineral taxes - - 453 311
Transportation and selling - - 525 472
Operating 313 222 1,351 1,026
-------------------------------------------------------------------------
Operating Cash Flow $ (30) $ 10 $ 8,136 $ 5,447
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Capital Expenditures (Continuing Operations)


Three Months Ended Twelve Months Ended
December 31, December 31,
-------------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------

Upstream Core Capital
Canada $ 1,370 $ 733 $ 4,150 $ 3,015
United States 633 398 1,982 1,249
Other Countries 31 30 70 79
-------------------------------------------------------------------------
2,034 1,161 6,202 4,343
-------------------------------------------------------------------------

Upstream Acquisition Capital
Canada 4 9 30 64
United States 227 297 418 300
-------------------------------------------------------------------------
231 306 448 364
-------------------------------------------------------------------------

Market Optimization 68 4 197 10
Corporate 29 18 78 46
-------------------------------------------------------------------------
Total $ 2,362 $ 1,489 $ 6,925 $ 4,763
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Property, Plant and Equipment and Total Assets

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

Upstream $ 24,247 $ 22,097 $ 28,858 $ 26,118
Market Optimization 371 167 597 414
Corporate 263 239 1,530 1,385
Assets of
Discontinued
Operations (Note 3) 3,163 3,296
-------------------------------------------------------------------------
Total $ 24,881 $ 22,503 $ 34,148 $ 31,213
-------------------------------------------------------------------------
-------------------------------------------------------------------------

3. 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.

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.

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

On September 13, 2005, EnCana announced it had reached an agreement to
sell all its interest in its Ecuador operations for $1.42 billion, which
is approximately equivalent to the asset's net book value at July 1,
2005, the referenced effective date of the transaction. Included in net
earnings for 2005 is a provision of $234 million which has been recorded
against the net book value to recognize management's best estimate of the
difference between the selling price and the December 31, 2005 underlying
accounting value of the related investments at the sales date, as
required under Canadian generally accepted accounting principles.

United Kingdom

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

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 December 31,
-----------------------------------------------------
Ecuador United Kingdom Midstream
-----------------------------------------------------
2005 2004 2005 2004 2005 2004
-------------------------------------------------------------------------
Revenues, Net of
Royalties $ 242 $ 173 $ - $ 27 $ 645 $ 666
-------------------------------------------------------------------------
Expenses
Production and
mineral taxes 30 19 - - - -
Transportation
and selling 12 11 - 7 3 3
Operating 38 36 - 4 110 81
Purchased product - - - - 343 462
Depreciation,
depletion and
amortization 111 66 - 25 8 5
Administrative - - - - 30 -
Interest, net (2) (2) - (4) (1) (1)
Accretion of
asset retirement
obligation - - - - - -
Foreign exchange
(gain) loss, net (4) 4 (37) (5) - (5)
(Gain) loss on
discontinuance - - - (1,365) (364) (54)
-------------------------------------------------------------------------
185 134 (37) (1,338) 129 491
-------------------------------------------------------------------------
Net Earnings (Loss)
Before Income Tax 57 39 37 1,365 516 175
Income tax expense 57 (1) 4 10 52 42
-------------------------------------------------------------------------
Net Earnings (Loss)
From Discontinued
Operations $ - $ 40 $ 33 $1,355 $ 464 $ 133
-------------------------------------------------------------------------
-------------------------------------------------------------------------


For the three months
ended December 31,
-----------------------------------
Syncrude Total
-----------------------------------
2005 2004 2005 2004
-------------------------------------------------------
Revenues, Net of
Royalties $ - $ (1) $ 887 $ 865
-------------------------------------------------------
Expenses
Production and
mineral taxes - - 30 19
Transportation
and selling - - 15 21
Operating - - 148 121
Purchased product - - 343 462
Depreciation,
depletion and
amortization - - 119 96
Administrative - - 30 -
Interest, net - - (3) (7)
Accretion of
asset retirement
obligation - - - -
Foreign exchange
(gain) loss, net - - (41) (6)
(Gain) loss on
discontinuance - 2 (364) (1,417)
-------------------------------------------------------
- 2 277 (711)
-------------------------------------------------------
Net Earnings (Loss)
Before Income Tax - (3) 610 1,576
Income tax expense - - 113 51
-------------------------------------------------------
Net Earnings (Loss)
From Discontinued
Operations $ - $ (3) $ 497 $1,525
-------------------------------------------------------
-------------------------------------------------------


For the twelve months ended December 31,
-----------------------------------------------------
Ecuador United Kingdom Midstream
-----------------------------------------------------
2005 2004 2005 2004 2005 2004
-------------------------------------------------------------------------
Revenues, Net of
Royalties(*) $ 965 $ 471 $ - $ 153 $1,570 $1,551
-------------------------------------------------------------------------
Expenses
Production and
mineral taxes 131 61 - - - -
Transportation
and selling 58 60 - 36 9 9
Operating 138 125 - 36 301 251
Purchased product - - - - 1,100 1,184
Depreciation,
depletion and
amortization 234 263 - 118 28 23
Administrative - - - - 30 -
Interest, net (2) (3) - (9) (2) (1)
Accretion of
asset retirement
obligation 1 1 - 3 - -
Foreign exchange
(gain) loss, net (4) 5 (40) (2) (2) (5)
(Gain) loss on
discontinuance - - - (1,365) (364) (54)
-------------------------------------------------------------------------
556 512 (40) (1,183) 1,100 1,407
-------------------------------------------------------------------------
Net Earnings (Loss)
Before Income Tax 409 (41) 40 1,336 470 144
Income tax expense
(recovery) 278 (8) 5 (2) 39 26
-------------------------------------------------------------------------
Net Earnings (Loss)
From Discontinued
Operations $ 131 $ (33) $ 35 $1,338 $ 431 $ 118
-------------------------------------------------------------------------
-------------------------------------------------------------------------


For the twelve months
ended December 31,
-----------------------------------
Syncrude Total
-----------------------------------
2005 2004 2005 2004
-------------------------------------------------------
Revenues, Net of
Royalties(*) $ - $ (1) $2,535 $2,174
-------------------------------------------------------
Expenses
Production and
mineral taxes - - 131 61
Transportation
and selling - - 67 105
Operating - - 439 412
Purchased product - - 1,100 1,184
Depreciation,
depletion and
amortization - - 262 404
Administrative - - 30 -
Interest, net - - (4) (13)
Accretion of
asset retirement
obligation - - 1 4
Foreign exchange
(gain) loss, net - - (46) (2)
(Gain) loss on
discontinuance - 2 (364) (1,417)
-------------------------------------------------------
- 2 1,616 738
-------------------------------------------------------
Net Earnings (Loss)
Before Income Tax - (3) 919 1,436
Income tax expense
(recovery) - - 322 16
-------------------------------------------------------
Net Earnings (Loss)
From Discontinued
Operations $ - $ (3) $ 597 $1,420
-------------------------------------------------------
-------------------------------------------------------
(*) Revenues, net of royalties in Ecuador include realized losses of
$128 million related to derivative financial instruments. These
losses are offset by the reversal of the December 31, 2004 unrealized
mark to market losses of $72 million. In 2004, revenues, net of
royalties included realized losses of $278 million in addition to the
unrealized mark to market losses.


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

As at
---------------------------------------
December 31, 2005
---------------------------------------
United
Ecuador Kingdom Midstream Total
-------------------------------------------------------------------------
Assets
Cash and cash
equivalents $ 207 $ 8 $ (7) $ 208
Accounts receivable and
accrued revenues 137 - 271 408
Risk management - - 21 21
Inventories 23 - 390 413
-------------------------------------------------------------------------
367 8 675 1,050
Property, plant and
equipment, net 1,166 - 520 1,686
Investments and other
assets 360 - - 360
Goodwill - - 67 67
-------------------------------------------------------------------------
$ 1,893 $ 8 $ 1,262 $ 3,163
-------------------------------------------------------------------------
Liabilities
Accounts payable and
accrued liabilities $ 91 $ 27 $ 49 $ 167
Income tax payable 184 6 40 230
Risk management - - 41 41
-------------------------------------------------------------------------
275 33 130 438
Asset retirement
obligation 21 - - 21
Future income taxes 162 (2) 86 246
-------------------------------------------------------------------------
458 31 216 705
-------------------------------------------------------------------------
Net Assets of
Discontinued Operations $ 1,435 $ (23) $ 1,046 $ 2,458
-------------------------------------------------------------------------
-------------------------------------------------------------------------


As at
------------------------------------------------
December 31, 2004
------------------------------------------------
United
Ecuador Kingdom Midstream Syncrude Total
-------------------------------------------------------------------------
Assets
Cash and cash
equivalents $ 2 $ 12 $ 9 $ - $ 23
Accounts receivable and
accrued revenues 111 13 332 - 456
Risk management 3 - 19 - 22
Inventories 15 - 455 - 470
-------------------------------------------------------------------------
131 25 815 - 971
Property, plant and
equipment, net 1,295 - 637 - 1,932
Investments and other
assets 328 - - - 328
Goodwill - - 65 - 65
-------------------------------------------------------------------------
$ 1,754 $ 25 $ 1,517 $ - $ 3,296
-------------------------------------------------------------------------
Liabilities
Accounts payable and
accrued liabilities $ 61 $ 32 $ 137 $ 3 $ 233
Income tax payable 101 - 2 - 103
Risk management 72 - 17 - 89
-------------------------------------------------------------------------
234 32 156 3 425
Asset retirement
obligation 22 - - - 22
Future income taxes 80 11 111 - 202
-------------------------------------------------------------------------
336 43 267 3 649
-------------------------------------------------------------------------
Net Assets of
Discontinued Operations $ 1,418 $ (18) $ 1,250 $ (3) $ 2,647
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Contingencies

In Ecuador, a subsidiary of EnCana has a 40 percent non-operated economic
interest in relation to Block 15 pursuant to a contract with a subsidiary
of Occidental Petroleum Corporation. In its 2004 filings with Securities
regulatory authorities, Occidental Petroleum Corporation indicated that
its subsidiary had received formal notification from Petroecuador, the
state oil company of Ecuador, initiating proceedings to determine if the
subsidiary had violated the Hydrocarbons Law and its Participation
Contract for Block 15 with Petroecuador and whether such violations
constitute grounds for terminating the Participation Contract.

In its filings, Occidental Petroleum Corporation indicated that it
believes it has complied with all material obligations under the
Participation Contract and that any termination of the Participation
Contract by Ecuador based upon these stated allegations would be
unfounded and would constitute an unlawful expropriation under
international treaties. The subsidiary of Occidental Petroleum
Corporation has delivered, to the Government of Ecuador, its written
defense to the allegations. Upon review, the Government of Ecuador may
decide whether there are grounds for termination of the Participation
Contract.

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

4. DIVESTITURES

Total proceeds received on sale of assets and investments was
$2,523 million (2004 - $1,500 million) as described below:

Upstream

In 2005, the Company has completed the disposition of mature conventional
oil and natural gas assets for proceeds of $471 million (2004 -
$1,430 million).

In May, the Company completed the sale of its Gulf of Mexico assets for
approximately $2.1 billion resulting in net proceeds of approximately
$1.5 billion after deducting $578 million in tax plus other adjustments.
In accordance with full cost accounting for oil and gas activities,
proceeds were credited to property, plant and equipment.

Other

On December 15, 2004, EnCana sold its 25 percent limited partnership
interest in Kingston CoGen Limited Partnership for net cash consideration
of $25 million, recording a gain on sale of $28 million.

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

5. INTEREST, NET

Three Months Twelve Months
Ended Ended
December 31, December 31,
---------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------
Interest Expense - Long-Term Debt $ 107 $ 108 $ 417 $ 385
Early Retirement of Long-Term Debt - (5) 121 (16)
Interest Expense - Other 6 16 18 42
Interest Income (9) (5) (32) (13)
-------------------------------------------------------------------------
$ 104 $ 114 $ 524 $ 398
-------------------------------------------------------------------------
-------------------------------------------------------------------------

6. FOREIGN EXCHANGE (GAIN) LOSS, NET

Three Months Twelve Months
Ended Ended
December 31, December 31,
---------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------
Unrealized Foreign Exchange Loss
(Gain) on Translation of U.S.
Dollar Debt Issued in Canada $ 27 $ (163) $ (113) $ (285)
Other Foreign Exchange Loss (Gain) 10 (36) 89 (127)
-------------------------------------------------------------------------
$ 37 $ (199) $ (24) $ (412)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

7. INCOME TAXES

The provision for income taxes is as follows:

Three Months Twelve Months
Ended Ended
December 31, December 31,
---------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------
Current
Canada $ 205 $ 86 $ 493 $ 586
United States (25) (30) 719 (12)
Other (2) (3) (8) (15)
-------------------------------------------------------------------------
Total Current Tax 178 53 1,204 559
-------------------------------------------------------------------------

Future 717 422 56 182
Future Tax Rate Reductions - - - (109)
-------------------------------------------------------------------------
Total Future Tax 717 422 56 73
-------------------------------------------------------------------------
$ 895 $ 475 $ 1,260 $ 632
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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

Three Months Twelve Months
Ended Ended
December 31, December 31,
---------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------
Net Earnings Before Income Tax $ 2,764 $ 1,530 $ 4,089 $ 2,725
Canadian Statutory Rate 37.9% 39.1% 37.9% 39.1%
-------------------------------------------------------------------------
Expected Income Tax 1,048 599 1,550 1,066

Effect on Taxes Resulting from:
Non-deductible Canadian crown
payments 68 38 207 192
Canadian resource allowance (61) (59) (202) (246)
Canadian resource allowance
on unrealized risk management
losses (26) (37) - (10)
Statutory and other
rate differences (124) (3) (235) (50)
Effect of tax rate changes - - - (109)
Non-taxable capital (gains)
losses 3 (50) (24) (91)
Previously unrecognized capital - 7 - 17
Tax basis retained on
dispositions - 1 (68) (169)
Large corporations tax 1 11 25 24
Other (14) (32) 7 8
-------------------------------------------------------------------------
$ 895 $ 475 $ 1,260 $ 632
-------------------------------------------------------------------------
Effective Tax Rate 32.4% 31.0% 30.8% 23.2%
-------------------------------------------------------------------------
-------------------------------------------------------------------------

8. LONG-TERM DEBT

As at As at
December 31, December 31,
2005 2004
-------------------------------------------------------------------------
Canadian Dollar Denominated Debt
Revolving credit and term loan borrowings $ 1,425 $ 1,515
Unsecured notes 793 1,309
-------------------------------------------------------------------------
2,218 2,824
-------------------------------------------------------------------------
U.S. Dollar Denominated Debt
Revolving credit and term loan borrowings - 399
Unsecured notes and debentures 4,494 4,641
-------------------------------------------------------------------------
4,494 5,040
-------------------------------------------------------------------------
Increase in Value of Debt Acquired(*) 64 66
Current Portion of Long-Term Debt (73) (188)
-------------------------------------------------------------------------
$ 6,703 $ 7,742
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) Certain of the notes and debentures of EnCana were acquired in
business combinations and were accounted for at their fair value at
the dates of acquisition. The difference between the fair value and
the principal amount of the debt is being amortized over the
remaining life of the outstanding debt acquired, approximately
21 years.

9. ASSET RETIREMENT OBLIGATION

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

As at As at
December 31, December 31,
2005 2004
-------------------------------------------------------------------------
Asset Retirement Obligation, Beginning of Year $ 611 $ 383
Liabilities Incurred 77 98
Liabilities Settled (42) (16)
Liabilities Disposed (23) (35)
Change in Estimated Future Cash Flows 135 124
Accretion Expense 37 22
Other 21 35
-------------------------------------------------------------------------
Asset Retirement Obligation, End of Year $ 816 $ 611
-------------------------------------------------------------------------
-------------------------------------------------------------------------

10. SHARE CAPITAL

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

Common Shares Outstanding,
Beginning of Year 900.6 $ 5,299 921.2 $ 5,305
Common Shares Issued under
Option Plans 15.0 294 19.4 281
Common Shares Repurchased (60.7) (462) (40.0) (287)
-------------------------------------------------------------------------
Common Shares Outstanding,
End of Year 854.9 $ 5,131 900.6 $ 5,299
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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

Normal Course Issuer Bid

To December 31, 2005, the Company purchased 60,757,198 Common Shares for
total consideration of approximately $2,114 million. Of the amount paid,
$462 million was charged to Share capital, $10 million was charged to
Paid in surplus and $1,642 million was charged to Retained earnings.
Included in the above are 5.5 million Common Shares which have been
purchased by an EnCana Employee Benefit Plan Trust and held for issuance
upon vesting of units under EnCana's Performance Share Unit plan (see
Note 11).

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. During January 2006, EnCana purchased
approximately 6.8 million Common Shares under the current Bid for total
consideration of $314 million. Under the prior Bid which commenced
October 29, 2004 and expired October 28, 2005, EnCana purchased
approximately 84.2 million Common Shares.

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 December 31, 2005. Information related to
TSAR's is included in Note 11.

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

Outstanding, Beginning of Year 36.2 23.15
Exercised (14.9) 22.90
Forfeited (0.6) 21.71
-------------------------------------------------------------------------
Outstanding, End of Year 20.7 23.36
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Exercisable, End of Year 16.8 23.21
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Outstanding Options Exercisable Options
---------------------------------------------------------------
Weighted
Average
Range of Number of Remaining Weighted Number of Weighted
Exercise Options Contractual Average Options Average
Price Outstanding Life Exercise Outstanding Exercise
(C$) (millions) (years) Price (C$) (millions) Price (C$)
-------------------------------------------------------------------------
10.50 to
22.99 1.7 2.3 15.74 1.7 15.60
23.00 to
23.49 1.3 0.7 23.17 1.1 23.16
23.50 to
23.99 6.9 2.3 23.89 3.6 23.88
24.00 to
24.49 10.2 1.2 24.18 10.1 24.18
24.50 to
25.99 0.6 2.6 25.23 0.3 25.21
-------------------------------------------------------------------------
20.7 1.7 23.36 16.8 23.21
-------------------------------------------------------------------------
-------------------------------------------------------------------------

EnCana has recorded stock-based compensation expense in the Consolidated
Statement of Earnings for stock options granted to employees and
directors in 2003 using the fair-value method. Stock options granted
subsequent to December 31, 2003 have an associated Tandem Share
Appreciation Right attached. Compensation expense has not been recorded
in the Consolidated Statement of Earnings related to stock options
granted prior to 2003. If the Company had applied the fair-value method
to options granted prior to 2003, pro forma Net Earnings and Net Earnings
per Common Share for the three months ended December 31, 2005 would be
unchanged (three months ended 2004 - $2,570 million; $2.80 per common
share - basic; $2.76 per common share - diluted). Pro forma Net Earnings
and Net Earnings per Common Share for the twelve months ended December
31, 2005 would be unchanged (2004 - $3,476 million; $3.77 per common
share - basic; $3.71 per common share - diluted).

11. COMPENSATION PLANS

The tables below outline certain information related to EnCana's
compensation plans at December 31, 2005. Additional information is
contained in Note 15 of the Company's annual audited Consolidated
Financial Statements for the year ended December 31, 2004.

A) Pensions

The following table summarizes the net benefit plan expense:

Three Months Twelve Months
Ended Ended
December 31, December 31,
---------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------
Current Service Cost $ 6 $ 2 $ 11 $ 6
Interest Cost 6 5 16 14
Expected Return on Plan Assets (5) (4) (14) (12)
Amortization of Net Actuarial Loss 3 - 5 4
Amortization of Transitional
Obligation (1) - (2) (2)
Amortization of Past Service Cost 1 1 2 2
Expense for Defined Contribution
Plan 6 9 22 19
-------------------------------------------------------------------------
Net Benefit Plan Expense $ 16 $ 13 $ 40 $ 31
-------------------------------------------------------------------------
-------------------------------------------------------------------------

For the year ended December 31, 2005, contributions to the defined
benefit pension plans were made totaling $9 million as approved by the
Board of Directors, and Management expects to contribute a similar amount
in 2006.

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

The following table summarizes the information about SAR's at December
31, 2005:

Weighted
Average
Outstanding Exercise
SAR's Price
-------------------------------------------------------------------------
Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 930,510 18.31
Exercised (682,241) 16.55
Forfeited (1,530) 23.14
-------------------------------------------------------------------------
Outstanding, End of Year 246,739 23.13
-------------------------------------------------------------------------
Exercisable, End of Year 246,739 23.13
-------------------------------------------------------------------------
-------------------------------------------------------------------------

U.S. Dollar Denominated (US$)
Outstanding, Beginning of Year 771,860 14.40
Exercised (452,349) 14.45
-------------------------------------------------------------------------
Outstanding, End of Year 319,511 14.33
-------------------------------------------------------------------------
Exercisable, End of Year 319,511 14.33
-------------------------------------------------------------------------
-------------------------------------------------------------------------

For the year ended December 31, 2005, EnCana recorded compensation costs
of $17 million related to the outstanding SAR's (2004 - $17 million).

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

The following table summarizes the information about Tandem SAR's at
December 31, 2005:

Weighted
Average
Outstanding Exercise
TSAR's Price
-------------------------------------------------------------------------
Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 1,735,000 27.77
Granted 7,581,412 40.14
Exercised - SAR's (151,610) 27.51
Exercised - Options (104,735) 27.60
Forfeited (656,100) 34.44
-------------------------------------------------------------------------
Outstanding, End of Year 8,403,967 38.41
-------------------------------------------------------------------------
Exercisable, End of Year 229,705 28.00
-------------------------------------------------------------------------
-------------------------------------------------------------------------

For the year ended December 31, 2005, EnCana recorded compensation costs
of $60 million related to the outstanding TSAR's (2004 - $3 million).

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

The following table summarizes the information about DSU's at December
31, 2005:

Weighted
Average
Outstanding Exercise
DSU's Price
-------------------------------------------------------------------------
Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 750,612 24.81
Granted, Directors 80,765 43.75
Units, in Lieu of Dividends 5,184 52.34
-------------------------------------------------------------------------
Outstanding, End of Year 836,561 26.81
-------------------------------------------------------------------------
Exercisable, End of Year 836,561 26.81
-------------------------------------------------------------------------
-------------------------------------------------------------------------

For the year ended December 31, 2005, EnCana recorded compensation costs
of $16 million related to the outstanding DSU's (2004 - $10 million).

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

The following table summarizes the information about PSU's at
December 31, 2005:

Weighted
Average
Outstanding Grant
PSU's Price
-------------------------------------------------------------------------
Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 3,294,206 26.71
Granted 1,734,089 38.13
Forfeited (323,947) 30.48
-------------------------------------------------------------------------
Outstanding, End of Year 4,704,348 30.65
-------------------------------------------------------------------------
-------------------------------------------------------------------------

U.S. Dollar Denominated (US$)
Outstanding, Beginning of Year 449,230 20.56
Granted 390,171 30.92
Forfeited (99,752) 26.50
-------------------------------------------------------------------------
Outstanding, End of Year 739,649 25.22
-------------------------------------------------------------------------
-------------------------------------------------------------------------

For the year ended December 31, 2005, EnCana recorded compensation costs
of $91 million related to the outstanding PSU's (2004 - $25 million).

At December 31, 2005, EnCana has approximately 5.5 million Common Shares
held in trust for issuance upon vesting of the PSU's.

12. PER SHARE AMOUNTS

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

Twelve Months
Three Months Ended Ended
--------------------------------------------------------------
September
March 31, June 30, 30, December 31, December 31,
--------------------------------------------------------------
(millions) 2005 2005 2005 2005 2004 2005 2004
-------------------------------------------------------------------------
Weighted
Average
Common
Shares
Outstanding
- Basic 891.8 872.0 855.1 854.4 917.6 868.3 920.8
Effect of
Dilutive
Securities 17.2 19.9 20.7 18.1 12.2 20.9 15.2
-------------------------------------------------------------------------
Weighted
Average
Common
Shares
Outstanding
- Diluted 909.0 891.9 875.8 872.5 929.8 889.2 936.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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

13. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

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

Realized and Unrealized (Loss) Gain on Risk Management Activities

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

Realized Gain (Loss)
--------------------------------------------
Q1 Q2 Q3 Q4 YTD
-------------------------------------------------------------------------

Revenues, Net of Royalties $ (19) $ (114) $ (196) $ (355) $ (684)
Operating Expenses and Other 5 5 7 14 31
-------------------------------------------------------------------------
Loss on Risk Management -
Continuing Operations (14) (109) (189) (341) (653)
Loss on Risk Management -
Discontinued Operations (24) (32) (55) (15) (126)
-------------------------------------------------------------------------
$ (38) $ (141) $ (244) $ (356) $ (779)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Unrealized Gain (Loss)
--------------------------------------------
Q1 Q2 Q3 Q4 YTD
-------------------------------------------------------------------------

Revenues, Net of Royalties $ (962) $ 315 $ (810) $ 991 $ (466)
Operating Expenses and Other 3 (1) 1 (6) (3)
-------------------------------------------------------------------------
(Loss) Gain on Risk
Management - Continuing
Operations (959) 314 (809) 985 (469)
(Loss) Gain on Risk
Management - Discontinued
Operations (30) 31 (90) 139 50
-------------------------------------------------------------------------
$ (989) $ 345 $ (899) $ 1,124 $ (419)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Amounts Recognized on Transition

As discussed in Note 2 to the annual audited Consolidated Financial
Statements for the year ended December 31, 2004, on January 1, 2004, the
fair value of all outstanding financial instruments that were not
considered accounting hedges was recorded in the Consolidated Balance
Sheet with an offsetting net deferred loss amount (the "transition
amount"). The transition amount is recognized into net earnings over the
life of the related contracts. Changes in fair value after that time are
recorded in the Consolidated Balance Sheet with an associated unrealized
gain or loss recorded in net earnings. The estimated fair value of all
derivative instruments is based on quoted market prices or, in their
absence, third party market indications and forecasts.

At December 31, 2005, a net unrealized gain remains to be recognized over
the next three years as follows:

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

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

Fair Value of Outstanding Risk Management Positions

The following table presents a reconciliation of the change in the
unrealized amounts from January 1, 2005 to December 31, 2005:

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

Fair Value of Contracts and Premiums
Paid, Beginning of Year $ (72) $ (189) $ -
Change in Fair Value of Contracts in
Place at Beginning of Year and
Contracts entered into During 2005 - (1,230) (1,230)
Fair Value of Contracts in Place at
Transition Expired During 2005 32 - 32
Fair Value of Contracts Realized
During 2005 - 779 779
-------------------------------------------------------------------------
Fair Value of Contracts Outstanding $ (40) $ (640) $ (419)
Unamortized Premiums Paid on Collars
and Options 316
-------------------------------------------------------------------------
Fair Value of Contracts and Premiums
Paid, End of Year $ (324)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Amounts Allocated to Continuing
Operations $ (40) $ (304) $ (469)
Amounts Allocated to Discontinued
Operations - (20) 50
-------------------------------------------------------------------------
$ (40) $ (324) $ (419)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

At December 31, 2005, the remaining net deferred amounts recognized on
transition and the risk management amounts are recorded in the
Consolidated Balance Sheet as follows:

As at
December 31,
2005
-------------------------------------------------------------------------

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

Accounts payable and accrued liabilities 25
Other liabilities 17
-------------------------------------------------------------------------
Net Deferred Gain - Continuing Operations $ 40
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Risk Management
Current asset $ 495
Long-term asset 530

Current liability 1,227
Long-term liability 102
-------------------------------------------------------------------------
Net Risk Management Liability - Continuing Operations (304)
Net Risk Management Liability - Discontinued Operations (20)
-------------------------------------------------------------------------
$ (324)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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

As at
December 31,
2005
-------------------------------------------------------------------------

Commodity Price Risk
Natural gas $ (247)
Crude oil (66)
Credit Derivatives (1)
Interest Rate Risk 10
-------------------------------------------------------------------------
Total Fair Value Positions - Continuing Operations (304)
Total Fair Value Positions - Discontinued Operations (20)
-------------------------------------------------------------------------
$ (324)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Information with respect to power and interest rate risk contracts in
place at December 31, 2004 is disclosed in Note 16 to the Company's
annual audited Consolidated Financial Statements. No significant new
contracts have been entered into as at December 31, 2005.

Natural Gas

At December 31, 2005, the Company's gas risk management activities from
financial contracts had an unrealized loss of $(500) million and a fair
market value position of $(267) million. The contracts were as follows:


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

Sales Contracts
Fixed Price Contracts

NYMEX Fixed Price 525 2006 5.65 US$/Mcf $ (954)
Colorado Interstate
Gas (CIG) 100 2006 4.44 US$/Mcf (151)
Houston Ship
Channel (HSC) 90 2006 5.08 US$/Mcf (146)
Other 81 2006 4.58 US$/Mcf (126)

NYMEX Fixed Price 240 2007 7.76 US$/Mcf (203)

Collars and Other Options
Purchased NYMEX Put
Options 2,602 2006 7.76 US$/Mcf (73)

Purchased NYMEX Put
Options 240 2007 6.00 US$/Mcf (5)

Basis Contracts
Fixed NYMEX to
AECO Basis 799 2006 (0.69) US$/Mcf 217
Fixed NYMEX to
Rockies Basis 324 2006 (0.58) US$/Mcf 162
Fixed NYMEX to
CIG Basis 301 2006 (0.83) US$/Mcf 133
Other 182 2006 (0.36) US$/Mcf 52

Fixed NYMEX to
AECO Basis 735 2007 (0.71) US$/Mcf 101
Fixed NYMEX to
Rockies Basis 538 2007 (0.65) US$/Mcf 232
Fixed NYMEX to
CIG Basis 390 2007 (0.76) US$/Mcf 164
Fixed Rockies to
CIG Basis 12 2007 (0.10) US$/Mcf -

Fixed NYMEX to
AECO Basis 191 2008 (0.78) US$/Mcf 12
Fixed NYMEX to
Rockies Basis 162 2008 (0.59) US$/Mcf 52
Fixed NYMEX to 2008-
CIG Basis 40 2009 (0.68) US$/Mcf 23

Purchase Contracts
Fixed Price Contracts
Waha Purchase 23 2006 5.32 US$/Mcf 33
-------------------------------------------------------------------------
(477)
Other Financial
Positions(*) (23)
-------------------------------------------------------------------------
Total Unrealized Loss
on Financial Contracts (500)
Unamortized Premiums
Paid on Options 233
-------------------------------------------------------------------------
Total Fair Value Positions $ (267)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Total Fair Value Positions -
Continuing Operations (247)
Total Fair Value Positions -
Discontinued Operations (20)
-------------------------------------------------------------------------
Total Fair Value Positions $ (267)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) Other financial positions are part of the ongoing operations of the
Company's proprietary production management and gas storage
optimization activities.


Crude Oil

At December 31, 2005, the Company's oil risk management activities from
financial contracts had an unrealized loss of $(149) million and a fair
market value position of $(66) million. The contracts were as follows:

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

Fixed WTI NYMEX Price 15,000 2006 34.56 $ (153)
Unwind WTI NYMEX Fixed Price (1,300) 2006 52.75 5
Purchased WTI NYMEX Put Options 57,000 2006 50.00 (10)
Purchased WTI NYMEX Call Options (13,700) 2006 61.24 14

Purchased WTI NYMEX Put Options 43,000 2007 44.44 (6)
-------------------------------------------------------------------------
(150)
Other Financial Positions(*) 1
-------------------------------------------------------------------------
Total Unrealized Loss on
Financial Contracts (149)
Unamortized Premiums Paid
on Options 83
-------------------------------------------------------------------------
Total Fair Value Positions $ (66)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Total Fair Value Positions -
Continuing Operations $ (66)
Total Fair Value Positions -
Discontinued Operations -
-------------------------------------------------------------------------
$ (66)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) Other financial positions are part of the ongoing operations of the
Company's proprietary production management.


14. 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 all but one of the class actions in the United States District Court
and in the Gallo action, decisions 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 are on appeal to the United States Court of
Appeals for the Ninth Circuit.

Without admitting any liability in the lawsuits, in November 2005, WD has
agreed to pay $20.5 million to settle the class action lawsuits that were
consolidated in San Diego Superior Court, subject to final documentation
and approval by the San Diego Superior Court. The individual parties who
had brought their own actions are not parties to this settlement.

New York
WD is also 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 has agreed to pay a maximum of $9.1 million
to settle the New York class action lawsuit, subject to final
documentation and approval by the New York District Court.

Based on the aforementioned settlements, during the fourth quarter of
2005 a total of $30 million was recorded, which amount has been included
in Administrative costs in the Net Earnings from Discontinued Operations.
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.

15. RECLASSIFICATION

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

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

Ryder McRitchie
Manager, Investor Relations
403-645-2007

Paul Gagne
Manager, Investor Relations
403-645-4737

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

investor.relations@encana.com

ECA stock price

TSX $14.27 Can 0

NYSE $11.11 USD 0

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