EnCana generates 2007 cash flow of US$8.5 billion, or $11.06 per share, up 29 percent

Drill bit additions exceed 200% of production; Net earnings per share down 23 percent

Quarterly dividend doubled to 40 cents per share

CALGARY, Feb. 14 /CNW/ - EnCana Corporation (TSX & NYSE: ECA) achieved
strong increases in 2007 cash flow and operating earnings during a year of
solid growth in natural gas and oil production. Financial results were
enhanced by EnCana's favourable gas price hedges, which offset weaker gas
prices, and excellent performance from the company's downstream segment of the
integrated oil business. EnCana also achieved very strong proved reserves
additions at competitive costs.
"EnCana delivered tremendous operational and financial performance in
2007, a direct result of our sharpened focus on North American unconventional
natural gas and integrated oil resource plays. The sustainable value creation
capacity of our resource play strategy is becoming increasingly evident. With
strong production growth of 11 percent per share and successful price hedges
that delivered a $1 billion benefit to 2007 cash flow, our company's cash
flow, operating earnings and free cash flow all increased substantially in a
year when our industry faced many challenges. In 2007, production from our key
natural gas resource plays grew 14 percent, while production from our
integrated oil projects increased 25 percent. Our newly established refining
business also delivered great results, achieving twice the cash flow we
expected during its inaugural year. Completing the year's success story,
proved reserves additions were also substantial, replacing more than two times
the amount of oil and gas we produced. Most importantly, these reserves
additions were achieved at a highly-competitive finding and development cost
of $1.65 per thousand cubic feet equivalent," said Randy Eresman, EnCana's
President & Chief Executive Officer.
"EnCana's energy resources lie beneath its more than 25 million net acres
of land in North America, largely in the heart of the unconventional fairway.
Our low-risk, long-life resource play assets hold the potential to deliver
strong shareholder value creation for many years ahead. As a reflection of the
company's confidence in the sustainability of its business model, EnCana's
board of directors has approved a doubling of our quarterly dividend to
40 cents per share," Eresman said.
     IMPORTANT NOTE: Effective January 2, 2007, EnCana established an
integrated oil business with ConocoPhillips, which resulted in EnCana
contributing its interests in Foster Creek and Christina Lake into an
upstream partnership owned 50-50 by the two companies. Unless otherwise
noted in this news release, EnCana's proved reserves and production in
2007 are reported on a post integrated oil basis. Production and wells
drilled from 2006 have also been adjusted on a pro forma basis to reflect
the integrated oil transaction. Per share amounts for cash flow and
earnings are on a diluted basis. EnCana reports in U.S. dollars unless
otherwise noted and follows U.S. protocols, which report production,
sales and reserves on an after-royalties basis. The company's financial
statements are prepared in accordance with Canadian generally accepted
accounting principles (GAAP).
     2007 Highlights
---------------
     <<
Financial - US$
         -  Cash flow per share increased 29 percent to $11.06, or
$8.5 billion
- Operating earnings per share were up 37 percent to $5.36, or
$4.1 billion
- Net earnings per share were down 23 percent to $5.18, or
$4.0 billion, primarily due to the after-tax change in the
unrealized mark-to-market impact of EnCana's financial hedges
- Operating cash flow from the integrated oil business was
$1.3 billion in 2007 compared to $276 million in 2006, including
$1.1 billion of operating cash flow generated from the U.S.
refineries
- Total capital investment was down 4 percent to $6.0 billion
- Generated $2.4 billion of free cash flow (as defined in Note 1 on
page 10), up 171 percent
- Purchased 38.9 million EnCana shares at an average price of $52.05
under the Normal Course Issuer Bid, for a total cost of
$2.0 billion
- Reduced shares outstanding at year-end by 4 percent, net of share
option exercises, to a year-end total of 750.2 million
- Doubled quarterly dividend in March 2007 to 20 cents per share,
which amounts to 80 cents per share on an annual basis
- At year end, net debt-to-adjusted-EBITDA was 1.2 times and net
debt-to-capitalization was 34 percent
     Operating - Upstream
         -  Natural gas production increased 6 percent to 3.6 billion cubic
feet per day (Bcf/d), up 15 percent per share
- Increased production from natural gas key resource plays by 14
percent
- Oil and natural gas liquids (NGLs) production decreased 9 percent
to about 134,000 barrels per day (bbls/d), or down about 2 percent
per share, primarily due to the sale of EnCana's Ecuador assets in
the first quarter of 2006
- Integrated oil production grew 25 percent to 26,814 bbls/d at
Foster Creek and Christina Lake
- Operating and administrative costs of $1.17 per thousand cubic
feet equivalent (Mcfe)
     Operating - Downstream
         -  Refined products averaged 457,000 bbls/d (228,500 bbls/d net to
EnCana)
- Refinery crude utilization of 96 percent or 432,000 bbls/d crude
throughput (216,000 bbls/d net to EnCana)
     Reserves

         -  Total proved reserves increased 12 percent to 18.9 trillion cubic
feet equivalent (Tcfe)
- Added 3.6 Tcfe of proved reserves, compared to production of
1.6 Tcfe, for a production replacement of 227 percent
- Proved natural gas reserves increased 7 percent to 13.3 trillion
cubic feet (Tcf)
- Proved oil and NGLs reserves increased 26 percent to 927 million
barrels (MMbbls)
- Proved reserves additions included approximately 2.2 Tcf of
natural gas reserves, led by the Cutbank Ridge, Jonah and Piceance
resource plays, and 241 million bbls of oil and NGLs, primarily
from the Foster Creek and Christina Lake key resource plays
- Finding and Development (F&D) costs were $1.65 per Mcfe
- Three-year (2005-2007) F&D costs averaged $1.59 per Mcfe
- F&D costs for natural gas and associated liquids were
approximately $2.40 per Mcfe
- Proved reserves life index of 12 years
- Reserves replacement costs are outlined on page 8
     2007 strategic results
         -  Completed first full year of integrated oil business with
ConocoPhillips composed of two 50-50 entities - one upstream and
one downstream - which became effective January 2, 2007
- Acquired the remaining 50 percent interest in the Deep Bossier
natural gas play in East Texas for $2.55 billion, before closing
adjustments
- Approved the development of the Deep Panuke natural gas project
offshore Nova Scotia
- Completed the sale of interests in Chad for $208 million, assets
in the Mackenzie Delta and Beaufort Sea for $159 million and
assets in Australia for $31 million, before closing adjustments
- Announced an agreement to sell remaining interests in Brazil for
approximately $165 million, before closing adjustments. The sale
is expected to close in the first half of 2008, pending certain
conditions and regulatory approvals.
>>
     Strong natural gas production in 2007 led by U.S. resource plays
     Total natural gas production averaged about 3.6 Bcf/d in 2007, an
increase of 6 percent - roughly twice the company's original forecast -
principally due to strong performance from the Jonah and East Texas
properties. Gas production growth was led by a 14 percent increase in U.S.
production. In 2007, U.S. natural gas production represented about 40 percent
of EnCana's total natural gas portfolio. That share is expected to increase to
almost 45 percent in 2008.
     Integrated oil adds strong cash flow

     EnCana saw strong financial performance from the first full year of its
integrated oil business. Regional and local market factors have an impact on
refining crack spreads. The Wood River and Borger refineries are located in
markets influenced by U.S. Mid-Continent and Chicago 3-2-1 crack spreads,
which for most of the year were strong relative to U.S. Gulf Coast and NYMEX
crack spreads. Refining margins tracked well above historical levels through
the middle of 2007, helping the integrated oil business generate about
$1.3 billion in operating cash flow.
     Deep Panuke gas project offshore Nova Scotia approved
     Following the receipt of regulatory approval to develop the Deep Panuke
natural gas project, EnCana sanctioned the $700 million project. Deep Panuke,
located about 175 kilometres offshore Nova Scotia, is scheduled to start
production in late 2010 and is expected to deliver between 200 million and
300 million cubic feet of natural gas per day to markets in Canada and the
northeast United States.
     Fourth quarter production continues strong growth
     EnCana's fourth quarter natural gas production increased 9 percent, with
production at 3.7 Bcf/d, compared to the same quarter in 2006. Oil and natural
gas liquids production increased 4 percent, with production at 136,000 bbls/d.
Fourth quarter cash flow per share increased 17 percent to $2.56 or
$1.9 billion and operating earnings per share increased 33 percent to $1.12,
or $849 million.

<<
-------------------------------------------------------------------------
Financial Summary - Total Consolidated
-------------------------------------------------------------------------
(for the period
ended December 31)
($ millions, except Q4 Q4 % %
per share amounts) 2007 2006 change 2007 2006 change
-------------------------------------------------------------------------
Cash flow(1) 1,934 1,761 + 10 8,453 7,161 + 18
Per share diluted 2.56 2.18 + 17 11.06 8.56 + 29
-------------------------------------------------------------------------
Net earnings 1,082 663 + 63 3,959 5,652 - 30
Per share diluted 1.43 0.82 + 74 5.18 6.76 - 23
-------------------------------------------------------------------------
Operating earnings(1) 849 675 + 26 4,100 3,271 + 25
Per share diluted 1.12 0.84 + 33 5.36 3.91 + 37
-------------------------------------------------------------------------
-------------------------------------------------------------------------
             Earnings Reconciliation Summary - Total Consolidated
-------------------------------------------------------------------------
Net earnings 1,082 663 + 63 3,959 5,652 - 30
(Add back losses &
deduct gains)
Unrealized mark-to-
market hedging gain
(loss), after-tax (366) 95 (811) 1,370
Non-operating foreign
exchange gain (loss),
after-tax 267 (128) 217 -
Gain (loss) on
discontinuance,
after-tax 68 21 152 554
     Future tax recovery
due to tax rate
reductions 264 - 301 457
-------------------------------------------------------------------------
Operating earnings(1) 849 675 + 26 4,100 3,271 + 25
Per share diluted 1.12 0.84 + 33 5.36 3.91 + 37
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Cash flow and operating earnings are non-GAAP measures as defined in
Note 1 on Page 10.
     -------------------------------------------------------------------------
2007 Cash Flow Information
     (for the period ended December 31, $ millions)               Q4     2007
-------------------------------------------------------------------------
Cash from operating activities 2,193 8,429
Deduct (Add back):
Net change in other assets and liabilities (21) (16)
Net change in non-cash working capital from continuing
operations 280 (8)
-------------------------------------------------------------------------
Cash flow(1) 1,934 8,453
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     (1) Cash flow as defined in Note 1 on Page 10.
     -------------------------------------------------------------------------
Production & Drilling Summary
-------------------------------------------------------------------------
Total Consolidated
-------------------------------------------------------------------------
(for the period ended
December 31) Q4 Q4 % %
(After royalties) 2007 2006(1) change 2007 2006(1) change
-------------------------------------------------------------------------
Natural Gas production
(MMcf/d) 3,722 3,406 + 9 3,566 3,367 + 6
-------------------------------------------------------------------------
Natural gas
production per
1,000 shares (Mcf) 457 395 + 16 1,720 1,499 + 15
-------------------------------------------------------------------------
Oil and NGLs
production (Mbbls/d) 136 131 + 4 134 148 - 9
-------------------------------------------------------------------------
Oil and NGLs
production per
1,000 shares (Mcfe) 100 91 + 10 388 395 - 2
-------------------------------------------------------------------------
Total production
(MMcfe/d) 4,539 4,194 + 8 4,371 4,254 + 3
-------------------------------------------------------------------------
Total production
per 1,000 shares
(Mcfe) 557 487 + 14 2,108 1,894 + 11
-------------------------------------------------------------------------
Net wells drilled 1,313 809 + 62 4,484 3,657 + 23
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Continuing Operations
-------------------------------------------------------------------------
Natural Gas
production (MMcf/d) 3,722 3,406 + 9 3,566 3,367 + 6
-------------------------------------------------------------------------
North America Oil
and NGLs (Mbbls/d) 136 131 + 4 134 136 - 1
-------------------------------------------------------------------------
Total production
(MMcfe/d) 4,539 4,194 + 8 4,371 4,182 + 5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net wells drilled 1,313 809 + 62 4,484 3,650 + 23
-------------------------------------------------------------------------
     (1) 2006 information has been adjusted on a pro forma basis to reflect
the integrated oil transaction; 2006 includes production from
EnCana's Ecuador assets, which were sold in the first quarter of
2006.

Key natural gas resource play production up 14 percent
     Natural gas production from EnCana's key resource plays increased
14 percent in 2007 to 2.7 Bcf/d, up from 2.4 Bcf/d in 2006. The increase was
led by strong results in the U.S., where total gas production was up 14
percent, with the strongest growth in East Texas at 44 percent, Fort Worth in
Texas at 23 percent and Jonah in Wyoming at 20 percent. In the fourth quarter,
the company also saw the benefit of incremental production gains from the Deep
Bossier acquisition. In 2007, total gas production in Canada increased
2 percent. Growth was strong at Cutbank Ridge in northeast British Columbia at
38 percent, the company's coalbed methane (CBM) production in central and
southern Alberta at 34 percent, and Bighorn in west central Alberta at
31 percent. Drilling successes in Canada were offset by natural declines at
conventional properties.
Oil production from Foster Creek and Christina Lake was up 25 percent to
26,814 bbls/d. Overall, key resource play gas and oil production for the year
was up 13 percent.

Growth from key North American resource plays
     -------------------------------------------------------------------------
Daily Production
-----------------------------------------------
Resource Play 2007
-----------------------------------------------
(After royalties) Full
Year Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Natural gas (MMcf/d)
Jonah 557 612 588 523 504
Piceance 348 351 354 349 334
East Texas 143 187 144 139 103
Fort Worth 124 138 128 124 106
Greater Sierra 211 221 220 219 186
Cutbank Ridge 234 254 245 226 210
Bighorn 119 130 128 115 104
CBM 259 283 256 245 251
Shallow Gas(1) 726 727 713 729 735
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total natural gas (MMcf/d) 2,721 2,903 2,776 2,669 2,533
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Oil (Mbbls/d)
Foster Creek(2) 24 25 26 25 20
Christina Lake(2) 3 2 3 3 3
Pelican Lake(3) 23 24 24 23 23
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total oil (Mbbls/d) 50 51 53 51 46
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     Total (MMcfe/d)                    3,021   3,209   3,090   2,972   2,811
-------------------------------------------------------------------------
% change from prior period +13.3 +3.9 +4.0 +5.7 +2.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     -------------------------------------------------------------------------
Daily Production
-----------------------------------------------
Resource Play 2006 2005
-----------------------------------------------
(After royalties) Full Full
Year Q4 Q3 Q2 Q1 Year
-------------------------------------------------------------------------
Natural gas (MMcf/d)
Jonah 464 487 455 450 461 435
Piceance 326 335 331 324 316 307
East Texas 99 95 106 93 99 90
Fort Worth 101 99 104 108 93 70
Greater Sierra 213 212 209 224 208 219
Cutbank Ridge 170 199 167 173 140 92
Bighorn 91 99 97 95 72 55
CBM 194 211 209 179 177 112
Shallow Gas(1) 739 737 734 730 756 765
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total natural gas (MMcf/d) 2,397 2,474 2,412 2,376 2,322 2,145
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Oil (Mbbls/d)
Foster Creek(2) 18 21 19 16 18 14
Christina Lake(2) 3 3 3 3 3 3
Pelican Lake(3) 24 20 23 22 29 26
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total oil (Mbbls/d) 45 44 45 41 50 43
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     Total (MMcfe/d)            2,667   2,736   2,680   2,624   2,624   2,403
-------------------------------------------------------------------------
% change from prior period +11.0 +2.1 +2.1 - -2.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Shallow Gas volumes in 2006 and 2005 were restated in the first
quarter 2007 to report commingled volumes from multiple zones within
the same geographic area based upon regulatory approval.
(2) Foster Creek and Christina Lake volumes in 2006 and 2005 were
restated in the first quarter 2007 on a pro forma basis to reflect
the integrated oil transaction.
(3) Pelican Lake reached royalty payout in April 2006.
            Drilling activity in key North American resource plays
     -------------------------------------------------------------------------
Net Wells Drilled
-----------------------------------------------
Resource Play 2007
-----------------------------------------------
Full
Year Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Natural gas
Jonah 135 23 31 42 39
Piceance 286 77 72 72 65
East Texas 35 8 9 11 7
Fort Worth 75 15 17 29 14
Greater Sierra 109 27 27 32 23
Cutbank Ridge 81 11 18 25 27
Bighorn 58 6 15 9 28
CBM 1,079 330 323 18 408
Shallow Gas(1) 1,914 649 608 241 416
-------------------------------------------------------------------------
Total gas wells 3,772 1,146 1,120 479 1,027
-------------------------------------------------------------------------
Oil
Foster Creek(2) 23 6 8 1 8
Christina Lake(2) 3 - 1 2 -
Pelican Lake - - - - -
-------------------------------------------------------------------------
Total oil wells 26 6 9 3 8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total 3,798 1,152 1,129 482 1,035
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     -------------------------------------------------------------------------
Net Wells Drilled
-----------------------------------------------
Resource Play 2006 2005
-----------------------------------------------
Full Full
year Q4 Q3 Q2 Q1 Year
-------------------------------------------------------------------------
Natural gas
Jonah 163 41 48 48 26 104
Piceance 220 50 48 59 63 266
East Texas 59 11 12 17 19 84
Fort Worth 97 19 22 27 29 59
Greater Sierra 115 5 16 34 60 164
Cutbank Ridge 116 19 35 36 26 135
Bighorn 52 7 7 18 20 51
CBM 729 157 156 35 381 1,245
Shallow Gas(1) 1,310 389 475 217 229 1,389
-------------------------------------------------------------------------
Total gas wells 2,861 698 819 491 853 3,497
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Oil
Foster Creek(2) 3 - - - 3 20
Christina Lake(2) 1 - - - 1 -
Pelican Lake - - - - - 52
-------------------------------------------------------------------------
Total oil wells 4 - - - 4 72
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total 2,865 698 819 491 857 3,569
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Shallow Gas net wells drilled in 2006 and 2005 were restated in the
first quarter 2007 as a result of reporting commingled volumes from
multiple zones within the same geographic area based upon regulatory
approval.
(2) Foster Creek and Christina Lake net wells drilled in 2006 and 2005
were restated in the first quarter 2007 on a pro forma basis to
reflect the integrated oil transaction.

2007 proved reserves
     EnCana achieved 12 percent growth in proved reserves at a competitive
finding and development cost of $1.65 per Mcfe
All of EnCana's proved reserves are evaluated by independent qualified
reserves evaluators.
     -------------------------------------------------------------------------
2007 Proved Reserves Reconciliation
-------------------------------------------------------------------------
Crude oil
and Natural
Natural gas Gas Liquids
(Bcf) (MMbbls)
-------------------------------------------------------------------------
Canada USA Total Canada Canada
Conv. Bitumen
-------------------------------------------------------------------------
Start of 2007 7,028 5,390 12,418 279.8 799.6
Partnership contribution(2) - - - - (398.0)
-------------------------------------------------------------------------
Effective Jan. 2, 2007 7,028 5,390 12,418 279.8 401.6
-------------------------------------------------------------------------
Revisions and improved
recovery 87 78 165 12.8 62.7
Extensions & discoveries 949 827 1,776 13.8 142.0
Purchase of reserves in place 63 211 274 0.2 -
Sale of reserves in place (24) (7) (31) (0.2) -
Production (811) (491) (1,302) (33.0) (10.8)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
End of Year 7,292 6,008 13,300 273.4 595.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
% Change(3) + 4 + 11 + 7 - 2 + 48
Developed 4,868 3,368 8,236 217.8 71.7
Undeveloped 2,424 2,640 5,064 55.6 523.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total 7,292 6,008 13,300 273.4 595.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-----------------------------------------------------------------
2007 Proved Reserves Reconciliation
-----------------------------------------------------------------
Crude oil and Natural Gas Equiv-
Gas Liquids alent(1)
(MMbbls) (Bcfe)
-----------------------------------------------------------------
Canada USA Total Total
Total
-----------------------------------------------------------------
Start of 2007 1,079.4 54.0 1,133.4 19,218
Partnership contribution(2) (398.0) - (398.0) (2,388)
-----------------------------------------------------------------
Effective Jan. 2, 2007 681.4 54.0 735.4 16,830
-----------------------------------------------------------------
Revisions and improved
recovery 75.5 3.6 79.1 640
Extensions & discoveries 155.8 5.9 161.7 2,746
Purchase of reserves in place 0.2 - 0.2 275
Sale of reserves in place (0.2) - (0.2) (32)
Production (43.8) (5.2) (49.0) (1,596)
-----------------------------------------------------------------
-----------------------------------------------------------------
End of Year 868.9 58.3 927.2 18,863
-----------------------------------------------------------------
-----------------------------------------------------------------
% Change(3) + 28 + 8 + 26 + 12
-----------------------------------------------------------------
-----------------------------------------------------------------
Developed 289.5 37.0 326.5 10,195
Undeveloped 579.4 21.3 600.7 8,668
-----------------------------------------------------------------
-----------------------------------------------------------------
Total 868.9 58.3 927.2 18,863
-----------------------------------------------------------------
-----------------------------------------------------------------
(1) Gas equivalency has been calculated by EnCana. See the Advisory
Regarding Reserves Data and Other Oil and Gas Information
accompanying this release.
(2) Effective January 2, 2007, EnCana established an integrated oil
business with ConocoPhillips, which resulted in EnCana contributing
its interests in Foster Creek and Christina Lake to an upstream
partnership owned 50-50 by the two companies.
(3) EnCana's growth in proved reserves is expressed as the percentage
change from January 2, 2007 to the end of the year.
     -------------------------------------------------------------------------
Proved Reserves Costs
-------------------------------------------------------------------------
2007 2006 2005 3 Years
-------------------------------------------------------------------------
Capital investment ($millions)
-------------------------------------------------------------------------
Finding and development 5,587 6,107 6,231 17,925
Acquisitions 2,708 368 472 3,548
-------------------------------------------------------------------------
Finding, development and
acquisitions 8,295 6,475 6,703 21,473
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Reserves additions (Bcfe)
Finding and development 3,386 3,064 4,849 11,299
Acquisitions 275 69 85 429
-------------------------------------------------------------------------
Finding, development and
acquisitions 3,661 3,133 4,934 11,728
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Proved reserves costs ($/Mcfe)
Finding and development 1.65 1.99 1.29 1.59
Finding, development and
acquisitions 2.27 2.07 1.36 1.83
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>

Finding and development costs by commodity
     In 2007, F&D costs for natural gas and associated liquids were
approximately $2.40 per Mcfe, down from about $2.70 per Mcfe in 2006. Natural
gas and associated liquids reserves additions were approximately 2.0 Tcfe with
capital investments of $4.7 billion in 2007, compared to 2006 reserves
additions of about 1.9 Tcfe with capital investments of $5 billion.
In 2007, F&D costs for crude oil were approximately $3.60 per bbl, down
from about $5.45 per bbl in 2006. Crude oil reserves additions were
approximately 233 million bbls and capital investments were $840 million in
2007, compared to 2006 reserves additions of about 199 million bbls and
capital investments of $1.1 billion.
For the three years, 2005-2007, EnCana's F&D costs for natural gas and
associated liquids averaged approximately $2.35 per Mcfe based on total
reserves additions of about 6.4 Tcfe and total capital investments of $15
billion. For the same period, F&D costs for crude oil averaged approximately
$3.60 per bbl based on total reserves additions of about 820 million bbls and
total capital investments of $3 billion.
     Reserves replacement cost in 2007
     Reserves replacement cost for 2007 post integrated oil was approximately
$2.20 per Mcfe, which includes divestitures of 32 Bcfe for proceeds of
$382 million. EnCana's three-year (2005 - 2007) reserves replacement cost was
approximately $1.60 per Mcfe.

<<
-------------------------------------------------------------------------
2007 Natural Gas and Oil Prices
-------------------------------------------------------------------------
Q4 Q4 % %
2007 2006 change 2007 2006 change
-------------------------------------------------------------------------
Natural gas
($/Mcf, realized
prices include
hedging)
NYMEX 6.96 6.55 + 6 6.86 7.22 - 5
EnCana realized gas
price 7.32 6.70 + 9 7.22 6.72 + 7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Oil and NGLs
($/bbl, realized
prices include
hedging)
WTI 90.50 60.17 + 50 72.41 66.25 + 9
Western Canadian
Select (WCS) 56.82 39.08 + 45 49.50 44.69 + 11
Differential WTI/WCS 33.68 21.09 + 60 22.91 21.56 + 6
EnCana realized
liquids price 50.84 35.39 + 44 47.00 40.39 + 16
-------------------------------------------------------------------------
-------------------------------------------------------------------------
3-2-1 crack spread
($/bbl)
U.S. Gulf Coast 6.55 6.77 - 3 13.16 10.83 + 22
U.S. Mid-Continent 9.37 10.11 - 7 19.10 14.32 + 33
Chicago 9.17 9.70 - 5 17.67 13.38 + 32
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>

Price risk management
     Risk management positions at December 31, 2007 are presented in Note 19
to the unaudited Interim Consolidated Financial Statements for the fourth
quarter 2007. In 2007, EnCana's commodity price risk management measures
resulted in realized gains of approximately $1.0 billion after-tax, composed
of a $1.1 billion after-tax gain on gas price and basis hedges and a
$0.1 billion after-tax loss on oil price hedges and other hedges.
     Half of expected 2008 gas production hedged during first 10 months of
2008
     EnCana has hedged about 1.9 billion Bcf/d of expected gas production from
January to October 2008 at an average NYMEX equivalent price of $8.21 per Mcf.
EnCana has about 23,000 bbls/d of expected 2008 oil production hedged at a
fixed price of WTI $70.13 per bbl. This price hedging strategy helps reduce
uncertainty in cash flow during periods of commodity price volatility.
     U.S. Rockies basis differential hedges
     For 2008, EnCana has hedged 100 percent of its expected U.S. Rockies
basis exposure using a combination of downstream transportation and basis
hedges, including some hedges that are based on a percentage of NYMEX prices.
At December 31, 2007, U.S. basis hedges, a combination of Rockies,
Mid-Continent and San Juan instruments, had an effective annual average
differential of NYMEX less $1.03 per Mcf.
     2008 gas production forecast to increase 6 percent
     In 2008, natural gas production, which represents more than 80 percent of
EnCana's production, is expected to increase about 6 percent to about 3.8
Bcf/d. Oil and NGLs production is expected to average 132,000 bbls/d, down 1
percent, mostly due to natural decline in mature properties. Total production
in 2008 is expected to increase 5 percent to average 4.6 Bcfe/d. EnCana has
updated its corporate guidance on its website: www.encana.com to reflect
actual results for 2007.
     Corporate developments
     Quarterly dividend increased 100 percent to 40 cents per share
     Consistent with the company's focus on shareholder value creation,
EnCana's board of directors declared a quarterly dividend of 40 cents per
share, which is payable on March 31, 2008 to common shareholders of record as
of March 14, 2008. This is double the amount of the previous quarterly
dividend.


     Normal Course Issuer Bid
     In 2007, EnCana purchased 38.9 million shares, or about 5 percent, of the
outstanding shares at an average price of $52.05 per share under the company's
Normal Course Issuer Bid program. The average diluted shares for the year were
764.6 million and the shares outstanding at year end were 750.2 million. In
January 2008, the company purchased 3.0 million shares at an average price of
$63.29 for a cost of $191 million. During 2008, the company plans to purchase
approximately 2 percent of the shares outstanding (about 15 million shares).
     Financial strength

     EnCana maintains a strong balance sheet, targeting a net
debt-to-capitalization ratio between 30 and 40 percent. At December 31, 2007,
the company's net debt-to-capitalization ratio was 34 percent and net
debt-to-adjusted-EBITDA multiple, on a trailing 12-month basis, was 1.2 times.
The increase in the net-debt-to-capitalization ratio from the end of the third
quarter 2007 is primarily due to EnCana's $2.55 billion Deep Bossier
acquisition in Texas in November 2007.
In 2007, EnCana invested $6.0 billion in capital. Net acquisitions were
$2.3 billion, resulting in net capital investment in continuing operations of
$8.3 billion.
     <<
-------------------------------------------------------------------------
CONFERENCE CALL TODAY
11 a.m. Mountain Time (1 p.m. Eastern Time)
     EnCana will host a conference call today Thursday, February 14, 2008
starting at 11:00 a.m. MT (1:00 p.m. ET). To participate, please dial
(866) 321-6651 (toll-free in North America) or (416) 642-5212
approximately 10 minutes prior to the conference call and quote
confirmation code 6891314. An archived recording of the call will be
available from approximately 3:00 p.m. MT on February 14 until midnight
February 21, 2008 by dialling (888) 203-1112 or (647) 436-0148 and
entering access code 6891314.
     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, pre-tax cash flow,
operating earnings and free cash flow.
     -   Cash flow is a non-GAAP measure defined as excluding net change in
other assets and liabilities, net change in non-cash working capital
from continuing operations and net change in non-cash working capital
from discontinued operations, all of which are defined on the
Consolidated Statement of Cash Flows.
- Pre-tax cash flow is calculated as cash flow before cash taxes.
- Operating earnings is a non-GAAP measure that shows net earnings
excluding non-operating items such as the after-tax impacts of a
gain/loss on discontinuance, 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 Notes issued from
Canada and the partnership contribution receivable, the after-tax
foreign exchange gains/losses on settlement of intercompany
transactions and the effect of the reduction in income tax rates.
Management believes that these excluded 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 denominated Notes issued from 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 total capital investment, excluding acquisitions, and is
used to determine the funds available for other investing and/or
financing activities.
>>
     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 $65 billion, EnCana is a
leading North American unconventional natural gas and integrated oil company.
By partnering with employees, community organizations and other businesses,
EnCana contributes to the strength and sustainability of the communities where
it operates. EnCana common shares trade on the Toronto and New York stock
exchanges under the symbol ECA.
     RESERVES COST DEFINITIONS - Production replacement is calculated by
dividing reserves additions by production in the same period. Reserves
additions over a given period, in this case 2007, are calculated by summing
one or more of revisions and improved recovery, extensions and discoveries,
acquisitions and divestitures. Reserves replacement cost is calculated by
dividing total capital invested in finding, development and acquisitions net
of divestitures by reserves 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 2007 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 70 percent of its proved
undeveloped reserves will be developed within the next four years. 2007
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.
     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, net debt-to-capitalization ratio,
sustainable growth and returns, cash flow, free cash flow, cash flow per share
and increases in net asset value); anticipated ability to meet the company's
guidance forecasts; anticipated life of proved reserves; anticipated growth
and success of resource plays and the expected characteristics of resource
plays; the anticipated production, timing thereof, and expenditures associated
with the Deep Panuke Project; planned expansion of in-situ oil production;
anticipated crude oil and natural gas prices, including basis differentials
for various regions; anticipated expansion and production at Foster Creek and
Christina Lake; anticipated increased capacity for the Borger and Wood River
refineries; anticipated integrated oil cash flow; projections for future crack
spreads and anticipated refining profits; anticipated drilling inventory;
expected proportion of total production and cash flows contributed by natural
gas; anticipated success of EnCana's market risk mitigation strategy;
anticipated purchases pursuant to the Normal Course Issuer Bid and the source
of funding therefore; potential demand for natural gas; anticipated bitumen
production in 2008 and beyond; anticipated drilling; potential capital
expenditures and investment; potential oil, natural gas and NGLs production in
2008 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; the ability of the company and ConocoPhillips to successfully
manage and operate the integrated North American oil business and the ability
of the parties to obtain necessary regulatory approvals; refining and
marketing margins; potential disruption or unexpected technical difficulties
in developing new products and manufacturing processes; potential failure of
new products to achieve acceptance in the market; unexpected cost increases or
technical difficulties in constructing or modifying manufacturing or refining
facilities; unexpected difficulties in manufacturing, transporting or refining
synthetic crude oil; risks associated with technology; the company's ability
to 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 royalty, tax, environmental and
other laws or regulations or the interpretations of such laws or regulations;
political and economic conditions in the countries in which the company
operates; 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, except as required
by law, EnCana does not undertake any obligation to update publicly or to
revise any of the included forward-looking statements, whether as a result of
new information, future events or otherwise. The forward-looking statements
contained in this news release are expressly qualified by this cautionary
statement.

<<
Interim Consolidated Financial Statements
     (unaudited)
For the period ended December 31, 2007
     EnCana Corporation
     U.S. DOLLARS


CONSOLIDATED STATEMENT OF EARNINGS (unaudited)
                                       Three Months Ended  Twelve Months Ended
December 31, December 31,
($ millions, except per ---------------------------------------
share amounts) 2007 2006 2007 2006
-------------------------------------------------------------------------


     REVENUES, NET OF ROYALTIES (Note 6)
Upstream $ 3,161 $ 2,552 $ 11,758 $ 10,369
Integrated Oil 2,369 260 7,983 973
Market Optimization 837 735 2,944 3,007
Corporate - Unrealized gain
(loss) on risk management (566) 129 (1,239) 2,050
-------------------------------------------------------------------------
5,801 3,676 21,446 16,399
     EXPENSES                   (Note 6)
Production and mineral taxes 63 80 291 349
Transportation and selling 278 275 1,010 1,070
Operating 632 428 2,278 1,655
Purchased product 2,704 702 8,583 2,862
Depreciation, depletion and
amortization 1,086 766 3,816 3,112
Administrative 121 84 384 271
Interest, net (Note 9) 131 142 428 396
Accretion of asset
retirement obligation (Note 15) 18 13 64 50
Foreign exchange (gain)
loss, net (Note 10) (233) 172 (164) 14
(Gain) loss on
divestitures (Note 8) 22 (2) (65) (323)
-------------------------------------------------------------------------
4,822 2,660 16,625 9,456
-------------------------------------------------------------------------
NET EARNINGS BEFORE INCOME TAX 979 1,016 4,821 6,943
Income tax expense (Note 11) (28) 373 937 1,892
-------------------------------------------------------------------------
NET EARNINGS FROM CONTINUING
OPERATIONS 1,007 643 3,884 5,051
NET EARNINGS FROM DISCONTINUED
OPERATIONS (Note 7) 75 20 75 601
-------------------------------------------------------------------------
NET EARNINGS $ 1,082 $ 663 $ 3,959 $ 5,652
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     NET EARNINGS FROM CONTINUING
OPERATIONS PER COMMON
SHARE (Note 18)
Basic $ 1.34 $ 0.81 $ 5.13 $ 6.16
Diluted $ 1.33 $ 0.80 $ 5.08 $ 6.04
-------------------------------------------------------------------------
-------------------------------------------------------------------------


     NET EARNINGS PER COMMON
SHARE (Note 18)
Basic $ 1.44 $ 0.84 $ 5.23 $ 6.89
Diluted $ 1.43 $ 0.82 $ 5.18 $ 6.76
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.
     CONSOLIDATED STATEMENT OF RETAINED EARNINGS (unaudited)

                                                           Twelve Months Ended
December 31,
-------------------
($ millions) 2007 2006
-------------------------------------------------------------------------
     RETAINED EARNINGS, BEGINNING OF YEAR                  $ 11,344  $  9,481
Net Earnings 3,959 5,652
Dividends on Common Shares (603) (304)
Charges for Normal Course Issuer Bid (Note 16) (1,618) (3,485)
-------------------------------------------------------------------------
RETAINED EARNINGS, END OF YEAR $ 13,082 $ 11,344
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (unaudited)
                                       Three Months Ended  Twelve Months Ended
December 31, December 31,
---------------------------------------
($ millions) 2007 2006 2007 2006
-------------------------------------------------------------------------


     NET EARNINGS                      $  1,082  $    663  $  3,959  $  5,652
OTHER COMPREHENSIVE INCOME, NET
OF TAX
Foreign Currency Translation
Adjustment (110) (418) 1,688 113
-------------------------------------------------------------------------
COMPREHENSIVE INCOME $ 972 $ 245 $ 5,647 $ 5,765
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     CONSOLIDATED STATEMENT OF ACCUMULATED OTHER COMPREHENSIVE INCOME
(unaudited)
                                                           Twelve Months Ended
December 31,
-------------------
($ millions) 2007 2006
-------------------------------------------------------------------------
     ACCUMULATED OTHER COMPREHENSIVE INCOME, BEGINNING
OF YEAR $ 1,375 $ 1,262
Foreign Currency Translation Adjustment 1,688 113
-------------------------------------------------------------------------
ACCUMULATED OTHER COMPREHENSIVE INCOME, END OF YEAR $ 3,063 $ 1,375
-------------------------------------------------------------------------
-------------------------------------------------------------------------


     See accompanying Notes to Consolidated Financial Statements.
     CONSOLIDATED BALANCE SHEET (unaudited)
                                                           As at        As at
December 31, December 31,
($ millions) 2007 2006
-------------------------------------------------------------------------
     ASSETS
Current Assets
Cash and cash equivalents $ 553 $ 402
Accounts receivable and accrued
revenues 2,381 1,721
Current portion of partnership
contribution receivable (Notes 5, 12) 297 -
Risk management (Note 19) 385 1,403
Inventories (Note 13) 828 176
-------------------------------------------------------------------------
4,444 3,702
Property, Plant and Equipment, net (Note 6) 35,865 28,213
Investments and Other Assets 607 533
Partnership Contribution
Receivable (Notes 5, 12) 3,147 -
Risk Management (Note 19) 18 133
Goodwill 2,893 2,525
-------------------------------------------------------------------------
(Note 6) $ 46,974 $ 35,106
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued
liabilities $ 3,982 $ 2,494
Income tax payable 1,150 926
Current portion of partnership
contribution payable (Notes 5, 12) 288 -
Risk management (Note 19) 207 14
Current portion of long-term debt (Note 14) 703 257
-------------------------------------------------------------------------
6,330 3,691
Long-Term Debt (Note 14) 8,840 6,577
Other Liabilities 242 79
Partnership Contribution
Payable (Notes 5, 12) 3,163 -
Risk Management (Note 19) 29 2
Asset Retirement Obligation (Note 15) 1,458 1,051
Future Income Taxes 6,208 6,240
-------------------------------------------------------------------------
26,270 17,640
-------------------------------------------------------------------------
Shareholders' Equity
Share capital (Note 16) 4,479 4,587
Paid in surplus 80 160
Retained earnings 13,082 11,344
Accumulated other comprehensive
income 3,063 1,375
-------------------------------------------------------------------------
Total Shareholders' Equity 20,704 17,466
-------------------------------------------------------------------------
$ 46,974 $ 35,106
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     See accompanying Notes to Consolidated Financial Statements.
     CONSOLIDATED STATEMENT OF CASH FLOWS (unaudited)
                                       Three Months Ended  Twelve Months Ended
December 31, December 31,
---------------------------------------
($ millions) 2007 2006 2007 2006
-------------------------------------------------------------------------
     OPERATING ACTIVITIES
Net earnings from
continuing operations $ 1,007 $ 643 $ 3,884 $ 5,051
Depreciation, depletion
and amortization 1,086 766 3,816 3,112
Future income taxes (Note 11) (608) 260 (617) 950
Cash tax on sale of
assets (Note 8) - - - 49
Unrealized (gain) loss
on risk management (Note 19) 569 (141) 1,235 (2,060)
Unrealized foreign
exchange (gain) loss (52) 155 41 -
Accretion of asset
retirement obligation (Note 15) 18 13 64 50
(Gain) loss on
divestitures (Note 8) 22 (2) (65) (323)
Other (108) 48 95 214
Cash flow from
discontinued operations - 19 - 118
Net change in other
assets and liabilities (21) 90 (16) 138
Net change in non-cash
working capital from
continuing operations 280 39 (8) 3,343
Net change in non-cash
working capital from
discontinued operations - (193) - (2,669)
-------------------------------------------------------------------------
Cash From Operating
Activities 2,193 1,697 8,429 7,973
-------------------------------------------------------------------------
     INVESTING ACTIVITIES
Capital expenditures (Note 6) (4,408) (1,250) (8,737) (6,600)
Proceeds from
divestitures (Note 8) (24) 55 481 689
Cash tax on sale of
assets (Note 8) - - - (49)
Net change in investments
and other (31) 40 (5) 2
Net change in non-cash
working capital from
continuing operations 120 188 86 19
Discontinued operations - 180 - 2,557
-------------------------------------------------------------------------
Cash (Used in) Investing
Activities (4,343) (787) (8,175) (3,382)
-------------------------------------------------------------------------
     FINANCING ACTIVITIES
Net issuance (repayment)
of revolving long-term debt 1,090 646 181 134
Issuance of long-term
debt (Note 14) 1,485 - 2,409 -
Repayment of long-term
debt (257) - (257) (73)
Issuance of common
shares (Note 16) 18 39 176 179
Purchase of common
shares (Note 16) - (1,246) (2,025) (4,219)
Dividends on common shares (150) (78) (603) (304)
Other 1 (3) - (11)
-------------------------------------------------------------------------
Cash From (Used in)
Financing Activities 2,187 (642) (119) (4,294)
-------------------------------------------------------------------------
     FOREIGN EXCHANGE GAIN (LOSS)
ON CASH AND CASH
EQUIVALENTS HELD IN FOREIGN
CURRENCY 1 - 16 -
-------------------------------------------------------------------------
     INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS 38 268 151 297
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD 515 134 402 105
-------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS,
END OF PERIOD $ 553 $ 402 $ 553 $ 402
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     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. EnCana's continuing operations are in the business of
exploration for, and development, production and marketing of natural
gas, crude oil and natural gas liquids, refining operations 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, 2006, except as noted below. The disclosures provided below
are incremental to those included with the annual audited Consolidated
Financial Statements. The interim Consolidated Financial Statements
should be read in conjunction with the annual audited Consolidated
Financial Statements and the notes thereto for the year ended
December 31, 2006.
     2.  CHANGES IN ACCOUNTING POLICIES AND PRACTICES
     As disclosed in the December 31, 2006 annual audited Consolidated
Financial Statements, on January 1, 2007, the Company adopted the
Canadian Institute of Chartered Accountants ("CICA") Handbook Section
1530, "Comprehensive Income", Section 3251, "Equity", Section 3855,
"Financial Instruments - Recognition and Measurement", and Section 3865,
"Hedges". As required by the new standards, prior periods have not been
restated, except to reclassify the foreign currency translation
adjustment balance as described under Comprehensive Income.
     The adoption of these standards has had no material impact on the
Company's net earnings or cash flows. The other effects of the
implementation of the new standards are discussed below.
     Comprehensive Income
     The new standards introduce comprehensive income, which consists of net
earnings and Other Comprehensive Income ("OCI"). The Company's
Consolidated Financial Statements now include a Statement of
Comprehensive Income, which includes the components of comprehensive
income. For EnCana, OCI is currently comprised of the changes in the
foreign currency translation adjustment balance.
     The cumulative changes in OCI are included in Accumulated Other
Comprehensive Income ("AOCI"), which is presented as a new category
within shareholders' equity in the Consolidated Balance Sheet. The
accumulated foreign currency translation adjustment, formerly presented
as a separate category within shareholders' equity, is now included in
AOCI. The Company's Consolidated Financial Statements now include a
Statement of Accumulated Other Comprehensive Income, which provides the
continuity of the AOCI balance.
     The adoption of comprehensive income has been made in accordance with the
applicable transitional provisions. Accordingly, the December 31, 2007
year end accumulated foreign currency translation adjustment balance of
$3,063 million is now included in AOCI (December 31, 2006 - $1,375
million). In addition, the change in the accumulated foreign currency
translation adjustment balance for the three months and twelve months
ended December 31, 2007 of $(110) million and $1,688 million,
respectively, is now included in OCI in the Statement of Comprehensive
Income (three months and twelve months ended December 31, 2006 - $(418)
million and $113 million, respectively).
     Financial Instruments
     The financial instruments standard establishes the recognition and
measurement criteria for financial assets, financial liabilities and
derivatives. All financial instruments are required to be measured at
fair value on initial recognition of the instrument, except for certain
related party transactions. Measurement in subsequent periods depends on
whether the financial instrument has been classified as "held-for-
trading", "available-for-sale", "held-to-maturity", "loans and
receivables", or "other financial liabilities" as defined by the
accounting standard.
     Financial assets and financial liabilities "held-for-trading" are
measured at fair value with changes in those fair values recognized in
net earnings. Financial assets "available-for-sale" are measured at fair
value, with changes in those fair values recognized in OCI. Financial
assets "held-to-maturity", "loans and receivables" and "other financial
liabilities" are measured at amortized cost using the effective interest
method of amortization.


     Cash and cash equivalents are designated as "eld-for-trading" and are
measured at fair value. Accounts receivable and accrued revenues and the
partnership contribution receivable are designated as "oans and
receivables". Accounts payable and accrued liabilities, the partnership
contribution payable and long-term debt are designated as "other
financial liabilities".
     The adoption of the financial instruments standard has been made in
accordance with its transitional provisions. Accordingly, at January 1,
2007, $52 million of other assets were reclassified to long-term debt to
reflect the adopted policy of capitalizing long-term debt transaction
costs, premiums and discounts within long-term debt. The costs
capitalized within long-term debt will be amortized using the effective
interest method. Previously, the Company deferred these costs within
other assets and amortized them straight-line over the life of the
related long-term debt. The adoption of the effective interest method of
amortization had no effect on opening retained earnings.
     Risk management assets and liabilities are derivative financial
instruments classified as "held-for-trading" unless designated for hedge
accounting. Additional information on the Company's accounting treatment
of derivative financial instruments is contained in Note 1 of the
Company's annual audited Consolidated Financial Statements for the year
ended December 31, 2006.
     3.  UPDATE TO ACCOUNTING POLICIES AND PRACTICES

     As a result of the new joint venture with ConocoPhillips, EnCana has
updated the following significant accounting policies and practices to
incorporate the refining business (See Note 5):
     Revenue Recognition
     Revenues associated with the sales of EnCana's natural gas, crude oil,
NGLs and petroleum and chemical products are recognized when title passes
from the Company to its customer. Natural gas and crude oil produced and
sold by EnCana below or above its working interest share in the related
resource properties results in production underliftings or overliftings.
Underliftings are recorded as inventory and overliftings are recorded as
deferred revenue. Realized gains and losses from the Company's natural
gas and crude oil commodity price risk management activities are recorded
in revenue when the product is sold.
     Market optimization revenues and purchased product are recorded on a
gross basis when EnCana takes title to product and has risks and rewards
of ownership. Purchases and sales of inventory with the same counterparty
that are entered into in contemplation of each other are recorded on a
net basis. Revenues associated with the services provided where EnCana
acts as agent are recorded as the services are provided. Revenues
associated with the sale of natural gas storage services are recognized
when the services are provided. Sales of electric power are recognized
when power is provided to the customer.
     Unrealized gains and losses from the Company's natural gas and crude oil
commodity price risk management activities are recorded as revenue based
on the related mark-to-market calculations at the end of the respective
period.
     Inventory
     Product inventories, including petroleum and chemical products, are
valued at the lower of average cost and net realizable value on a first-
in, first-out basis.
     Property, Plant and Equipment
     Upstream
     EnCana accounts for natural gas and crude oil properties in accordance
with the Canadian Institute of Chartered Accountants' guideline on full
cost accounting in the oil and gas industry. Under this method, all
costs, including internal costs and asset retirement costs, directly
associated with the acquisition of, exploration for, and the development
of natural gas and crude oil reserves, are capitalized on a country-by-
country cost centre basis.
     Costs accumulated within each cost centre are depreciated, depleted and
amortized using the unit-of-production method based on estimated proved
reserves determined using estimated future prices and costs. For purposes
of this calculation, oil is converted to gas on an energy equivalent
basis. Capitalized costs subject to depletion include estimated future
costs to be incurred in developing proved reserves. Proceeds from the
divestiture of properties are normally deducted from the full cost pool
without recognition of gain or loss unless that deduction would result in
a change to the rate of depreciation, depletion and amortization of 20
percent or greater, in which case a gain or loss is recorded. Costs of
major development projects and costs of acquiring and evaluating
significant unproved properties are excluded, on a cost centre basis,
from the costs subject to depletion until it is determined whether or not
proved reserves are attributable to the properties, or impairment has
occurred. Costs that have been impaired are included in the costs subject
to depreciation, depletion and amortization.
     An impairment loss is recognized in net earnings when the carrying amount
of a cost centre is not recoverable and the carrying amount of the cost
centre exceeds its fair value. The carrying amount of the cost centre is
not recoverable if the carrying amount exceeds the sum of the
undiscounted cash flows from proved reserves. If the sum of the cash
flows is less than the carrying amount, the impairment loss is limited to
the amount by which the carrying amount exceeds the sum of:


     i.  the fair value of proved and probable reserves; and
ii. the costs of unproved properties that have been subject to a separate
impairment test.
     Downstream
     The initial acquisition costs of refinery property, plant and equipment
are capitalized when incurred. Costs include the cost of constructing or
otherwise acquiring the equipment or facilities, the cost of installing
the asset and making it ready for its intended use and the associated
asset retirement costs. Capitalized costs are not subject to depreciation
until the asset is put into use, after which they are depreciated on a
straight-line basis over their estimated service lives of approximately
25 years.
     An impairment loss is recognized on refinery property, plant and
equipment when the carrying amount is not recoverable and exceeds its
fair value. The carrying amount is not recoverable if the carrying amount
exceeds the sum of the undiscounted cash flows from expected use and
eventual disposition. If the carrying amount is not recoverable, an
impairment loss is measured as the amount by which the refinery asset
exceeds the discounted future cash flows from the refinery asset.


     Market Optimization
     Midstream facilities, including natural gas storage facilities, natural
gas liquids extraction plant facilities and power generation facilities,
are carried at cost and depreciated on a straight-line basis over the
estimated service lives of the assets, which range from 20 to 25 years.
Capital assets related to pipelines are carried at cost and depreciated
using the straight-line method over their economic lives, which range
from 20 to 35 years.
     Corporate
     Costs associated with office furniture, fixtures, leasehold improvements,
information technology and aircraft are carried at cost and depreciated
on a straight-line basis over the estimated service lives of the assets,
which range from three to 25 years. Assets under construction are not
subject to depreciation until put into use. Land is carried at cost.


     Asset Retirement Obligation
     The fair value of estimated asset retirement obligations is recognized in
the Consolidated Balance Sheet when identified and a reasonable estimate
of fair value can be made.
     Asset retirement obligations include those legal obligations where the
Company will be required to retire tangible long-lived assets such as
producing well sites, offshore production platforms, natural gas
processing plants and refining facilities. These obligations also include
items for which the Company has made promissory estoppel. The asset
retirement cost, equal to the initially estimated fair value of the asset
retirement obligation, is capitalized as part of the cost of the related
long-lived asset. Changes in the estimated obligation resulting from
revisions to estimated timing or amount of undiscounted cash flows are
recognized as a change in the asset retirement obligation and the related
asset retirement cost.
     Amortization of asset retirement costs are included in depreciation,
depletion and amortization in the Consolidated Statement of Earnings.
Increases in the asset retirement obligation resulting from the passage
of time are recorded as accretion of asset retirement obligation in the
Consolidated Statement of Earnings.
     Actual expenditures incurred are charged against the accumulated
obligation.
     4.  RECENT ACCOUNTING PRONOUNCEMENT
     As of January 1, 2008, EnCana is required to adopt the CICA Handbook
Section 3031, "Inventories", which will replace the existing inventories
standard. The new standard requires inventory to be valued on a first-in,
first-out or weighted average basis, which is consistent with EnCana's
current treatment. The adoption of this standard should not have a
material impact on EnCana's Consolidated Financial Statements.
     5.  JOINT VENTURE WITH CONOCOPHILLIPS
     On January 2, 2007, EnCana became a 50 percent partner in an integrated,
North American oil business with ConocoPhillips which consists of an
upstream and a downstream entity. The upstream entity contribution
included assets from EnCana, primarily the Foster Creek and Christina
Lake properties, with a fair value of $7.5 billion and a note receivable
from ConocoPhillips of an equal amount. For the downstream entity,
ConocoPhillips contributed its Wood River and Borger refineries, located
in Illinois and Texas respectively, for a fair value of $7.5 billion and
EnCana contributed a note payable of $7.5 billion. Further information
about these notes is included in Note 12.
     In accordance with Canadian generally accepted accounting principles,
these entities have been accounted for using the proportionate
consolidation method with the results of operations shown in a separate
business segment, Integrated Oil (See Note 6).
     6.  SEGMENTED INFORMATION
     The Company has defined its continuing operations into the following
segments:
     -   Canada, United States and Other includes the Company's upstream
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. Offshore and international exploration is
mainly focused on opportunities in Atlantic Canada, the Middle East,
and Europe.


     -   Integrated Oil is focused on two lines of business: the exploration
for, and development and production of bitumen in Canada using in-
situ recovery methods; and the refining of crude oil into petroleum
and chemical products located in the United States. This segment
represents EnCana's 50 percent interest in the joint venture with
ConocoPhillips.
     -   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
Canada, United States and Integrated Oil segments. 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
financial instruments. Once amounts are settled, the realized gains
and losses are recorded in the operating segment to which the
derivative instrument relates.
     Market Optimization markets substantially all of the Company's upstream
production 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.
     In 2007, as a result of the joint venture with ConocoPhillips, EnCana
redefined its business segments to those described above. All prior
periods have been restated to conform with the current presentation.
     Operations that have been discontinued are disclosed in Note 7.
     Results of Continuing Operations (For the three months ended December 31)


                                                  Upstream
-----------------------------------------------
Canada United States Other
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
     Revenues, Net of
Royalties $1,964 $1,718 $1,110 $ 765 $ 87 $ 69
Expenses
Production and mineral
taxes 16 20 47 60 - -
Transportation and
selling 83 107 87 66 - -
Operating 292 227 95 76 82 61
Purchased product - - - - - -
Depreciation, depletion
and amortization 599 494 324 200 52 6
-------------------------------------------------------------------------
Segment Income (Loss) $ 974 $ 870 $ 557 $ 363 $ (47) $ 2
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Integrated Market
Total Upstream Oil Optimization
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
     Revenues, Net of
Royalties $3,161 $2,552 $2,369 $ 260 $ 837 $ 735
Expenses
Production and mineral
taxes 63 80 - - - -
Transportation and
selling 170 173 108 103 - (1)
Operating 469 364 151 64 9 13
Purchased product - - 1,888 - 816 702
Depreciation, depletion
and amortization 975 700 77 43 6 4
-------------------------------------------------------------------------
Segment Income (Loss) $1,484 $1,235 $ 145 $ 50 $ 6 $ 17
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Corporate Consolidated
-------------------------------------------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
     Revenues, Net of Royalties                $ (566) $  129  $5,801  $3,676
Expenses
Production and mineral taxes - - 63 80
Transportation and selling - - 278 275
Operating 3 (13) 632 428
Purchased product - - 2,704 702
Depreciation, depletion and amortization 28 19 1,086 766
-------------------------------------------------------------------------
Segment Income (Loss) $ (597) $ 123 1,038 1,425
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Administrative 121 84
Interest, net 131 142
Accretion of asset retirement obligation 18 13
Foreign exchange (gain) loss, net (233) 172
(Gain) loss on divestitures 22 (2)
-------------------------------------------------------------------------
59 409
-------------------------------------------------------------------------
Net Earnings Before Income Tax 979 1,016
Income tax expense (28) 373
-------------------------------------------------------------------------
Net Earnings From Continuing Operations $1,007 $ 643
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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

Produced Gas
-------------------------------------------------------------------------
Canada United States Total
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
     Revenues, Net of
Royalties $1,510 $1,401 $1,011 $ 706 $2,521 $2,107
Expenses
Production and mineral
taxes 8 11 40 54 48 65
Transportation and
selling 72 66 87 66 159 132
Operating 214 166 95 76 309 242
-------------------------------------------------------------------------
Operating Cash Flow $1,216 $1,158 $ 789 $ 510 $2,005 $1,668
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Oil & NGLs
-------------------------------------------------------------------------
Canada United States Total
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------


     Revenues, Net of
Royalties $ 454 $ 317 $ 99 $ 59 $ 553 $ 376
Expenses
Production and mineral
taxes 8 9 7 6 15 15
Transportation and
selling 11 41 - - 11 41
Operating 78 61 - - 78 61
-------------------------------------------------------------------------
Operating Cash Flow $ 357 $ 206 $ 92 $ 53 $ 449 $ 259
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Integrated Oil
-------------------------------------------------------------------------
Downstream
Oil Refining Other
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------


     Revenues, Net of
Royalties $ 186 $ 248 $2,206 $ - $ (23) $ 12
Expenses
Transportation and
selling 108 103 - - - -
Operating 36 56 111 - 4 8
Purchased product - - 1,915 - (27) -
-------------------------------------------------------------------------
Operating Cash Flow $ 42 $ 89 $ 180 $ - $ - $ 4
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Integrated Oil
-------------------------------------------------------------------------
Total
-------------------------------------------------------------------------
2007 2006
-------------------------------------------------------------------------
     Revenues, Net of Royalties                                $2,369  $  260
Expenses
Transportation and selling 108 103
Operating 151 64
Purchased product 1,888 -
-------------------------------------------------------------------------
Operating Cash Flow $ 222 $ 93
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Results of Continuing Operations (For the twelve months ended
December 31)
                                                  Upstream
-----------------------------------------------
Canada United States Other
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
     Revenues, Net of
Royalties $7,316 $6,970 $4,074 $3,121 $ 368 $ 278
Expenses
Production and mineral
taxes 102 116 189 233 - -
Transportation and
selling 327 330 307 248 - -
Operating 1,010 866 323 283 315 235
Purchased product - - - - - -
Depreciation, depletion
and amortization 2,171 1,989 1,158 848 94 31
-------------------------------------------------------------------------
Segment Income (Loss) $3,706 $3,669 $2,097 $1,509 $ (41) $ 12
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Integrated Market
Total Upstream Oil Optimization
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
     Revenues, Net of
Royalties $11,758 $10,369 $7,983 $ 973 $2,944 $3,007
Expenses
Production and mineral
taxes 291 349 - - - -
Transportation and
selling 634 578 366 476 10 16
Operating 1,648 1,384 598 221 37 62
Purchased product - - 5,725 - 2,858 2,862
Depreciation, depletion
and amortization 3,423 2,868 284 157 17 12
-------------------------------------------------------------------------
Segment Income (Loss) $5,762 $5,190 $1,010 $ 119 $ 22 $ 55
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Corporate Consolidated
-------------------------------------------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
     Revenues, Net of Royalties            $(1,239)  $2,050  $21,446  $16,399
Expenses
Production and mineral taxes - - 291 349
Transportation and selling - - 1,010 1,070
Operating (5) (12) 2,278 1,655
Purchased product - - 8,583 2,862
Depreciation, depletion and
amortization 92 75 3,816 3,112
-------------------------------------------------------------------------
Segment Income (Loss) $(1,326) $1,987 5,468 7,351
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Administrative 384 271
Interest, net 428 396
Accretion of asset retirement obligation 64 50
Foreign exchange (gain) loss, net (164) 14
(Gain) loss on divestitures (65) (323)
-------------------------------------------------------------------------
647 408
-------------------------------------------------------------------------
Net Earnings Before Income Tax 4,821 6,943
Income tax expense 937 1,892
-------------------------------------------------------------------------
Net Earnings From Continuing Operations $3,884 $5,051
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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

Produced Gas
-------------------------------------------------------------------------
Canada United States Total
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
     Revenues, Net of
Royalties $5,671 $5,440 $3,765 $2,854 $9,436 $8,294
Expenses
Production and mineral
taxes 70 80 167 213 237 293
Transportation and
selling 285 278 307 248 592 526
Operating 744 629 323 283 1,067 912
-------------------------------------------------------------------------
Operating Cash Flow $4,572 $4,453 $2,968 $2,110 $7,540 $6,563
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Oil & NGLs
-------------------------------------------------------------------------
Canada United States Total
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------


     Revenues, Net of
Royalties $1,645 $1,530 $ 309 $ 267 $1,954 $1,797
Expenses
Production and mineral
taxes 32 36 22 20 54 56
Transportation and
selling 42 52 - - 42 52
Operating 266 237 - - 266 237
-------------------------------------------------------------------------
Operating Cash Flow $1,305 $1,205 $ 287 $ 247 $1,592 $1,452
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Integrated Oil
-------------------------------------------------------------------------
Downstream
Oil Refining Other
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------


     Revenues, Net of
Royalties $ 738 $ 941 $7,315 $ - $ (70) $ 32
Expenses
Transportation and
selling 366 476 - - - -
Operating 159 194 428 - 11 27
Purchased product - - 5,813 - (88) -
-------------------------------------------------------------------------
Operating Cash Flow $ 213 $ 271 $1,074 $ - $ 7 $ 5
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Integrated Oil
-------------------------------------------------------------------------
Total
-------------------------------------------------------------------------
2007 2006
-------------------------------------------------------------------------
     Revenues, Net of Royalties                                $7,983  $  973
Expenses
Transportation and selling 366 476
Operating 598 221
Purchased product 5,725 -
-------------------------------------------------------------------------
Operating Cash Flow $1,294 $ 276
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Capital Expenditures (Continuing Operations)
                                     Three Months Ended   Twelve Months Ended
December 31, December 31,
-----------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Capital
Canada $ 941 $ 689 $ 3,330 $ 3,352
United States 606 315 1,919 2,061
Other 31 34 106 106
Integrated Oil 208 150 580 632
Market Optimization 1 4 6 44
Corporate 18 25 94 74
-------------------------------------------------------------------------
1,805 1,217 6,035 6,269
-------------------------------------------------------------------------
Acquisition Capital
Canada 8 2 75 11
United States 2,595 16 2,613 284
Other - 15 - 15
Integrated Oil - - 14 21
-------------------------------------------------------------------------
2,603 33 2,702 331
-------------------------------------------------------------------------
Total $ 4,408 $ 1,250 $ 8,737 $ 6,600
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     On November 20, 2007, EnCana acquired certain natural gas and land
interests in Texas for approximately $2.55 billion before closing
adjustments. The purchase was facilitated by an unrelated party, Brown
Kilgore Properties LLC ("Brown Kilgore"), which holds the majority of the
assets in trust for the Company in anticipation of a qualifying like kind
exchange for U.S. tax purposes. Pursuant to the agreement with Brown
Kilgore, EnCana operates the properties, receives all the revenue and
pays all of the expenses associated with the properties. The arrangement
with Brown Kilgore will be complete on May 18, 2008 and the assets will
be transferred to EnCana at that time. EnCana has determined that the
relationship with Brown Kilgore represents an interest in a Variable
Interest Entity ("VIE") and that EnCana is the primary beneficiary of the
VIE. EnCana has consolidated Brown Kilgore from the date of acquisition.
     Property, Plant and Equipment and Total Assets by Segment
                                         Property,
Plant and Equipment Total Assets
------------------------------------------
As at As at
------------------------------------------
December December December December
31, 2007 31, 2006 31, 2007 31, 2006
-------------------------------------------------------------------------
Canada $ 17,631 $ 16,783 $ 21,429 $ 20,188
United States 11,879 8,494 12,948 9,509
Other 1,104 1,182 1,135 1,224
Integrated Oil 4,721 1,322 9,597 1,379
Market Optimization 171 154 478 468
Corporate 359 278 1,387 2,338
-------------------------------------------------------------------------
Total $ 35,865 $ 28,213 $ 46,974 $ 35,106
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     On February 9, 2007, EnCana announced that it had completed the next
phase in the development of The Bow office project with the sale of
project assets and has entered into a 25 year lease agreement with a
third party developer. Corporate Property, Plant and Equipment and Total
Assets includes EnCana's accrual to date of $147 million related to this
office project as an asset under construction. A corresponding liability
is included in Other Liabilities in the Consolidated Balance Sheet. There
is no effect on the Company's net earnings or cash flows related to the
capitalization of The Bow office project.
     7.  DISCONTINUED OPERATIONS
     Midstream
     The $75 million gain on discontinuance in 2007 is the result of an
expired clause included in the December 2005 sale of the Company's
Midstream natural gas liquids processing operations. The clause provided
potential market price support for the facilities and was accrued for in
2005.
     During 2006, EnCana completed, in two separate transactions with a single
purchaser, the sale of its natural gas storage operations in Canada and
the United States. Total proceeds received were approximately $1.5
billion and an after-tax gain on sale of $829 million was recorded.
     Ecuador
     On February 28, 2006, EnCana completed the sale of its Ecuador operations
for proceeds of $1.4 billion before indemnifications. A loss of $279
million, including the impact of indemnifications, was recorded.
     Amounts recorded as depreciation, depletion and amortization in 2006
represent provisions which were recorded against the net book value of
the Ecuador operations to recognize Management's best estimate of the
difference between the selling price and the underlying accounting value
of the related investments, as required by Canadian generally accepted
accounting principles.
     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 Total
------------------------------------------------------
2007 2006 2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net
of Royalties $ - $ - $ - $ - $ - $ 5 $ - $ 5
-------------------------------------------------------------------------
Expenses
Production and
mineral taxes - - - - - - - -
Transportation
and selling - - - - - - - -
Operating - - - - - 8 - 8
Purchased
product - - - - - 2 - 2
Depreciation,
depletion and
amortization - - - - - - - -
Interest, net - - - - - - - -
Foreign exchange
(gain) loss, net - - - (1) - (1) - (2)
(Gain) loss on
discontinuance - - - - (75) (41) (75) (41)
-------------------------------------------------------------------------
- - - (1) (75) (32) (75) (33)
-------------------------------------------------------------------------
Net Earnings
(Loss) Before
Income Tax - - - 1 75 37 75 38
Income tax
expense - - - 1 - 17 - 18
-------------------------------------------------------------------------
Net Earnings
(Loss) From
Discontinued
Operations $ - $ - $ - $ - $ 75 $ 20 $ 75 $ 20
-------------------------------------------------------------------------
-------------------------------------------------------------------------

For the twelve months ended December 31,
------------------------------------------------------
Ecuador United Kingdom Midstream Total
------------------------------------------------------
2007 2006 2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of
Royalties(x) $ - $ 200 $ - $ - $ - $ 482 $ - $ 682
-------------------------------------------------------------------------
Expenses
Production and
mineral taxes - 23 - - - - - 23
Transportation
and selling - 10 - - - - - 10
Operating - 25 - - - 37 - 62
Purchased product - - - - - 356 - 356
Depreciation,
depletion and
amortization - 84 - - - - - 84
Interest, net - (2) - - - - - (2)
Foreign exchange
(gain) loss, net - 1 - (1) - 4 - 4
(Gain) loss on
discontinuance - 279 - - (75) (807) (75) (528)
-------------------------------------------------------------------------
- 420 - (1) (75) (410) (75) 9
-------------------------------------------------------------------------
Net Earnings (Loss)
Before Income Tax - (220) - 1 75 892 75 673
Income tax
expense - 59 - (4) - 17 - 72
-------------------------------------------------------------------------
Net Earnings (Loss)
From Discontinued
Operations $ - $(279) $ - $ 5 $ 75 $ 875 $ 75 $ 601
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     (x) Revenues, net of royalties in Ecuador for 2006 include realized
losses of $1 million related to derivative financial instruments.
     Contingencies
     EnCana agreed to indemnify the purchaser of its Ecuador interests against
losses that may arise in certain circumstances which are defined in the
share sale agreements. The obligation to indemnify will arise should
losses exceed amounts specified in the sale agreements and is limited to
maximum amounts which are set forth in the share sale agreements.
     During the second quarter of 2006, the Government of Ecuador seized the
Block 15 assets, in relation to which EnCana previously held a 40 percent
economic interest, from the operator which is an event requiring
indemnification under the terms of EnCana's sale agreement with the
purchaser. The purchaser requested payment and EnCana paid the maximum
amount in the third quarter of 2006, calculated in accordance with the
terms of the agreements, of approximately $265 million. EnCana does not
expect that any further significant indemnification payments relating to
any other business matters addressed in the share sale agreements will be
required to be made to the purchaser.
     8.  DIVESTITURES
     Total year-to-date proceeds received on sale of assets and investments
were $481 million (2006 - $689 million) as described below:
     Canada and United States
     In 2007, the Company completed the divestiture of mature conventional oil
and natural gas assets for proceeds of $64 million (2006 - $78 million).
     Other
     In August 2007, the Company closed the sale of Australia assets for
proceeds of $31 million resulting in a gain on sale of $30 million. After
recording income tax of $5 million, EnCana recorded an after-tax gain of
$25 million.
     In May 2007, the Company completed the sale of its assets in the
Mackenzie Delta and Beaufort Sea for proceeds of $159 million.
     In January 2007, the Company completed the sale of its interests in Chad,
properties that were in the pre-production stage, for proceeds of $208
million which resulted in a gain on sale of $59 million.
     In August 2006, the Company completed the sale of its 50 percent interest
in the Chinook heavy oil discovery offshore Brazil for approximately
$367 million which resulted in a gain on sale of $304 million. After
recording income tax of $49 million, EnCana recorded an after-tax gain of
$255 million.
     Market Optimization
     In February 2006, the Company sold its investment in Entrega Gas Pipeline
LLC for approximately $244 million which resulted in a gain on sale of
$17 million.
     Corporate


     In February 2007, the Company sold The Bow office project assets for
proceeds of approximately $57 million, representing its investment at the
date of sale. Refer to Note 6 for further discussion of The Bow office
project assets.
     9.  INTEREST, NET
                                     Three Months Ended   Twelve Months Ended
December 31, December 31,
-----------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Interest Expense -
Long-Term Debt $ 129 $ 97 $ 460 $ 366
Interest Expense - Other(x) 66 57 244 76
Interest Income(x) (64) (12) (276) (46)
-------------------------------------------------------------------------
$ 131 $ 142 $ 428 $ 396
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x) In 2007, Interest Expense - Other and Interest Income are primarily
due to the Partnership Contribution Payable and Receivable, respectively.
See Note 12.
     10. FOREIGN EXCHANGE (GAIN) LOSS, NET
                                     Three Months Ended   Twelve Months Ended
December 31, December 31,
-----------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Unrealized Foreign Exchange
(Gain) Loss on:
Translation of U.S. dollar
debt issued from Canada $ (75) $ 155 $(683) $ -
Translation of U.S. dollar
partnership contribution
receivable issued from
Canada 22 - 617 -
Other Foreign Exchange
(Gain) Loss (180) 17 (98) 14
-------------------------------------------------------------------------
$(233) $ 172 $(164) $ 14
-------------------------------------------------------------------------
-------------------------------------------------------------------------

11. INCOME TAXES
     The provision for income taxes is as follows:
                                     Three Months Ended   Twelve Months Ended
December 31, December 31,
-----------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Current
Canada $ 415 $ 70 $ 900 $ 764
United States 163 41 647 128
Other Countries 2 2 7 50
-------------------------------------------------------------------------
Total Current Tax 580 113 1,554 942
-------------------------------------------------------------------------
Future (344) 260 (316) 1,407
Future Tax Rate Reductions (264) - (301) (457)
-------------------------------------------------------------------------
$ (28) $ 373 $ 937 $1,892
-------------------------------------------------------------------------
-------------------------------------------------------------------------

The following table reconciles income taxes calculated at the Canadian
statutory rate with the actual income taxes:
                                     Three Months Ended   Twelve Months Ended
December 31, December 31,
-----------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Net Earnings Before Income Tax $ 979 $1,016 $4,821 $6,943
Canadian Statutory Rate 32.3% 34.7% 32.3% 34.7%
-------------------------------------------------------------------------
Expected Income Tax 316 352 1,557 2,407
     Effect on Taxes Resulting from:
Non-deductible Canadian
Crown payments - 22 - 97
Canadian resource allowance - 2 - (16)
Statutory and other rate
differences 40 (18) 76 (98)
Effect of tax rate changes (264) - (301) (457)
Effect of legislative changes 52 - (179) -
Non-taxable downstream
partnership income (30) - (70) -
Non-taxable capital (gains)
losses (80) 29 (124) (1)
Other (62) (14) (22) (40)
-------------------------------------------------------------------------
$ (28) $ 373 $ 937 $1,892
-------------------------------------------------------------------------
Effective Tax Rate (2.9%) 36.7% 19.4% 27.3%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     12. PARTNERSHIP CONTRIBUTION RECEIVABLE/PAYABLE
     Partnership Contribution Receivable
     On January 2, 2007, upon the creation of the Integrated Oil joint
venture, ConocoPhillips entered into a subscription agreement for a 50
percent interest in the upstream entity in exchange for a promissory note
of $7.5 billion. The note bears interest at a rate of 5.3 percent per
annum. Equal payments of principal and interest are payable quarterly,
with final payment due January 2, 2017. The current and long-term
partnership contribution receivable shown in the Consolidated Balance
Sheet represents EnCana's 50 percent share of this promissory note, net
of payments to date.
     Partnership Contribution Payable
     On January 2, 2007, upon the creation of the Integrated Oil joint
venture, EnCana issued a promissory note to the downstream entity in the
amount of $7.5 billion in exchange for a 50 percent interest. The note
bears interest at a rate of 6.0 percent per annum. Equal payments of
principal and interest are payable quarterly, with final payment due
January 2, 2017. The current and long-term partnership contribution
payable amounts shown in the Consolidated Balance Sheet represents
EnCana's 50 percent share of this promissory note, net of payments to
date.
     13. INVENTORIES
                                                             As at      As at
December December
31, 2007 31, 2006
-------------------------------------------------------------------------
Product
Canada $ - $ 1
United States 2 -
Integrated Oil 646 49
Market Optimization 180 126
-------------------------------------------------------------------------
$ 828 $ 176
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     14. LONG-TERM DEBT
                                                             As at      As at
December December
31, 2007 31, 2006
-------------------------------------------------------------------------
Canadian Dollar Denominated Debt
Revolving credit and term loan borrowings $ 1,506 $ 1,456
Unsecured notes 1,138 793
-------------------------------------------------------------------------
2,644 2,249
-------------------------------------------------------------------------
U.S. Dollar Denominated Debt
Revolving credit and term loan borrowings 495 104
Unsecured notes 6,421 4,421
-------------------------------------------------------------------------
6,916 4,525
-------------------------------------------------------------------------
     Increase in Value of Debt Acquired(x)                      66         60
Debt Discounts and Financing Costs (83) -
Current Portion of Long-Term Debt (703) (257)
-------------------------------------------------------------------------
$ 8,840 $ 6,577
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x) 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.
     On March 12, 2007, EnCana completed a public offering in Canada of senior
unsecured medium term notes in the aggregate principal amount of C$500
million. The notes have a coupon rate of 4.3 percent and mature on
March 12, 2012.
     On August 13, 2007, EnCana completed a public offering in the United
States of senior unsecured notes in the aggregate principal amount of US
$500 million. The notes have a coupon rate of 6.625 percent and mature on
August 15, 2037.
     On December 4, 2007, EnCana completed a public offering in the United
States of senior unsecured notes in two series in the aggregate principal
amount of US$1,500 million. The first series of US$700 million have a
coupon rate of 5.9 percent and mature on December 1, 2017. The second
series of US$800 million have a coupon rate of 6.5 percent and mature on
February 1, 2038.
     15. 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 assets and refining facilities:
                                                             As at      As at
December December
31, 2007 31, 2006
-------------------------------------------------------------------------
     Asset Retirement Obligation, Beginning of Year       $  1,051   $    816
Liabilities Incurred 89 68
Liabilities Settled (100) (51)
Change in Estimated Future Cash Flows 184 172
Accretion Expense 64 50
Other 170 (4)
-------------------------------------------------------------------------
Asset Retirement Obligation, End of Year $ 1,458 $ 1,051
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     16. SHARE CAPITAL
                                      December 31, 2007     December 31, 2006
----------------------------------------
(millions) Number Amount Number Amount
-------------------------------------------------------------------------
     Common Shares Outstanding,
Beginning of Year 777.9 $ 4,587 854.9 $ 5,131
Common Shares Issued under
Option Plans 8.3 176 8.6 179
Stock-Based Compensation - 17 - 11
Common Shares Purchased (36.0) (301) (85.6) (734)
-------------------------------------------------------------------------
Common Shares Outstanding,
End of Year 750.2 $ 4,479 777.9 $ 4,587
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     Normal Course Issuer Bid
     To December 31, 2007, the Company purchased 38.9 million Common Shares
for total consideration of approximately $2,025 million. Of the amount
paid, $325 million was charged to Share capital and $1,700 million was
charged to Retained earnings. Included in the Common Shares Purchased in
2007 are 2.9 million Common Shares distributed, valued at $24 million,
from the EnCana Employee Benefit Plan Trust that vested under EnCana's
Performance Share Unit Plan (See Note 17). For these Common Shares
distributed, there was an $82 million adjustment to Retained earnings
with a reduction to Paid in surplus of $106 million.
     EnCana has received regulatory approval each year under Canadian
securities laws to purchase Common Shares under six consecutive Normal
Course Issuer Bids ("Bids"). EnCana is entitled to purchase, for
cancellation, up to approximately 75.1 million Common Shares under the
renewed Bid which commenced on November 13, 2007 and terminates on
November 12, 2008.
     Stock Options

     EnCana 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 date
granted. Options granted under predecessor and/or related company
replacement plans expire up to 10 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 ("TSARs")
attached to them at December 31, 2007. Information related to TSARs is
included in Note 17.
                                                                     Weighted
Stock Average
Options Exercise
(millions) Price (C$)
-------------------------------------------------------------------------
Outstanding, Beginning of Year 11.8 23.17
Exercised (8.3) 23.73
Forfeited (0.1) 22.53
-------------------------------------------------------------------------
Outstanding, End of Year 3.4 21.82
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Exercisable, End of Year 3.4 21.82
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Outstanding Options Exercisable Options
-------------------------------------------------------
Weighted Weighted
Number of Average Average Number of Weighted
Options Remaining Exercise Options Out- Average
Range of Outstanding Contractual Price standing Exercise
Exercise Price(C$) (millions) Life (years) (C$) (millions) Price(C$)
-------------------------------------------------------------------------
11.00 to 21.99 0.6 1.8 11.58 0.6 11.58
22.00 to 23.99 2.6 0.3 23.86 2.6 23.86
24.00 to 25.99 0.2 0.7 25.04 0.2 25.04
-------------------------------------------------------------------------
3.4 0.6 21.82 3.4 21.82
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     At December 31, 2007, the balance in Paid in surplus relates to stock-
based compensation programs.
     17. COMPENSATION PLANS
     The tables below outline certain information related to EnCana's
compensation plans at December 31, 2007. Additional information is
contained in Note 15 of the Company's annual audited Consolidated
Financial Statements for the year ended December 31, 2006.
     A)  Pensions
     The following table summarizes the net benefit plan expense:
                                     Three Months Ended   Twelve Months Ended
December 31, December 31,
-----------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Current Service Cost $ 5 $ 6 $ 16 $ 16
Interest Cost 5 4 19 17
Expected Return on Plan Assets (5) (4) (19) (16)
Expected Actuarial Loss on
Accrued Benefit Obligation 1 2 4 6
Expected Amortization of Past
Service Costs 1 1 2 2
Amortization of Transitional
Obligation (1) - (2) (1)
Expense for Defined
Contribution Plan 9 8 34 28
-------------------------------------------------------------------------
Net Benefit Plan Expense $ 15 $ 17 $ 54 $ 52
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     For the year ended December 31, 2007, contributions of $8 million have
been made to the defined benefit pension plans (2006 - $9 million).
     B) Tandem Share Appreciation Rights ("TSARs")
     The following table summarizes the information about TSARs at
December 31, 2007:


                                                                     Weighted
Average
Outstanding Exercise
TSARs Price
-------------------------------------------------------------------------
Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 17,276,191 44.99
Granted 4,814,338 57.70
Exercised - SARs (2,020,357) 41.20
Exercised - Options (12,235) 35.04
Forfeited (1,203,796) 50.02
-------------------------------------------------------------------------
Outstanding, End of Year 18,854,141 50.49
-------------------------------------------------------------------------
Exercisable, End of Year 5,267,550 43.18
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the year ended December 31, 2007, EnCana recorded compensation costs
of $225 million related to the outstanding TSARs (2006 - $52 million).
     C) Performance Tandem Share Appreciation Rights ("Performance TSARs")
     In 2007, under the terms of the existing Employee Stock Option Plan,
EnCana granted Performance TSARs under which the employee has the right
to receive a cash payment equal to the excess of the market price of
EnCana Common Shares at the time of exercise over the grant price.
Performance TSARs vest and expire under the same terms and service
conditions as the underlying option, and vesting is subject to EnCana
attaining prescribed performance relative to pre-determined key measures.
Performance TSARs that do not vest when eligible are forfeited.
     The following table summarizes the information about Performance TSARs at
December 31, 2007:
                                                                     Weighted
Average
Outstanding Exercise
TSARs Price
-------------------------------------------------------------------------
Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year - -
Granted 7,275,575 56.09
Forfeited (344,650) 56.09
-------------------------------------------------------------------------
Outstanding, End of Year 6,930,925 56.09
-------------------------------------------------------------------------
Exercisable, End of Year - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     For the year ended December 31, 2007, EnCana recorded compensation costs
of $21 million related to the outstanding Performance TSARs (2006 - nil).
     D) Deferred Share Units ("DSUs")
     The following table summarizes the information about DSUs at December 31,
2007:


                                                                      Average
Outstanding Share
DSUs Price
-------------------------------------------------------------------------
     Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 866,577 29.56
Granted, Directors 79,168 57.02
Exercised (365,885) 29.56
Units, in Lieu of Dividends 9,314 62.80
-------------------------------------------------------------------------
Outstanding, End of Year 589,174 33.78
-------------------------------------------------------------------------
Exercisable, End of Year 589,174 33.78
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     For the year ended December 31, 2007, EnCana recorded compensation costs
of $14 million related to the outstanding DSUs (2006 - $5 million).
     E) Performance Share Units ("PSUs")
     The following table summarizes the information about PSUs at December 31,
2007:


                                                                      Average
Outstanding Share
PSUs Price
-------------------------------------------------------------------------
     Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 4,766,329 31.24
Granted 23,097 62.84
Distributed (2,937,491) 26.98
Forfeited (166,899) 34.38
-------------------------------------------------------------------------
Outstanding, End of Year 1,685,036 38.79
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     For the year ended December 31, 2007, EnCana recorded compensation costs
of $43 million related to the outstanding PSUs (2006 - $27 million).
     At December 31, 2007, EnCana has approximately 2.6 million Common Shares
held in trust for issuance upon vesting of the PSUs (2006 - 5.5 million).
     F) Share Appreciation Rights ("SARs")


     EnCana has not granted any SARs after 2002, and as at December 31, 2007
there are none outstanding. For the year ended December 31, 2007, EnCana
has not recorded any compensation costs related to the outstanding SARs
(2006 - reduction of compensation costs of $1 million).
     18. PER SHARE AMOUNTS
     The following table summarizes the Common Shares used in calculating Net
Earnings per Common Share:
                                                                Twelve Months
Three Months Ended Ended
-------------------------------------------------------
March 31, June 30, Sept.30, December 31, December 31,
-------------------------------------------------------
(millions) 2007 2007 2007 2007 2006 2007 2006
-------------------------------------------------------------------------
Weighted Average
Common Shares
Outstanding -
Basic 768.4 758.5 750.4 749.8 792.5 756.8 819.9
Effect of Dilutive
Securities 11.2 6.7 5.5 5.3 13.9 7.8 16.6
-------------------------------------------------------------------------
Weighted Average
Common Shares
Outstanding -
Diluted 779.6 765.2 755.9 755.1 806.4 764.6 836.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     19. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
     As a means of managing commodity price volatility, EnCana entered into
various financial instrument agreements and physical contracts. The
following information presents all positions for financial instruments.
     Realized and Unrealized Gain (Loss) on Risk Management Activities


     The following tables summarize the gains and losses on risk management
activities:
                                                Realized Gain (Loss)
-----------------------------------------
Three Months Ended Twelve Months Ended
December 31, December 31,
-----------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of Royalties $ 408 $ 240 $1,601 $ 393
Operating Expenses and Other (1) 1 3 5
-------------------------------------------------------------------------
Gain (Loss) on Risk Management -
Continuing Operations 407 241 1,604 398
Gain (Loss) on Risk Management -
Discontinued Operations - 8 - 12
-------------------------------------------------------------------------
$ 407 $ 249 $1,604 $ 410
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Unrealized Gain (Loss)
-----------------------------------------
Three Months Ended Twelve Months Ended
December 31, December 31,
-----------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of Royalties $ (566) $ 129 $(1,239) $2,050
Operating Expenses and Other (3) 12 4 10
-------------------------------------------------------------------------
Gain (Loss) on Risk Management -
Continuing Operations (569) 141 (1,235) 2,060
Gain (Loss) on Risk Management -
Discontinued Operations - (7) - 20
-------------------------------------------------------------------------
$ (569) $ 134 $(1,235) $2,080
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     Fair Value of Outstanding Risk Management Positions
     The following table presents a reconciliation of the change in the
unrealized amounts from January 1, 2007 to December 31, 2007:

Fair Total
Market Unrealized
Value Gain (Loss)
-------------------------------------------------------------------------
Fair Value of Contracts, Beginning of Year $ 1,416
Change in Fair Value of Contracts in Place at
Beginning of Year and Contracts Entered into
During 2007 353 $ 353
Fair Value of Contracts in Place at Transition that
Expired During 2007 - 16
Foreign Exchange Gains on Canadian Dollar Contracts 2 -
Fair Value of Contracts Realized During 2007 (1,604) (1,604)
-------------------------------------------------------------------------
Fair Value of Contracts, End of Year $ 167 $(1,235)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     At December 31, 2007, the risk management amounts are recorded in the
Consolidated Balance Sheet as follows:
                                                                        As at
December 31, 2007
-------------------------------------------------------------------------
Risk Management
Current asset $ 385
Long-term asset 18
Current liability 207
Long-term liability 29
-------------------------------------------------------------------------
Net Risk Management Asset $ 167
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     A summary of all unrealized estimated fair value financial positions is
as follows:
As at
December 31, 2007
-------------------------------------------------------------------------
Commodity Price Risk
Natural gas $ 346
Crude oil (199)
Power 19
Credit Derivatives (1)
Interest Rate Risk 2
-------------------------------------------------------------------------
Total Fair Value Positions $ 167
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     Information with respect to credit derivatives and interest rate risk
contracts in place at December 31, 2006 is disclosed in Note 16 to the
Company's annual audited Consolidated Financial Statements.
     Natural Gas
     At December 31, 2007, the Company's gas risk management activities from
financial contracts had an unrealized gain and a fair market value
position of $346 million. The contracts were as follows:
                                   Notional                              Fair
Volumes Market
(MMcf/d) Term Average Price Value
-------------------------------------------------------------------------
Sales Contracts
Fixed Price Contracts
NYMEX Fixed Price 1,583 2008 8.21 US$/Mcf $303
Basis Contracts
Canada 191 2008 (0.78) US$/Mcf 1
United States 1,049 2008 (1.02) US$/Mcf 65
Canada and United States(x) 2009-2011 US$/Mcf (23)
-------------------------------------------------------------------------
Total Fair Value Positions $346
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x) EnCana has entered into swaps to protect against widening natural gas
price differentials between production areas, including Canada, the U.S.
Rockies and Texas, and various sales points. These basis swaps are
priced using both fixed prices and basis prices determined as a
percentage of NYMEX.
     Crude Oil
     At December 31, 2007, the Company's oil risk management activities from
financial contracts had an unrealized loss and a fair market value of
$(199) million. The contracts were as follows:
                                   Notional                              Fair
Volumes Market
(bbls/d) Term Average Price Value
-------------------------------------------------------------------------
Sales Contracts
Fixed Price Contracts
WTI NYMEX Fixed Price 23,000 2008 70.13 US$/bbl $(188)
-------------------------------------------------------------------------
(188)
Other Financial Positions(x) (11)
-------------------------------------------------------------------------
Total Fair Value Positions $(199)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x) Other financial positions are part of the ongoing operations of the
Company's proprietary production management.
     Power
     The Company has in place two Canadian dollar denominated derivative
contracts, commencing January 1, 2007 for a period of 11 years, to manage
its electricity consumption costs. At December 31, 2007, these contracts
had an unrealized gain and a fair market value position of $19 million.
     20. 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


     During the period between 2003 and 2005, EnCana and its indirect wholly
owned U.S. marketing subsidiary, WD Energy Services Inc. ("WD"), along
with other energy companies, were named as defendants in several
lawsuits, some of which were class action lawsuits, relating to sales of
natural gas from 1999 to 2002. The lawsuits allege that the defendants
engaged in a conspiracy with unnamed competitors in the natural gas
markets in California in violation of U.S. and California anti-trust and
unfair competition laws.
     Without admitting any liability in the lawsuits, WD agreed to settle all
of the class action lawsuits in both state and federal court for payment
of $20.5 million and $2.4 million, respectively. Also, as previously
disclosed, without admitting any liability whatsoever, WD concluded
settlements with the U.S. Commodity Futures Trading Commission ("CFTC")
for $20 million and of a previously disclosed consolidated class action
lawsuit in the United States District Court in New York for $8.2 million.


     The remaining lawsuits were commenced by individual plaintiffs, one of
which is E. & J. Gallo Winery ("Gallo"). The Gallo lawsuit claims damages
in excess of $30 million. The other remaining lawsuits do not specify the
precise amount of damages claimed. California law allows for the
possibility that the amount of damages assessed could be tripled.
     The Company and WD intend to vigorously defend against the 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.
     21. SUBSEQUENT EVENTS
     On January 18, 2008, EnCana completed a public offering in Canada of
senior unsecured medium term notes in the aggregate principal amount of
C$750 million. The notes have a coupon rate of 5.80 percent and mature on
January 18, 2018. The net proceeds of the offering were used to repay a
portion of EnCana's existing bank and commercial paper indebtedness.


     22. RECLASSIFICATION
     Certain information provided for prior periods has been reclassified to
conform to the presentation adopted in 2007.
     >>

/For further information: on EnCana Corporation is available on the company's
website, www.encana.com, or by contacting:

For further information:
EnCana Corporate Communications
Investor contact:
Paul Gagne
Vice-President, Investor Relations
(403) 645-4737

Ryder McRitchie
Manager, Investor Relations
(403) 645-2007

Susan Grey
Manager, Investor Relations
(403) 645-4751

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

ECA stock price

TSX $15.12 Can 0.200

NYSE $11.85 USD 0.160

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