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 "held-for-trading" and are
    measured at fair value. Accounts receivable and accrued revenues and the
    partnership contribution receivable are designated as "loans 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(*)     $   -  $ 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
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (*) 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(*)          66         57        244         76
    Interest Income(*)                  (64)       (12)      (276)       (46)
    -------------------------------------------------------------------------
                                      $ 131      $ 142      $ 428      $ 396
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (*) 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(*)                      66         60
    Debt Discounts and Financing Costs                        (83)         -
    Current Portion of Long-Term Debt                        (703)      (257)
    -------------------------------------------------------------------------
                                                         $  8,840   $  6,577
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (*) 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$/Mcf       65
      Canada and United States(*)         2009-2011         US$/Mcf      (23)
    -------------------------------------------------------------------------
    Total Fair Value Positions                                          $346
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (*) 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(*)                                         (11)
    -------------------------------------------------------------------------
    Total Fair Value Positions                                         $(199)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (*) 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:

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

Organization Profile

Encana Corporation

More on this organization


Custom Packages

Browse our custom packages or build your own to meet your unique communications needs.

Start today.

CNW Membership

Fill out a CNW membership form or contact us at 1 (877) 269-7890

Learn about CNW services

Request more information about CNW products and services or call us at 1 (877) 269-7890