EnCana generates 2008 cash flow of US$9.4 billion, or $12.48 per share, up 13 percent

Operating earnings per share up 9 percent; Proved reserves additions 150% of production

CALGARY, Feb. 12 /CNW/ - EnCana Corporation (TSX & NYSE: ECA) achieved
solid increases in 2008 cash flow and operating earnings as a result of strong
growth in natural gas and oil production and higher prices. Financial results
were enhanced in the fourth quarter by EnCana's favourable natural gas price
hedges. Again in 2008, EnCana achieved strong year-over-year proved reserves
additions.
"Despite the unprecedented volatility in oil and natural gas prices and a
challenging operating environment in 2008, EnCana delivered strong operational
and financial performance. We met or exceeded all of our targets, including
those for cash flow, production and capital investment. Overall production
grew 6 percent, driven by our key resource plays which increased 13 percent
year-over-year. We added reserves of 2.5 trillion cubic feet of gas
equivalent, replacing 150 percent of production at a very competitive finding
and development cost of US$2.50 per thousand cubic feet of gas equivalent,"
said Randy Eresman, EnCana's President & Chief Executive Officer.
"EnCana is pursuing a conservative and prudent capital program in 2009
and we have built flexibility into our plans to adjust investment depending on
how the year unfolds. With widespread economic uncertainty, we remain intently
focused on our core business objectives: maintaining financial strength,
generating significant free cash flow, further optimizing our capital
investments and continuing to pay a stable dividend to shareholders -
currently $1.60 per share annualized, which at the current share price results
in a yield of about 3.7 percent.
"Natural gas and oil prices are expected to remain low at least through
the first quarter of 2009. While we have seen some indication of a softening
in service and supply costs, reductions are likely to be more pronounced in
the latter half of 2009. We are affirming our 2009 corporate guidance. Our
cash flow forecast for the year is underpinned by strong hedges - about two-
thirds of expected natural gas production hedged through October 2009 at an
average price of $9.13 per thousand cubic feet, well above the current spot
price. In addition, we are continually seeking new ways to strengthen our
financial position, including cost-reduction initiatives, project reviews
throughout the year and exploring and implementing operational efficiencies
across our company.
"EnCana's low-risk, low-cost resource play business model provides
financial resilience and positions the company very well for dealing with the
economic downturn. We can apply an even higher level of scrutiny and fine tune
investments in order to target optimal project returns and long-term value
creation," Eresman said.
     IMPORTANT NOTE: Effective January 2, 2007, EnCana established an
integrated oil business with ConocoPhillips, which resulted in EnCana
contributing its interests in Foster Creek and Christina Lake into an upstream
partnership owned 50-50 by the two companies. Production and wells drilled in
2006 have been adjusted on a pro-forma basis to reflect the integrated oil
transaction. Unless otherwise noted in this news release, EnCana's proved
reserves and production for 2007 and 2008 are reported on a post integrated
oil basis. Per share amounts for cash flow and earnings are on a diluted
basis. EnCana reports in U.S. dollars unless otherwise noted and follows U.S.
protocols, which report production, sales and reserves on an after-royalties
basis. The company's financial statements are prepared in accordance with
Canadian generally accepted accounting principles (GAAP).
     <<
2008 Highlights
---------------
     Financial - US$
     -   Cash flow increased 13 percent per share to $12.48, or $9.4 billion
- Operating earnings were up 9 percent per share to $5.86, or
$4.4 billion
- Net earnings were up 53 percent per share to $7.91, or $5.9 billion,
primarily due to an after-tax unrealized mark-to-market hedging gain
of $1.8 billion in 2008 compared to an after-tax loss of $811 million
in 2007.
- Capital investment, excluding acquisitions and divestitures, was up
17 percent to $7.1 billion
- Generated $2.3 billion of free cash flow (as defined in Note 1 on
page 10), down $112 million from 2007
- Operating cash flow nearly doubled to $421 million from the company's
Foster Creek and Christina Lake upstream projects, whereas lower
refining margins and higher purchased product costs resulted in a
$241 million loss in operating cash flow for the downstream business.
As a result, EnCana's integrated oil business venture with
ConocoPhillips generated $180 million of operating cash flow
- Purchased approximately 4.8 million EnCana shares at an average price
of $67.13 under the Normal Course Issuer Bid, for a total cost of
approximately $326 million
- Doubled quarterly dividend to 40 cents per share in March 2008, or
$1.60 per share on an annualized basis
- At year end, debt to capitalization was 28 percent and debt to
adjusted EBITDA was 0.7 times
     Operating - Upstream
     -   Natural gas production increased 8 percent to 3.8 billion cubic feet
per day (Bcf/d), up 9 percent per share
- Increased production from natural gas key resource plays by
14 percent
- Oil and natural gas liquids (NGLs) production was relatively flat at
about 134,000 barrels per day (bbls/d)
- Integrated oil production grew 13 percent to 30,183 bbls/d at Foster
Creek and Christina Lake
- Operating and administrative costs of $1.25 per thousand cubic feet
equivalent (Mcfe), compared to $1.17 per Mcfe in 2007
     Operating - Downstream
     -   Refined products averaged 448,000 bbls/d (224,000 bbls/d net to
EnCana)
- Refinery crude utilization of 93 percent or 423,000 bbls/d crude
throughput (211,500 bbls/d net to EnCana)
     Reserves

     -   Total proved reserves increased 5 percent to 19.7 trillion cubic feet
of gas equivalent (Tcfe)
- Added 2.5 Tcfe of proved reserves, compared to production of
1.7 Tcfe, for a production replacement of 150 percent
- Proved natural gas reserves increased 3 percent to 13.7 trillion
cubic feet (Tcf)
- Proved oil and NGLs reserves increased 8 percent to 1.0 billion
barrels
- Proved reserves additions, excluding acquisitions and divestitures,
included approximately 1.9 Tcf of natural gas reserves and
130 million bbls of oil and NGLs reserves
- Finding and development (F&D) costs were $2.50 per Mcfe
- Three-year (2006-2008) F&D costs averaged $2.02 per Mcfe
- F&D costs for natural gas and associated liquids were approximately
$2.90 per Mcfe
- Proved reserves life index of approximately 12 years
- Reserves replacement costs are outlined on page 7
     Strategic developments
     -   Acquired additional land and mineral interests in the Haynesville
Shale play in Louisiana and Texas for approximately $1.0 billion
- Began construction of a Coker and Refinery Expansion (CORE) project
at the Wood River refinery in Roxana, Illinois that is expected to
expand heavy oil processing capacity and increase production of clean
transportation fuels for the U.S. Midwest market
- Signed a contract for the design and construction of the Production
Field Centre for the Deep Panuke natural gas project offshore Nova
Scotia
- Divested mature conventional oil and natural gas assets in North
America for approximately $698 million as well as interests in Brazil
for approximately $164 million, before closing adjustments
>>
     Fourth quarter natural gas production grows 4 percent
     EnCana's fourth quarter natural gas production increased 4 percent to 3.9
Bcf/d, compared to the same quarter in 2007. Oil and natural gas liquids
production in the quarter was flat at 136,000 bbls/d. Total production
increased 3 percent to 4.7 Bcfe/d. Fourth quarter cash flow per share
decreased 32 percent to $1.73, or $1.3 billion, and operating earnings per
share decreased 46 percent to $0.60, or $449 million, largely due to a 30
percent drop in heavy oil prices and a 31 percent decrease in the Chicago 3-2-
1 crack spread.
     <<
-------------------------------------------------------------------------
Financial Summary - Total Consolidated
-------------------------------------------------------------------------
(for the period
ended December 31)
($ millions, except Q4 Q4 % %
per share amounts) 2008 2007 change 2008 2007 change
-------------------------------------------------------------------------
Cash flow(1) 1,299 1,934 -33 9,386 8,453 +11
Per share diluted 1.73 2.56 -32 12.48 11.06 +13
-------------------------------------------------------------------------
Operating earnings(1) 449 849 -47 4,405 4,100 +7
Per share diluted 0.60 1.12 -46 5.86 5.36 +9
-------------------------------------------------------------------------
Net earnings 1,077 1,082 - 5,944 3,959 +50
Per share diluted 1.43 1.43 - 7.91 5.18 +53
-------------------------------------------------------------------------
Capital investment 1,925 1,805 +7 7,080 6,035 +17
-------------------------------------------------------------------------
-------------------------------------------------------------------------
             Earnings Reconciliation Summary - Total Consolidated
-------------------------------------------------------------------------
     Net earnings          1,077    1,082        -    5,944    3,959      +50
Add back (losses)
& deduct gains:
     Unrealized
mark-to-market
hedging gain (loss),
after-tax 747 (366) 1,818 (811)
     Non-operating
foreign exchange
gain (loss),
after-tax (119) 267 (378) 217
     Gain on
discontinuance,
after-tax - 68 99 152
     Future tax recovery
due to tax rate
reductions - 264 - 301
-------------------------------------------------------------------------
     Operating earnings(1)   449      849      -47    4,405    4,100       +7
Per share diluted 0.60 1.12 -46 5.86 5.36 +9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     (1) Cash flow and operating earnings are non-GAAP measures as defined in
Note 1 on Page 10.

-------------------------------------------------------------------------
2008 Cash Flow Information
(for the period ended December 31, $ millions) Q4 2008
-------------------------------------------------------------------------
Cash from operating activities 2,043 8,855
Deduct (Add back):
Net change in other assets and liabilities 21 (262)
Net change in non-cash working capital
from continuing operations 723 (269)
-------------------------------------------------------------------------
Cash flow(1) 1,299 9,386
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     (1) Cash flow is a non-GAAP measure as defined in Note 1 on Page 10.
>>

Year-over-year increase in net earnings related to unrealized
mark-to-market accounting gains
     EnCana's net earnings in 2008 increased more than 50 percent to $5.9
billion. Net earnings in 2008 included a $1.8 billion after-tax unrealized
gain, whereas net earnings in 2007 included an $811 million after-tax
unrealized loss, both due to mark-to-market accounting for hedging contracts.
The large unrealized gain in 2008 resulted from a decrease in commodity prices
during the second half of the year. The gain essentially reversed unrealized
mark-to-market losses recognized earlier in the year when natural gas prices
were rising. It is because of these dramatic mark-to-market accounting swings
in net earnings that EnCana focuses on operating earnings, which excludes the
unrealized mark-to-market accounting gains and losses, as a better measure of
earnings performance. Operating earnings in 2008 were up 7 percent compared to
2007, reflecting stronger prices in 2008 and EnCana's 6 percent increase in
daily production.
     <<
-------------------------------------------------------------------------
Production & Drilling Summary - Total Consolidated
-------------------------------------------------------------------------
(for the period ended
December 31) Q4 Q4 % %
(After royalties) 2008 2007 change 2008 2007 change
-------------------------------------------------------------------------
Natural Gas
production (MMcf/d) 3,858 3,722 +4 3,838 3,566 +8
-------------------------------------------------------------------------
Natural gas
production per
1,000 shares (Mcf) 473 457 +4 1,873 1,720 +9
-------------------------------------------------------------------------
Oil and NGLs
production (Mbbls/d) 136 136 - 134 134 -
-------------------------------------------------------------------------
Oil and NGLs
production per
1,000 shares (Mcfe) 100 100 - 391 388 +1
-------------------------------------------------------------------------
Total production
(MMcfe/d) 4,673 4,539 +3 4,639 4,371 +6
-------------------------------------------------------------------------
Total production
per 1,000 shares
(Mcfe) 573 557 +3 2,264 2,108 +7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total Net wells
drilled 1,047 1,313 -20 3,329 4,484 -26
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Natural gas production growth benefits from a 14 percent increase from
key resource plays
>>
     Natural gas production averaged about 3.8 Bcf/d in 2008, an increase of 8
percent from 2007. Natural gas key resource play production increased 14
percent in 2008 compared with 2007. EnCana's production growth was led by a 21
percent increase in gas production in the U.S. mainly from East Texas, which
continues to benefit from drilling and operational successes and the
incremental volumes from Deep Bossier, where the company doubled its interest
in late 2007. In Canada, production remained flat as increases from drilling
successes in Bighorn, coalbed methane (CBM) and Cutbank Ridge offset natural
declines. Total production growth more than offset a production decrease, on
an annualized basis, of about 40 million cubic feet per day (MMcf/d) due to
freeze-offs, pipeline outages, shut-ins and hurricanes. Production is expected
to remain essentially flat in 2009.
     <<
Integrated Oil Division benefits from higher 2008 crude oil prices offset
by lower refining margins
>>
     EnCana's Integrated Oil Division, which includes the company's integrated
oil business venture with ConocoPhillips and production from Athabasca and
Senlac, generated $375 million in operating cash flow, down 75 percent, from
2007. EnCana saw strong financial performance from its Foster Creek and
Christina Lake operations, which benefited from higher heavy oil prices, up
about 60 percent, and a 13 percent increase in production to 30,183 bbls/d.
Operating cash flow for Foster Creek and Christina Lake nearly doubled to $421
million in 2008 compared to $213 million in 2007. The downstream operations
reported a loss of $241 million in operating cash flow, a $1.3 billion
decrease compared to 2007, a year with record crack spreads. Downstream
operating cash flow was reduced as a result of lower refining margins and
higher purchased product costs during the second half of 2008. The Wood River
and Borger refineries are located in markets influenced by U.S. Mid-Continent
and Chicago 3-2-1 crack spreads. In 2008 the Chicago 3-2-1 crack spread
decreased 37 percent to $11.22 per bbl compared to $17.67 per bbl in 2007. The
weaker refining margins were offset, somewhat, by the higher upstream pricing,
which demonstrates the benefit of the company's integration strategy.
At Foster Creek steaming of Phase 1D and 1E has started and construction
is nearing completion. A ramp up of production is expected to begin at the end
of the first quarter in 2009. Capital costs for the expansions remain on
budget. At Christina Lake construction of the Phase 1C expansion also remains
on schedule and on budget.
     <<
Growth from key North American resource plays
     -------------------------------------------------------------------------
Daily Production
Resource Play ---------------------------------------
2008
---------------------------------------
(After royalties) Full
Year Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Natural gas (MMcf/d)
Jonah 603 573 615 630 595
Piceance 385 377 407 383 372
East Texas 334 408 339 316 273
Fort Worth 142 143 148 137 140
Greater Sierra 220 228 228 219 205
Cutbank Ridge(1) 296 311 322 280 271
Bighorn(1) 167 165 185 170 146
CBM 304 308 309 303 298
Shallow Gas 700 683 691 712 715
-------------------------------------------------------------------------
Total natural gas (MMcf/d) 3,151 3,196 3,244 3,150 3,015
-------------------------------------------------------------------------
Oil (Mbbls/d)(3)
Foster Creek 26 29 27 21 27
Christina Lake 4 6 5 4 2
Pelican Lake 22 20 22 21 24
Weyburn(2) 14 15 14 13 14
-------------------------------------------------------------------------
Total oil (Mbbls/d)(3) 66 71 67 59 67
-------------------------------------------------------------------------
Total (MMcfe/d)(1)(2) 3,548 3,621 3,648 3,506 3,417
-------------------------------------------------------------------------
% change from prior period +13.0 -0.7 +4.1 +2.6 +2.7
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Daily Production
Resource Play ----------------------------------------------
2007 2006
----------------------------------------------
(After royalties) Full Full
Year Q4 Q3 Q2 Q1 Year
-------------------------------------------------------------------------
Natural gas (MMcf/d)
Jonah 557 612 588 523 504 464
Piceance 348 351 354 349 334 326
East Texas 143 187 144 139 103 99
Fort Worth 124 138 128 124 106 101
Greater Sierra 211 221 220 219 186 213
Cutbank Ridge(1) 258 283 269 248 232 189
Bighorn(1) 126 136 136 122 109 97
CBM 259 283 256 245 251 194
Shallow Gas 726 727 713 729 735 739
-------------------------------------------------------------------------
Total natural gas (MMcf/d) 2,752 2,938 2,808 2,698 2,560 2,422
-------------------------------------------------------------------------
Oil (Mbbls/d)(3)
Foster Creek 24 25 26 25 20 18
Christina Lake 3 2 3 3 3 3
Pelican Lake 23 24 24 23 23 24
Weyburn(2) 15 14 15 15 15 15
-------------------------------------------------------------------------
Total oil (Mbbls/d)(3) 65 65 67 65 62 60
-------------------------------------------------------------------------
Total (MMcfe/d)(1)(2) 3,141 3,327 3,210 3,088 2,926 2,782
-------------------------------------------------------------------------
% change from prior period +12.9 +3.7 +4.0 +5.5 +9.2
-------------------------------------------------------------------------
(1) Key resource play production volumes in 2007 and 2006 for Cutbank
Ridge and Bighorn were restated in the first quarter of 2008 to
include new areas and zones that qualify for key resource play
inclusion.
(2) Key resource play production volumes in 2007 and 2006 were restated
in the first quarter of 2008 to include Weyburn as a key resource
play.
(3) Totals may not add due to rounding.
            Drilling activity in key North American resource plays
     -------------------------------------------------------------------------
Net Wells Drilled
---------------------------------------
2008
Resource Play ---------------------------------------
Full
Year Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Natural gas
Jonah 175 40 43 49 43
Piceance 328 70 94 81 83
East Texas 78 23 22 22 11
Fort Worth 83 21 21 20 21
Greater Sierra 106 14 29 27 36
Cutbank Ridge(1) 82 17 17 24 24
Bighorn(1) 64 5 11 18 30
CBM 698 359 78 10 251
Shallow Gas 1,195 383 233 83 496
-------------------------------------------------------------------------
Total gas wells 2,809 932 548 334 995
-------------------------------------------------------------------------
Oil
Foster Creek 20 1 6 1 12
Christina Lake - - - - -
Pelican Lake - - - - -
Weyburn(2) 21 3 4 5 9
-------------------------------------------------------------------------
Total oil wells 41 4 10 6 21
-------------------------------------------------------------------------
Total(1)(2) 2,850 936 558 340 1,016
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Net Wells Drilled
----------------------------------------------
2007 2006
Resource Play ----------------------------------------------
Full Full
Year Q4 Q3 Q2 Q1 Year
-------------------------------------------------------------------------
Natural gas
Jonah 135 23 31 42 39 163
Piceance 286 77 72 72 65 220
East Texas 35 8 9 11 7 59
Fort Worth 75 15 17 29 14 97
Greater Sierra 109 27 27 32 23 115
Cutbank Ridge(1) 93 11 23 26 33 134
Bighorn(1) 62 6 18 10 28 58
CBM 1,079 330 323 18 408 729
Shallow Gas 1,914 649 608 241 416 1,310
-------------------------------------------------------------------------
Total gas wells 3,788 1,146 1,128 481 1,033 2,885
-------------------------------------------------------------------------
Oil
Foster Creek 23 6 8 1 8 3
Christina Lake 3 - 1 2 - 1
Pelican Lake - - - - - -
Weyburn(2) 37 10 9 9 9 35
-------------------------------------------------------------------------
Total oil wells 63 16 18 12 17 39
-------------------------------------------------------------------------
Total(1)(2) 3,851 1,162 1,146 493 1,050 2,924
-------------------------------------------------------------------------
(1) Key resource play net wells drilled in 2007 and 2006 for Cutbank
Ridge and Bighorn were restated in the first quarter of 2008 to
include new areas and zones that qualify for key resource play
inclusion.
(2) Key resource play net wells drilled in 2007 and 2006 were restated in
the first quarter of 2008 to include Weyburn as a key resource play.

2008 proved reserves
     Proved reserves grow 5 percent at a finding and development cost of $2.50
per Mcfe
>>
     In 2008, total proved reserves increased 5 percent to 19.7 Tcfe at an
average F&D cost of $2.50 per Mcfe. EnCana added 2.5 Tcfe of proved reserves,
compared to production of 1.7 Tcfe, resulting in a reserve replacement of 150
percent of 2008 production. Cutbank Ridge, Bighorn and East Texas resource
plays contributed to proved reserves additions of 1.9 Tcf of natural gas.
Proved reserves of 387 Bcf were added for the Deep Panuke natural gas project,
for which development is well underway and first production is expected in
late 2010. About 130 million bbls of oil and NGLs were added, about two-thirds
at Foster Creek and Christina Lake, where there were positive reserves
revisions. Despite the low-price environment at year end, these projects had
no reserves writedowns, which reflects the quality of the underlying
reservoirs and EnCana's strong operating performance. EnCana's thermal oil
projects have about 670 million bbls of proved reserves, of which about 80
percent is undeveloped.
F&D costs for natural gas and associated liquids were approximately $2.90
per Mcfe. When the cost of acquiring non-developed land in 2008 is excluded
from the calculation, F&D costs averaged $2.45 per Mcfe. Natural gas and
associated liquids reserves additions were approximately 2.0 Tcfe with capital
investments of $5.8 billion in 2008, compared to 2007 reserves additions of
about 2.0 Tcfe with capital investments of $4.7 billion. In 2008, F&D costs
for crude oil were approximately $8.35 per bbl, up from about $3.60 per bbl in
2007. Crude oil reserves additions were approximately 123 million bbls and
capital investments were $1 billion in 2008, compared to 2007 reserves
additions of about 233 million bbls and capital investments of $840 million.
     Three-year F&D averages $2.02 per Mcfe
     For the three years 2006-2008, EnCana's F&D costs averaged $2.02 per
Mcfe. For natural gas and associated liquids, F&D costs averaged $2.65 per
Mcfe based on reserves additions of about 5.8 Tcfe and capital investments of
$15.6 billion. For the same period, F&D costs for crude oil averaged $5.30 per
bbl based on reserves additions of about 555 million bbls and capital
investments of $2.9 billion.
     Reserves replacement cost in 2008
     Reserves replacement cost for 2008 was approximately $2.60 per Mcfe,
which includes divestitures of 222 Bcfe for proceeds of $800 million. EnCana's
three-year (2006-2008) reserves replacement cost was approximately $2.55 per
Mcfe.
All of EnCana's proved reserves are evaluated by independent qualified
reserves evaluators and are presented in compliance with U.S. Securities and
Exchange Commission requirements.
     <<
-------------------------------------------------------------------------
2008 Proved Reserves Reconciliation
-------------------------------------------------------------------------
Natural gas Crude oil and Gas
(Bcf) Natural Gas Liquids Equiv-
(MMbbls) alent(1)
(Bcfe)
-------------------------------------------------------------------------
Canada USA Total Canada USA Total Total
-------------------------------------------------------------------------
Start of 2008 7,292 6,008 13,300 868.9 58.3 927.2 18,863
-------------------------------------------------------------------------
Revisions &
improved
recovery 148 (166) (18) 112.8 (3.6) 109.2 638
Extensions &
discoveries 1,311 655 1,966 17.0 3.8 20.8 2,091
Purchase of
reserves
in place 32 7 39 0.2 - 0.2 40
Sale of
reserves
in place (129) (75) (204) (0.9) (2.0) (2.9) (222)
Production (807) (598) (1,405) (44.0) (4.9) (48.9) (1,698)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
End of Year 7,847 5,831 13,678 954.0 51.6 1,005.6 19,712
-------------------------------------------------------------------------
-------------------------------------------------------------------------
% Change +8 -3 +3 +10 -11 +8 +5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Developed 4,945 3,720 8,665 334.4 33.9 368.3 10,875
Undeveloped 2,902 2,111 5,013 619.6 17.7 637.3 8,837
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total 7,847 5,831 13,678 954.0 51.6 1,005.6 19,712
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Gas equivalency has been calculated by EnCana. See the Advisory
Regarding Reserves Data and Other Oil and Gas Information
accompanying this news release.

-------------------------------------------------------------------------
Proved Reserves Costs
-------------------------------------------------------------------------
2008 2007 2006 3 Years
-------------------------------------------------------------------------
Capital investment ($ millions)
-------------------------------------------------------------------------
Finding and development 6,818 5,587 6,107 18,512
Acquisitions 580 2,708 368 3,656
-------------------------------------------------------------------------
Finding, development and acquisitions 7,398 8,295 6,475 22,168
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Reserves additions (Bcfe)
Finding and development 2,729 3,386 3,064 9,179
Acquisitions 40 275 69 384
-------------------------------------------------------------------------
Finding, development and acquisitions 2,769 3,661 3,133 9,563
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Proved reserves costs ($/Mcfe)
Finding and development 2.50 1.65 1.99 2.02
Finding, development and acquisitions 2.67 2.27 2.07 2.32
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     -------------------------------------------------------------------------
2008 Natural Gas and Oil Prices
-------------------------------------------------------------------------
Q4 Q4 % %
2008 2007 change 2008 2007 change
-------------------------------------------------------------------------
Natural gas
NYMEX 6.94 6.97 - 9.04 6.86 +32
EnCana realized
gas price(1) 7.18 7.32 -2 7.92 7.22 +10
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Oil and NGLs
WTI 59.08 90.50 -35 99.75 72.41 +38
Western Canadian
Select (WCS) 39.95 56.85 -30 79.70 49.50 +61
Differential WTI/WCS 19.13 33.65 -43 20.05 22.91 -12
EnCana realized
liquids price(1) 36.16 50.84 -29 71.12 47.00 +51
-------------------------------------------------------------------------
-------------------------------------------------------------------------
3-2-1 crack spread
($/bbl)
Chicago 6.31 9.17 -31 11.22 17.67 -37
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Realized prices include the impact of financial hedging.
>>

Price risk management
     Risk management positions at December 31, 2008 are presented in Note 18
to the unaudited Interim Consolidated Financial Statements for the fourth
quarter of 2008. In 2008, EnCana's commodity price risk management measures
resulted in realized losses of approximately $219 million after-tax, composed
of a $48 million after-tax loss on gas price and basis hedges and a $171
million after-tax loss on oil price hedges and other hedges.
     <<
Two-thirds of expected 2009 gas production hedged during first 10 months
of 2009
>>
     EnCana has hedged about 2.6 Bcf/d of expected gas production through
October 2009 at an average NYMEX equivalent price of $9.13 per Mcf. This price
hedging strategy helps reduce uncertainty in cash flow during periods of
commodity price volatility. EnCana's risk management policy targets hedging,
when appropriate, of up to 50 percent of production from the upcoming year and
up to 25 percent of production from the two successive years. EnCana will
continue to look for opportunities in 2009 to hedge additional volumes at
prices and terms consistent with the company's policy.
EnCana has also hedged 100 percent of its expected U.S. Rockies basis
exposure through 2011 using a combination of downstream transportation and
basis hedges, including some hedges that are based on a percentage of NYMEX
prices and some hedges that move basis risk to alternative markets downstream.


     Corporate developments
     In May, EnCana announced a plan to split into two independent companies -
one a pure-play North American unconventional natural gas company and the
other a fully integrated oil company with in-situ oil properties and
refineries. Preparations were undertaken in order to complete the transaction
in early 2009. Uncertainty in the global financial markets caused EnCana to
delay its plans until clear signs of stabilization return. In the meantime,
EnCana is continuing to prepare documentation and maintain support systems in
anticipation of the proposed transaction.
     Quarterly dividend of 40 cents per share declared

     EnCana's Board of Directors has declared a quarterly dividend of 40 cents
per share payable on March 31, 2009 to common shareholders of record as of
March 16, 2009. Based on the February 11, 2009 closing share price on the New
York Stock Exchange of $43.10, this represents an annualized yield of about
3.7 percent.
     Normal Course Issuer Bid
     In 2008, EnCana purchased 4.8 million of its shares, or less than 1
percent, of the outstanding shares at an average price of $67.13 per share
under the company's Normal Course Issuer Bid program, prior to the May
announcement of EnCana's intention to split into two independent companies, at
which time it suspended purchases under the NCIB. The average diluted shares
for the year were 751.8 million and the shares outstanding at year end were
750.4 million. In November 2008, EnCana renewed its Normal Course Issuer Bid
program. Under the renewed bid, EnCana may purchase for cancellation up to
approximately 75 million of its common shares, representing approximately 10
percent of the common shares outstanding on October 31, 2008, through market
purchases. Upon completion of the proposed split transaction and subject to
market conditions prevailing at that time, EnCana intends to resume purchases
of common shares under the program.
     Financial strength
     EnCana has a very strong balance sheet, with more than 80 percent of
EnCana's outstanding debt comprised of long-term, fixed-rate debt with an
average remaining term of more than 14 years. Long-term debt maturities in
2009 are $250 million and $200 million in 2010. At December 31, 2008, EnCana
had $2.6 billion in unused committed credit facilities. EnCana targets a debt
to capitalization ratio between 30 and 40 percent. At December 31, 2008, the
company's debt to capitalization ratio was 28 percent and debt to adjusted
EBITDA, on a trailing 12-month basis, was 0.7 times. The company expects to
continue to be in the lower end of its managed ranges through 2009.


     NOTE: EnCana changed its debt metric calculation to focus on long-term
debt rather than net debt. This new calculation excludes the impact of
fluctuations related to mark-to-market accounting. The company believes this
debt to capitalization ratio, in which debt is defined as the current and
long-term portions of long-term debt, provides a more conservative measure of
liquidity and is a better reflection of the company's financial position.
     In 2008, EnCana invested $7.1 billion in capital, excluding acquisitions
and divestitures, on continued development of its key resource plays and
expansion of the company's downstream heavy oil processing capacity through
its venture with ConocoPhillips. Acquisitions in 2008 were $1.2 billion,
mainly in the U.S., and largely due to investments in Haynesville properties.
Proceeds from divestitures were $0.9 billion. Depending on market conditions
in 2009, EnCana may divest between $500 million and $1 billion of assets.
     <<
-------------------------------------------------------------------------
CONFERENCE CALL TODAY
11 a.m. Mountain Time (1 p.m. Eastern Time)
     EnCana will host a conference call today Thursday, February 12, 2009
starting at 11:00 a.m. MT (1:00 p.m. ET). To participate, please dial
(800) 731-5319 (toll-free in North America) or (416) 644-3422
approximately 10 minutes prior to the conference call. An archived
recording of the call will be available from approximately 2:00 p.m. MT
on February 12 until midnight February 19, 2009 by dialling
(877) 289-8525 or (416) 640-1917 and entering access code 21297063.
     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 non-GAAP measures as follows:
     -   Cash flow is a non-GAAP measure defined as cash from operating
activities excluding net change in other assets and liabilities and
net change in non-cash working capital from continuing operations,
both of which are defined on the Consolidated Statement of Cash
Flows, in this news release and interim financial statements.
- 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 debt issued from
Canada and the partnership contribution receivable, the after-tax
foreign exchange gain/loss on settlement of intercompany
transactions, future income tax on foreign exchange related to U.S.
dollar intercompany debt recognized for tax purposes only and the
effect of changes in statutory 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
U.S. dollar debt issued from Canada has maturity dates in excess of
five years.
- Free cash flow is a non-GAAP measure that EnCana defines as cash flow
in excess of capital investment, excluding net acquisitions and
divestitures, and is used to determine the funds available for other
investing and/or financing activities.
- Capitalization is a non-GAAP measure defined as debt plus
shareholders' equity. Debt to capitalization and debt to adjusted
EBITDA are two ratios which management uses to steward the company's
overall debt position as measures of the company's overall financial
strength.
- Adjusted EBITDA is a non-GAAP measure defined as net earnings from
continuing operations before gains or losses on divestitures, income
taxes, foreign exchange gains or losses, interest net, accretion of
asset retirement obligation, and depreciation, depletion and
amortization.
>>
     These measures have been described and presented in this news release in
order to provide shareholders and potential investors with additional
information regarding EnCana's liquidity and its ability to generate funds to
finance its operations.
     EnCana Corporation
     With an enterprise value of approximately $40 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 2008, 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 2008 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. 2008
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, debt to capitalization ratio, debt to
adjusted EBITDA multiple, 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 divestitures; the
proposed corporate reorganization transaction, the timing thereof and the
conditions for proceeding with the transaction; potential dividends;
anticipated success of EnCana's market risk mitigation strategy; anticipated
purchases pursuant to the Normal Course Issuer Bid, the timing thereof and the
source of funding therefor; potential demand for natural gas; anticipated oil
production in 2009 and beyond; anticipated drilling; potential capital
expenditures and investment; potential oil, natural gas and NGLs production in
2009 and beyond; anticipated costs and inflationary pressures; 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 assumptions,
risks and uncertainties include, among other things: volatility of and
assumptions regarding oil and gas prices; assumptions based upon the company's
current guidance; risks associated with the timing and the ability to obtain
any necessary approvals, waivers, consents, court orders and other
requirements necessary or desirable to permit or facilitate the proposed
corporate reorganization transaction (including regulatory and shareholder
approvals); the risk that any applicable conditions of the proposed corporate
reorganization transaction may not be satisfied; 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.
Forward-looking information respecting anticipated 2009 cash flow and
free cash flow for EnCana is based upon achieving average production of oil
and gas for 2009 of approximately 4.6 Bcfe/d, average commodity prices for
2009 based on a WTI price of $55 - $75/bbl for oil, a NYMEX price of $5.50 -
$7.50/Mcf for natural gas, an average U.S./Canadian dollar foreign exchange
rate of $0.75 - $0.85, an average Chicago 3-2-1 crack spread for 2009 of $5 -
$10/bbl for refining margins, and an average number of outstanding shares for
EnCana of approximately 750 million. Forward-looking information respecting
the rescheduling of the proposed corporate reorganization transaction is based
upon the assumption that financial and other markets will stabilize.
Assumptions relating to forward-looking statements generally include EnCana's
current expectations and projections made by the company in light of, and
generally consistent with, its historical experience and its perception of
historical trends, as well as expectations regarding rates of advancement and
innovation, generally consistent with and informed by its past experience, all
of which are subject to the risk factors identified elsewhere in this news
release.
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.
     <<
EnCana Corporation

Interim Consolidated Financial Statements
(unaudited)
For the period ended December 31, 2008
     (U.S. Dollars)

     CONSOLIDATED STATEMENT OF EARNINGS (unaudited)
                                   Three Months Ended     Twelve Months Ended
December 31, December 31,
($ millions, except ------------------- --------------------
per share amounts) 2008 2007 2008 2007
-------------------------------------------------------------------------


     REVENUES, NET OF
ROYALTIES (Note 5) $ 6,359 $ 5,875 $ 30,064 $ 21,700
     EXPENSES (Note 5)
Production and mineral
taxes 72 63 478 291
Transportation and
selling 422 352 1,704 1,264
Operating 549 632 2,475 2,278
Purchased product 2,466 2,704 11,186 8,583
Depreciation, depletion
and amortization 996 1,086 4,223 3,816
Administrative 74 121 473 384
Interest, net (Note 8) 158 131 586 428
Accretion of asset
retirement
obligation (Note 13) 18 18 79 64
Foreign exchange (gain)
loss, net (Note 9) 253 (233) 423 (164)
(Gain) loss on
divestitures (Note 7) 1 22 (140) (65)
-------------------------------------------------------------------------
5,009 4,896 21,487 16,879
-------------------------------------------------------------------------
NET EARNINGS BEFORE
INCOME TAX 1,350 979 8,577 4,821
Income tax
expense (Note 10) 273 (28) 2,633 937
-------------------------------------------------------------------------
NET EARNINGS FROM
CONTINUING OPERATIONS 1,077 1,007 5,944 3,884
NET EARNINGS FROM
DISCONTINUED
OPERATIONS (Note 6) - 75 - 75
-------------------------------------------------------------------------
NET EARNINGS $ 1,077 $ 1,082 $ 5,944 $ 3,959
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     NET EARNINGS FROM
CONTINUING
OPERATIONS (Note 17)
PER COMMON SHARE
Basic $ 1.44 $ 1.34 $ 7.92 $ 5.13
Diluted $ 1.43 $ 1.33 $ 7.91 $ 5.08
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     NET EARNINGS PER
COMMON SHARE (Note 17)
Basic $ 1.44 $ 1.44 $ 7.92 $ 5.23
Diluted $ 1.43 $ 1.43 $ 7.91 $ 5.18
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.



CONSOLIDATED STATEMENT OF RETAINED EARNINGS (unaudited)
                                                          Twelve Months Ended
December 31,
--------------------
($ millions) 2008 2007
-------------------------------------------------------------------------
     RETAINED EARNINGS, BEGINNING OF YEAR              $   13,082  $   11,344
Net Earnings 5,944 3,959
Dividends on Common Shares (1,199) (603)
Charges for Normal Course Issuer Bid (Note 14) (243) (1,618)
-------------------------------------------------------------------------
RETAINED EARNINGS, END OF YEAR $ 17,584 $ 13,082
-------------------------------------------------------------------------
-------------------------------------------------------------------------

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (unaudited)
                                   Three Months Ended     Twelve Months Ended
December 31, December 31,
------------------- --------------------
($ millions) 2008 2007 2008 2007
-------------------------------------------------------------------------


     NET EARNINGS              $    1,077  $    1,082  $    5,944  $    3,959
OTHER COMPREHENSIVE
INCOME, NET OF TAX
Foreign Currency
Translation Adjustment (1,448) (110) (2,230) 1,688
-------------------------------------------------------------------------
COMPREHENSIVE INCOME $ (371) $ 972 $ 3,714 $ 5,647
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     CONSOLIDATED STATEMENT OF ACCUMULATED OTHER COMPREHENSIVE INCOME
(unaudited)
                                                          Twelve Months Ended
December 31,
--------------------
($ millions) 2008 2007
-------------------------------------------------------------------------
     ACCUMULATED OTHER COMPREHENSIVE INCOME,
BEGINNING OF YEAR $ 3,063 $ 1,375
Foreign Currency Translation Adjustment (2,230) 1,688
-------------------------------------------------------------------------
ACCUMULATED OTHER COMPREHENSIVE INCOME,
END OF YEAR $ 833 $ 3,063
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.
     CONSOLIDATED BALANCE SHEET (unaudited)
As at As at
December December
($ millions) 31, 2008 31, 2007
-------------------------------------------------------------------------
     ASSETS
Current Assets
Cash and cash equivalents $ 383 $ 553
Accounts receivable and accrued revenues 1,568 2,381
Current portion of partnership
contribution receivable 313 297
Risk management (Note 18) 2,818 385
Inventories (Note 11) 520 828
-------------------------------------------------------------------------
5,602 4,444
Property, Plant and Equipment, net (Note 5) 35,424 35,865
Investments and Other Assets 727 607
Partnership Contribution Receivable 2,834 3,147
Risk Management (Note 18) 234 18
Goodwill 2,426 2,893
-------------------------------------------------------------------------
(Note 5) $ 47,247 $ 46,974
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued
liabilities $ 2,871 $ 3,982
Income tax payable 424 1,150
Current portion of partnership
contribution payable 306 288
Risk management (Note 18) 43 207
Current portion of long-term debt (Note 12) 250 703
-------------------------------------------------------------------------
3,894 6,330
Long-Term Debt (Note 12) 8,755 8,840
Other Liabilities 576 242
Partnership Contribution Payable 2,857 3,163
Risk Management (Note 18) 7 29
Asset Retirement Obligation (Note 13) 1,265 1,458
Future Income Taxes 6,919 6,208
-------------------------------------------------------------------------
24,273 26,270
-------------------------------------------------------------------------
Shareholders' Equity
Share capital (Note 14) 4,557 4,479
Paid in surplus - 80
Retained earnings 17,584 13,082
Accumulated other comprehensive income 833 3,063
Total Shareholders' Equity 22,974 20,704
-------------------------------------------------------------------------
$ 47,247 $ 46,974
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.
     CONSOLIDATED STATEMENT OF CASH FLOWS (unaudited)
                                   Three Months Ended     Twelve Months Ended
December 31, December 31,
------------------- --------------------
($ millions) 2008 2007 2008 2007
-------------------------------------------------------------------------


     OPERATING ACTIVITIES
Net earnings from
continuing operations $ 1,077 $ 1,007 $ 5,944 $ 3,884
Depreciation, depletion
and amortization 996 1,086 4,223 3,816
Future income
taxes (Note 10) 155 (608) 1,646 (617)
Cash tax on sale
of assets (Note 10) - - 25 -
Unrealized (gain)
loss on risk
management (Note 18) (1,090) 569 (2,729) 1,235
Unrealized foreign
exchange (gain) loss 268 (52) 417 41
Accretion of asset
retirement
obligation (Note 13) 18 18 79 64
(Gain) loss on
divestitures (Note 7) 1 22 (140) (65)
Other (126) (108) (79) 95
Net change in other
assets and liabilities 21 (21) (262) (16)
Net change in non-cash
working capital from
continuing operations 723 280 (269) (8)
-------------------------------------------------------------------------
Cash From Operating
Activities 2,043 2,193 8,855 8,429
-------------------------------------------------------------------------
     INVESTING ACTIVITIES
Capital
expenditures (Note 5) (1,885) (4,408) (8,254) (8,737)
Proceeds from
divestitures (Note 7) 311 (24) 904 481
Cash tax on
sale of assets (Note 10) - - (25) -
Net change in
investments and other (101) (31) (267) (5)
Net change in non-cash
working capital from
continuing operations 18 120 89 86
-------------------------------------------------------------------------
Cash (Used in)
Investing Activities (1,657) (4,343) (7,553) (8,175)
-------------------------------------------------------------------------
     FINANCING ACTIVITIES
Net issuance (repayment)
of revolving long-term
debt (304) 1,090 (53) 181
Issuance of
long-term debt (Note 12) - 1,485 723 2,409
Repayment of long-term debt - (257) (664) (257)
Issuance of
common shares (Note 14) 2 18 80 176
Purchase of
common shares (Note 14) - - (326) (2,025)
Dividends on
common shares (300) (150) (1,199) (603)
Other - 1 - -
-------------------------------------------------------------------------
Cash From (Used in)
Financing Activities (602) 2,187 (1,439) (119)
-------------------------------------------------------------------------
FOREIGN EXCHANGE GAIN (LOSS)
ON CASH AND CASH EQUIVALENTS
HELD IN FOREIGN CURRENCY (23) 1 (33) 16
-------------------------------------------------------------------------
     INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS (239) 38 (170) 151
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD 622 515 553 402
-------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS,
END OF PERIOD $ 383 $ 553 $ 383 $ 553
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 operations are in the business of the exploration
for, the development of, and the production and marketing of natural gas,
crude oil and natural gas liquids ("NGLs"), 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, 2007, 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, 2007.
     2.  CHANGES IN ACCOUNTING POLICIES AND PRACTICES
     As disclosed in the December 31, 2007 annual audited Consolidated
Financial Statements, on January 1, 2008, the Company adopted
the following Canadian Institute of Chartered Accountants ("CICA")
Handbook Sections:
     -   "Inventories", Section 3031. The new standard replaces the previous
inventories standard and requires inventory to be valued on a first-
in, first-out or weighted average cost basis, which is consistent
with EnCana's former accounting policy. The new standard allows
the reversal of previous write-downs to net realizable value when
there is a subsequent increase in the value of inventories. The
adoption of this standard has had no material impact on EnCana's
Consolidated Financial Statements.
     -   "Financial Instruments - Presentation", Section 3863 and "Financial
Instruments - Disclosures", Section 3862. The new disclosure standard
increases EnCana's disclosure regarding the nature and extent of the
risks associated with financial instruments and how those risks are
managed (See Note 18). The new presentation standard carries forward
the former presentation requirements.
     -   "Capital Disclosures", Section 1535. The new standard requires EnCana
to disclose its objectives, policies and processes for managing its
capital structure (See Note 15).
     3.  RECENT ACCOUNTING PRONOUNCEMENTS
     As of January 1, 2009, EnCana will be required to adopt the CICA Handbook
Section 3064, "Goodwill and Intangible Assets", which will replace the
existing Goodwill and Intangible Assets standard. The new standard
revises the requirement for recognition, measurement, presentation and
disclosure of intangible assets. The adoption of this standard should not
have a material impact on EnCana's Consolidated Financial Statements.
     In February 2008, the CICA's Accounting Standards Board confirmed that
International Financial Reporting Standards ("IFRS") will replace
Canadian generally accepted accounting principles in 2011 for profit-
oriented Canadian publicly accountable enterprises. EnCana will
be required to report its results in accordance with IFRS beginning in
2011. The Company has developed a changeover plan to complete
the transition to IFRS by January 1, 2011, including the preparation of
required comparative information.
     The key elements of EnCana's changeover plan include:
     -   determine appropriate changes to accounting policies and required
amendments to financial disclosures;
- identify and implement changes in associated processes and
information systems;
- comply with internal control requirements;
- communicate collateral impacts to internal business groups; and
- educate and train internal and external stakeholders.
     The Company is currently analyzing accounting policy alternatives and
identifying implementation options for the corresponding process changes.
EnCana will update its IFRS changeover plan to reflect new and amended
accounting standards issued by the International Accounting Standards
Board. As IFRS is expected to change prior to 2011, the impact of IFRS on
the Company's consolidated financial statements is not reasonably
determinable at this time.


     4.  PROPOSED CORPORATE REORGANIZATION
     On May 11, 2008, EnCana announced its plans to split into two independent
energy companies - one a North American natural gas company and the other
a fully integrated oil company with in-situ oil properties and refineries
supplemented by reliable production from various natural gas and crude
oil resource plays.
     The proposed corporate reorganization (the "Arrangement") would be
implemented through a court approved Plan of Arrangement and is subject
to shareholder approval. The Arrangement would result in two publicly
traded entities with the names of Cenovus Energy Inc.("Cenovus") and
EnCana Corporation. Each EnCana shareholder would receive one share of
each entity in exchange for each EnCana Common Share held. On October 15,
2008, EnCana announced the proposed Arrangement would be delayed until
the global debt and equity markets regain stability.
     5.  SEGMENTED INFORMATION
     The Company's reportable segments are as follows:
     -   Canada includes the Company's exploration for, and development and
production of natural gas, crude oil and NGLs and other related
activities within the Canadian cost centre.


     -   USA includes the Company's exploration for, and development and
production of natural gas, NGLs and other related activities within
the United States cost centre.
     -   Downstream Refining is focused on the refining of crude oil into
petroleum and chemical products at two refineries located in
the United States. The refineries are jointly owned with
ConocoPhillips.
     -   Market Optimization is primarily responsible for the sale of the
Company's proprietary production. These results are included in
the Canada and USA segments. Market optimization activities include
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 and Other mainly 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 segments are
based on market values and eliminated on consolidation. The tables in
this note present financial information on an after eliminations basis.
     EnCana has updated its segmented reporting to present the upstream
Canadian and United States cost centres and Downstream Refining
as separate reportable segments. This results in EnCana presenting the
Canadian portion of the Integrated Oil Division as part of the
Canada segment. Previously, this was aggregated and presented in the
Integrated Oil segment. Prior periods have been restated to reflect the
new presentation.


     EnCana has a decentralized decision making and reporting structure.
Accordingly, the Company is organized into Divisions as follows:
     -   Canadian Plains Division includes natural gas production and crude
oil development and production assets located in eastern Alberta and
Saskatchewan.
     -   Canadian Foothills Division includes natural gas development and
production assets located in western Alberta and British Columbia as
well as the Company's Canadian offshore assets.
     -   USA Division includes the assets located in the United States and
comprises the USA segment described above.
     -   Integrated Oil Division is the combined total of Integrated Oil -
Canada and Downstream Refining. Integrated Oil - Canada includes the
Company's exploration for, and development and production of bitumen
using in-situ recovery methods. Integrated Oil - Canada is composed
of EnCana's interests in the FCCL Oil Sands Partnership jointly owned
with ConocoPhillips, the Athabasca natural gas assets and other
bitumen interests.
     Operations that have been discontinued are disclosed in Note 6.
     Results of Continuing Operations (For the three months ended December 31)
     Segment and Geographic Information
                                                                 Downstream
Canada USA Refining
-------------------------------------------------------------------------
2008 2007 2008 2007 2008 2007
-------------------------------------------------------------------------
     Revenues, Net of
Royalties $ 1,961 $ 2,220 $ 1,273 $ 1,178 $ 1,497 $ 2,206
Expenses
Production and
mineral taxes 13 16 59 47 - -
Transportation
and selling 287 265 135 87 - -
Operating 280 338 136 154 117 111
Purchased product (25) (27) - - 1,960 1,915
-------------------------------------------------------------------------
1,406 1,628 943 890 (580) 180
Depreciation,
depletion and
amortization 481 634 438 330 50 44
-------------------------------------------------------------------------
Segment Income
(Loss) $ 925 $ 994 $ 505 $ 560 $ (630) $ 136
-------------------------------------------------------------------------
-------------------------------------------------------------------------
                               Market           Corporate
Optimization & Other Consolidated
-------------------------------------------------------------------------
2008 2007 2008 2007 2008 2007
-------------------------------------------------------------------------
     Revenues, Net of
Royalties $ 543 $ 837 $ 1,085 $ (566) $ 6,359 $ 5,875
Expenses
Production and
mineral taxes - - - - 72 63
Transportation
and selling - - - - 422 352
Operating 18 9 (2) 20 549 632
Purchased product 531 816 - - 2,466 2,704
-------------------------------------------------------------------------
(6) 12 1,087 (586) 2,850 2,124
Depreciation,
depletion and
amortization 3 6 24 72 996 1,086
-------------------------------------------------------------------------
Segment Income
(Loss) $ (9) $ 6 $ 1,063 $ (658) $ 1,854 $ 1,038
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Administrative 74 121
Interest, net 158 131
Accretion of asset
retirement obligation 18 18
Foreign exchange (gain)
loss, net 253 (233)
(Gain) loss on divestitures 1 22
-------------------------------------------------------------------------
504 59
-------------------------------------------------------------------------
Net Earnings Before Income Tax 1,350 979
Income tax expense 273 (28)
-------------------------------------------------------------------------
Net Earnings From Continuing Operations $ 1,077 $ 1,007
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     Results of Continuing Operations  (For the three months ended
December 31)
     Product and Divisional Information
                                           Canada Segment
-------------------------------------------------------------------------
Canadian Canadian Integrated
Plains Foothills Oil - Canada Total
-------------------------------------------------------------------------
2008 2007 2008 2007 2008 2007 2008 2007
-------------------------------------------------------------------------
     Revenues, Net of
Royalties $ 789 $ 964 $ 923 $1,017 $ 249 $ 239 $1,961 $2,220
Expenses
Production and
mineral taxes 10 11 3 5 - - 13 16
Transportation
and selling 62 97 72 52 153 116 287 265
Operating 99 128 131 152 50 58 280 338
Purchased
product - - - - (25) (27) (25) (27)
-------------------------------------------------------------------------
Operating
Cash Flow $ 618 $ 728 $ 717 $ 808 $ 71 $ 92 $1,406 $1,628
-------------------------------------------------------------------------
-------------------------------------------------------------------------
                                           Canadian Plains Division
-------------------------------------------------------------------------
Gas Oil & NGLs Other Total
-------------------------------------------------------------------------
2008 2007 2008 2007 2008 2007 2008 2007
-------------------------------------------------------------------------


     Revenues, Net
of Royalties $ 506 $ 567 $ 280 $ 393 $ 3 $ 4 $ 789 $ 964
Expenses
Production and
mineral taxes 4 3 6 8 - - 10 11
Transportation
and selling 16 21 46 76 - - 62 97
Operating 50 65 48 62 1 1 99 128
-------------------------------------------------------------------------
Operating
Cash Flow $ 436 $ 478 $ 180 $ 247 $ 2 $ 3 $ 618 $ 728
-------------------------------------------------------------------------
-------------------------------------------------------------------------
                                           Canadian Foothills Division
-------------------------------------------------------------------------
Gas Oil & NGLs Other Total
-------------------------------------------------------------------------
2008 2007 2008 2007 2008 2007 2008 2007
-------------------------------------------------------------------------


     Revenues, Net
of Royalties $ 829 $ 880 $ 84 $ 122 $ 10 $ 15 $ 923 $1,017
Expenses
Production and
mineral taxes 2 4 1 1 - - 3 5
Transportation
and selling 43 50 3 2 26 - 72 52
Operating 117 137 9 10 5 5 131 152
-------------------------------------------------------------------------
Operating
Cash Flow $ 667 $ 689 $ 71 $ 109 $ (21)$ 10 $ 717 $ 808
-------------------------------------------------------------------------
-------------------------------------------------------------------------
                                           USA Division
-------------------------------------------------------------------------
Gas Oil & NGLs Other Total
-------------------------------------------------------------------------
2008 2007 2008 2007 2008 2007 2008 2007
-------------------------------------------------------------------------


     Revenues, Net
of Royalties $1,180 $1,011 $ 54 $ 99 $ 39 $ 68 $1,273 $1,178
Expenses
Production and
mineral taxes 54 40 5 7 - - 59 47
Transportation
and selling 135 87 - - - - 135 87
Operating 86 95 - - 50 59 136 154
-------------------------------------------------------------------------
Operating
Cash Flow $ 905 $ 789 $ 49 $ 92 $ (11)$ 9 $ 943 $ 890
-------------------------------------------------------------------------
-------------------------------------------------------------------------
                                           Integrated Oil Division
-------------------------------------------------------------------------
Downstream
Oil(x) Refining Other(x) Total
-------------------------------------------------------------------------
2008 2007 2008 2007 2008 2007 2008 2007
-------------------------------------------------------------------------


     Revenues, Net
of Royalties $ 219 $ 186 $1,497 $2,206 $ 30 $ 53 $1,746 $2,445
Expenses
Production and
mineral taxes - - - - - - - -
Transportation
and selling 146 108 - - 7 8 153 116
Operating 37 36 117 111 13 22 167 169
Purchased
product - - 1,960 1,915 (25) (27) 1,935 1,888
-------------------------------------------------------------------------
Operating
Cash Flow $ 36 $ 42 $ (580)$ 180 $ 35 $ 50 $ (509)$ 272
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x)Oil and Other comprise Integrated Oil - Canada. Other includes
production of natural gas and bitumen from the Athabasca and Senlac
properties.
     Results of Continuing Operations (For the twelve months ended
December 31)
     Segment and Geographic Information
                                                                 Downstream
Canada USA Refining
-------------------------------------------------------------------------
2008 2007 2008 2007 2008 2007
-------------------------------------------------------------------------
     Revenues, Net of
Royalties $ 10,050 $ 8,308 $ 5,629 $ 4,372 $ 9,011 $ 7,315
Expenses
Production and
mineral taxes 108 102 370 189 - -
Transportation
and selling 1,202 947 502 307 - -
Operating 1,333 1,204 618 595 492 428
Purchased product (151) (88) - - 8,760 5,813
-------------------------------------------------------------------------
7,558 6,143 4,139 3,281 (241) 1,074
Depreciation,
depletion and
amortization 2,198 2,298 1,691 1,181 188 159
-------------------------------------------------------------------------
Segment Income
(Loss) $ 5,360 $ 3,845 $ 2,448 $ 2,100 $ (429)$ 915
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Market Corporate
Optimization & Other Consolidated
-------------------------------------------------------------------------
2008 2007 2008 2007 2008 2007
-------------------------------------------------------------------------
     Revenues, Net of
Royalties $ 2,655 $ 2,944 $ 2,719 $ (1,239)$ 30,064 $ 21,700
Expenses
Production and
mineral taxes - - - - 478 291
Transportation
and selling - 10 - - 1,704 1,264
Operating 45 37 (13) 14 2,475 2,278
Purchased product 2,577 2,858 - - 11,186 8,583
-------------------------------------------------------------------------
33 39 2,732 (1,253) 14,221 9,284
Depreciation,
depletion and
amortization 15 17 131 161 4,223 3,816
-------------------------------------------------------------------------
Segment Income
(Loss) $ 18 $ 22 $ 2,601 $ (1,414) 9,998 5,468
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Administrative 473 384
Interest, net 586 428
Accretion of asset
retirement
obligation 79 64
Foreign exchange
(gain) loss, net 423 (164)
(Gain) loss on divestitures (140) (65)
-------------------------------------------------------------------------
1,421 647
-------------------------------------------------------------------------
Net Earnings Before
Income Tax 8,577 4,821
Income tax expense 2,633 937
-------------------------------------------------------------------------
Net Earnings From
Continuing Operations $ 5,944 $ 3,884
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     Results of Continuing Operations (For the twelve months ended
December 31)
     Product and Divisional Information
                                           Canada Segment
-------------------------------------------------------------------------
Canadian Canadian Integrated
Plains Foothills Oil - Canada Total
-------------------------------------------------------------------------
2008 2007 2008 2007 2008 2007 2008 2007
-------------------------------------------------------------------------
     Revenues, Net
of Royalties $4,418 $3,652 $4,355 $3,679 $1,277 $ 977 $10,050 $8,308
Expenses
Production
and mineral
taxes 74 63 33 39 1 - 108 102
Transportation
and selling 392 345 239 201 571 401 1,202 947
Operating 484 440 609 535 240 229 1,333 1,204
Purchased
product - - - - (151) (88) (151) (88)
-------------------------------------------------------------------------
Operating
Cash Flow $3,468 $2,804 $3,474 $2,904 $ 616 $ 435 $7,558 $6,143
-------------------------------------------------------------------------
-------------------------------------------------------------------------
                                           Canadian Plains Division
-------------------------------------------------------------------------
Gas Oil & NGLs Other Total
-------------------------------------------------------------------------
2008 2007 2008 2007 2008 2007 2008 2007
-------------------------------------------------------------------------


     Revenues, Net
of Royalties $2,301 $2,186 $2,106 $1,453 $ 11 $ 13 $4,418 $3,652
Expenses
Production and
mineral taxes 36 34 38 29 - - 74 63
Transportation
and selling 71 82 321 263 - - 392 345
Operating 241 221 239 215 4 4 484 440
-------------------------------------------------------------------------
Operating
Cash Flow $1,953 $1,849 $1,508 $ 946 $ 7 $ 9 $3,468 $2,804
-------------------------------------------------------------------------
-------------------------------------------------------------------------
                                           Canadian Foothills Division
-------------------------------------------------------------------------
Gas Oil & NGLs Other Total
-------------------------------------------------------------------------
2008 2007 2008 2007 2008 2007 2008 2007
-------------------------------------------------------------------------


     Revenues, Net
of Royalties $3,720 $3,232 $ 578 $ 390 $ 57 $ 57 $4,355 $3,679
Expenses
Production
and mineral
taxes 28 36 5 3 - - 33 39
Transportation
and selling 201 192 12 9 26 - 239 201
Operating 549 482 39 33 21 20 609 535
-------------------------------------------------------------------------
Operating
Cash Flow $2,942 $2,522 $ 522 $ 345 $ 10 $ 37 $3,474 $2,904
-------------------------------------------------------------------------
-------------------------------------------------------------------------
                                           USA Division
-------------------------------------------------------------------------
Gas Oil & NGLs Other Total
-------------------------------------------------------------------------
2008 2007 2008 2007 2008 2007 2008 2007
-------------------------------------------------------------------------


     Revenues, Net
of Royalties $4,934 $3,765 $ 407 $ 309 $ 288 $ 298 $5,629 $4,372
Expenses
Production and
mineral taxes 334 167 36 22 - - 370 189
Transportation
and selling 502 307 - - - - 502 307
Operating 352 323 - - 266 272 618 595
-------------------------------------------------------------------------
Operating
Cash Flow $3,746 $2,968 $ 371 $ 287 $ 22 $ 26 $4,139 $3,281
-------------------------------------------------------------------------
-------------------------------------------------------------------------
                                           Integrated Oil Division
-------------------------------------------------------------------------
Downstream
Oil(x) Refining Other(x) Total
-------------------------------------------------------------------------
2008 2007 2008 2007 2008 2007 2008 2007
-------------------------------------------------------------------------


     Revenues, Net
of Royalties $1,117 $ 738 $9,011 $7,315 $ 160 $ 239 $10,288 $8,292
Expenses
Production
and mineral
taxes - - - - 1 - 1 -
Transportation
and selling 526 366 - - 45 35 571 401
Operating 170 159 492 428 70 70 732 657
Purchased
product - - 8,760 5,813 (151) (88) 8,609 5,725
-------------------------------------------------------------------------
Operating
Cash Flow $ 421 $ 213 $ (241)$1,074 $ 195 $ 222 $ 375 $1,509
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x)Oil and Other comprise Integrated Oil - Canada. Other includes
production of natural gas and bitumen from the Athabasca and Senlac
properties.
     Capital Expenditures (Continuing Operations)
                                   Three Months Ended     Twelve Months Ended
December 31, December 31,
-------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------


     Capital
Canadian Plains $ 254 $ 288 $ 847 $ 846
Canadian Foothills 463 625 2,299 2,439
Integrated Oil - Canada 162 194 656 451
-------------------------------------------------------------------------
Canada 879 1,107 3,802 3,736
USA 815 606 2,615 1,919
Downstream Refining 168 53 478 220
Market Optimization 6 1 17 6
Corporate & Other 57 38 168 154
-------------------------------------------------------------------------
1,925 1,805 7,080 6,035
-------------------------------------------------------------------------
     Acquisition Capital
Canadian Foothills 31 8 151 75
Integrated Oil - Canada - - - 14
-------------------------------------------------------------------------
Canada 31 8 151 89
USA (71) 2,595 1,023 2,613
-------------------------------------------------------------------------
(40) 2,603 1,174 2,702
-------------------------------------------------------------------------
Total $ 1,885 $ 4,408 $ 8,254 $ 8,737
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     On September 25, 2008, EnCana acquired certain land and property in
Louisiana for approximately $101 million before closing adjustments. The
purchase was facilitated by an unrelated party, Brown Haynesville
Leasehold LLC ("Brown Haynesville"), 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.
     On July 23, 2008, EnCana acquired certain land and mineral interests in
Louisiana for approximately $457 million before closing adjustments. The
purchase was facilitated by an unrelated party, Brown Southwest Minerals
LLC ("Brown Southwest"), 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. On November 12, 2008, an unrelated party exercised an
option to purchase certain interests as part of the above acquisition
for approximately $157 million, reducing the qualifying like kind
exchange to approximately $300 million.
     Pursuant to the agreements with Brown Haynesville and Brown Southwest,
EnCana operates the properties, receives all the revenue and pays all of
the expenses associated with the properties. The arrangements with Brown
Haynesville and Brown Southwest will be completed on March 24, 2009 and
January 19, 2009 respectively and the assets will be transferred to
EnCana at that time. EnCana has determined that each relationship with
Brown Haynesville and Brown Southwest represents an interest in a
Variable Interest Entity("VIE") and that EnCana is the primary
beneficiary of the VIE. EnCana has consolidated Brown Haynesville and
Brown Southwest from the dates of acquisition.
     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 held the majority of the
assets in trust for the Company in anticipation of a qualifying like kind
exchange for U.S. tax purposes. The relationship with Brown Kilgore
represented an interest in a VIE from November 20, 2007 to May 18, 2008.
During this period, EnCana was the primary beneficiary of the VIE and
consolidated Brown Kilgore. On May 18, 2008, when the arrangement with
Brown Kilgore was completed, the assets were transferred to EnCana.
     Property, Plant and Equipment and Total Assets by Segment
                                  Property, Plant
and Equipment Total Assets
------------------------------------------------
As at As at
------------------------------------------------
December December December December
31, 2008 31, 2007 31, 2008 31, 2007
-------------------------------------------------------------------------
     Canada                     $  17,105   $  19,519   $  23,441   $  27,014
USA 13,541 11,879 14,635 12,948
Downstream Refining 4,032 3,706 4,637 4,887
Market Optimization 140 171 429 478
Corporate & Other 606 590 4,105 1,647
-------------------------------------------------------------------------
Total $ 35,424 $ 35,865 $ 47,247 $ 46,974
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     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. As at December 31, 2008, Corporate and Other
Property, Plant and Equipment and Total Assets includes EnCana's accrual
to date of $252 million (2007 - $147 million) related to this office
project as an asset under construction.


     On January 4, 2008, EnCana signed the contract for the design and
construction of the Production Field Centre ("PFC") for the Deep Panuke
project. As at December 31, 2008, Canada Property, Plant, and Equipment
and Total Assets includes EnCana's accrual to date of $199 million
related to this offshore facility as an asset under construction.
     Corresponding liabilities for these projects are 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 or the Deep Panuke PFC.
     6.  DISCONTINUED OPERATIONS
     Midstream
The $75 million gain on discontinuance in 2007 was 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.
     7.  DIVESTITURES
     Proceeds received on the sale of assets and investments were $904 million
(2007 - $481 million). The significant items are described below.
     Canada
In 2008, the Company completed the divestiture of mature conventional oil
and natural gas assets for proceeds of $39 million (2007 - nil) in
Canadian Plains and $400 million (2007 - $213 million) in Canadian
Foothills.
     In May 2007, the Company completed the sale of its assets in the
Mackenzie Delta and Beaufort Sea for proceeds of $159 million, which were
credited to property, plant and equipment in the Canadian cost centre and
reported in Canadian Foothills.
     USA
In 2008, the Company completed the divestiture of mature conventional
natural gas assets for proceeds of $251 million (2007 - $10 million).
     Corporate and Other
In September 2008, the Company completed the sale of its interests in
Brazil for net proceeds of $164 million, before closing ajdustments,
resulting in a gain on sale of $124 million. After recording income tax
of $25 million, EnCana recorded an after-tax gain of $99 million.
     In August 2007, the Company closed the sale of its 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 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 5 for further discussion of The Bow office
project assets.
     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.
     8. INTEREST, NET
                                   Three Months Ended     Twelve Months Ended
December 31, December 31,
---------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------


     Interest Expense -
Long-Term Debt $ 130 $ 129 $ 556 $ 460
Interest Expense - Other(x) 80 66 246 244
Interest Income(x) (52) (64) (216) (276)
-------------------------------------------------------------------------
$ 158 $ 131 $ 586 $ 428
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x)Interest Expense - Other and Interest Income are primarily due to the
Partnership Contribution Payable and Receivable, respectively.
     9.  FOREIGN EXCHANGE (GAIN) LOSS, NET
                                   Three Months Ended     Twelve Months Ended
December 31, December 31,
---------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------


     Unrealized Foreign Exchange
(Gain) Loss on:
Translation of U.S. dollar
debt issued from Canada $ 663 $ (75) $ 1,033 $ (683)
Translation of U.S. dollar
partnership contribution
receivable issued from
Canada (390) 22 (608) 617
Other Foreign Exchange
(Gain) Loss (20) (180) (2) (98)
-------------------------------------------------------------------------
$ 253 $ (233) $ 423 $ (164)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     10. INCOME TAXES
The provision for income taxes is as follows:
                                   Three Months Ended     Twelve Months Ended
December 31, December 31,
---------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
     Current
Canada $ 102 $ 415 $ 548 $ 900
United States 11 163 396 647
Other Countries 5 2 43 7
-------------------------------------------------------------------------
Total Current Tax 118 580 987 1,554
-------------------------------------------------------------------------


     Future                           155        (344)      1,646        (316)
Future Tax Rate Reductions - (264) - (301)
-------------------------------------------------------------------------
$ 273 $ (28) $ 2,633 $ 937
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     Included in current tax for 2008 is $25 million related to the sale of
assets in Brazil (2007 - nil).
     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,
---------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
     Net Earnings Before
Income Tax $ 1,350 $ 979 $ 8,577 $ 4,821
Canadian Statutory Rate 29.7% 32.3% 29.7% 32.3%
-------------------------------------------------------------------------
Expected Income Tax 400 316 2,544 1,557
     Effect on Taxes Resulting
from:
Statutory and other
rate differences (30) 40 167 76
Effect of tax rate changes(x) - (264) - (301)
Effect of legislative changes - 52 - (179)
Non-taxable downstream
partnership (income) loss 16 (30) 6 (70)
International financing (76) (17) (309) (62)
Foreign exchange (gains)
losses not included in net
earnings (92) - 49 -
Non-taxable capital (gains)
losses 54 (80) 84 (124)
Other 1 (45) 92 40
-------------------------------------------------------------------------
$ 273 $ (28) $ 2,633 $ 937
-------------------------------------------------------------------------
Effective Tax Rate 20.2% (2.9%) 30.7% 19.4%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x)The Canadian federal government, during the second quarter of 2007,
enacted income tax rate changes.
     11. INVENTORIES
                                                            As at       As at
December December
31, 2008 31, 2007
-------------------------------------------------------------------------
     Product
Canada $ 46 $ 65
USA 8 2
Downstream Refining 323 570
Market Optimization 127 180
Parts and Supplies 16 11
-------------------------------------------------------------------------
$ 520 $ 828
-------------------------------------------------------------------------
-------------------------------------------------------------------------
As a result of a significant decline in commodity prices in the latter
half of 2008, EnCana has written down its product inventory by
$152 million from cost to net realizable value.
     The total amount of inventories recognized as an expense during the year,
including the write-down, was $8,749 million (2007 - $5,752 million).
     12. LONG-TERM DEBT
                                                            As at       As at
December December
31, 2008 31, 2007
-------------------------------------------------------------------------
     Canadian Dollar Denominated Debt
Revolving credit and term loan borrowings $ 1,410 $ 1,506
Unsecured notes 1,020 1,138
-------------------------------------------------------------------------
2,430 2,644
-------------------------------------------------------------------------
     U.S. Dollar Denominated Debt
Revolving credit and term loan borrowings 247 495
Unsecured notes 6,350 6,421
-------------------------------------------------------------------------
6,597 6,916
-------------------------------------------------------------------------
     Increase in Value of Debt Acquired(x)                     49          66
Debt Discounts and Financing Costs (71) (83)
Current Portion of Long-Term Debt (250) (703)
-------------------------------------------------------------------------
$ 8,755 $ 8,840
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x)Certain of the notes and debentures of EnCana were acquired in
business combinations and were accounted for at their fair value at
the dates of acquisition. The difference between the fair value and
the principal amount of the debt is being amortized over the
remaining life of the outstanding debt acquired, approximately
20 years.
     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.
     13. 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, 2008 31, 2007
-------------------------------------------------------------------------
     Asset Retirement Obligation, Beginning of Year     $   1,458   $   1,051
Liabilities Incurred 54 89
Liabilities Settled (115) (100)
Liabilities Divested (38) -
Change in Estimated Future Cash Flows 54 184
Accretion Expense 79 64
Foreign Currency Translation (227) 163
Other - 7
-------------------------------------------------------------------------
Asset Retirement Obligation, End of Year $ 1,265 $ 1,458
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     14. SHARE CAPITAL
                                    December 31, 2008       December 31, 2007
---------------------------------------------
(millions) Number Amount Number Amount
-------------------------------------------------------------------------
Common Shares Outstanding,
Beginning of Year 750.2 $ 4,479 777.9 $ 4,587
Common Shares Issued under
Option Plans 3.0 80 8.3 176
Stock-Based Compensation - 11 - 17
Common Shares Purchased (2.8) (13) (36.0) (301)
-------------------------------------------------------------------------
Common Shares Outstanding,
End of Year 750.4 $ 4,557 750.2 $ 4,479
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     Normal Course Issuer Bid
     EnCana has received regulatory approval each year under Canadian
securities laws to purchase Common Shares under seven consecutive Normal
Course Issuer Bids ("Bids"). EnCana is entitled to purchase, for
cancellation, up to approximately 75.0 million Common Shares under the
renewed Bid which commenced on November 13, 2008 and terminates on
November 12, 2009.
     In 2008, the Company purchased 4.8 million Common Shares for total
consideration of approximately $326 million. Of the amount paid, $29
million was charged to Share capital and $297 million was charged to
Retained earnings. Included in the Common Shares Purchased in 2008 are
2.0 million Common Shares distributed, valued at $16 million, from the
EnCana Employee Benefit Plan Trust that vested under EnCana's Performance
Share Unit Plan (See Note 16). For these Common Shares distributed, there
was a $54 million adjustment to Retained earnings with a reduction to
Paid in surplus of $70 million.
     In 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 16). For these Common Shares distributed, there
was an $82 million adjustment to Retained earnings with a reduction to
Paid in surplus of $106 million.
     Stock Options
     EnCana has stock-based compensation plans that allow employees to
purchase Common Shares of the Company. Option exercise prices approximate
the market price for the Common Shares on the date the options were
granted. Options granted under the plans are generally fully exercisable
after three years and expire five years after the date granted. Options
granted under predecessor and/or related company replacement plans expire
up to 10 years from the date the options were granted.
     The following tables summarize the information related to options to
purchase Common Shares that do not have Tandem Share Appreciation Rights
("TSARs") attached to them at December 31, 2008. Information related to
TSARs is included in Note 16.
                                                                    Weighted
Stock Average
Options Exercise
(millions) Price (C$)
-------------------------------------------------------------------------
Outstanding, Beginning of Year 3.4 21.82
Exercised (2.9) 23.68
-------------------------------------------------------------------------
Outstanding, End of Year 0.5 11.62
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Exercisable, End of Year 0.5 11.62
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Outstanding Options Exercisable Options
-----------------------------------------------------------
Weighted
Number of Average Weighted Number of Weighted
Options Remaining Average Options Average
Outstanding Contractual Exercise Outstanding Exercise
(millions) Life (years) Price (C$) (millions) Price (C$)
Range of Exercise
Price (C$)
-------------------------------------------------------------------------
11.00 to 14.50 0.5 0.9 11.62 0.5 11.62
-------------------------------------------------------------------------
-------------------------------------------------------------------------
At December 31, 2007, the balance in Paid in surplus related to
stock-based compensation programs.
     15. CAPITAL STRUCTURE
     The Company's capital structure is comprised of Shareholders' Equity plus
Long-Term Debt. The Company's objectives when managing its capital
structure are to:
         i)  maintain financial flexibility to preserve EnCana's access to
capital markets and its ability to meet its financial
obligations; and
ii) finance internally generated growth as well as potential
acquisitions.
     The Company monitors its capital structure and short-term financing
requirements using non-GAAP financial metrics consisting of Debt to
Capitalization and Debt to Adjusted Earnings Before Interest, Taxes,
Depreciation and Amortization ("EBITDA"). These metrics are used to
steward the Company's overall debt position as measures of the Company's
overall financial strength.
     To provide a more conservative measure of liquidity, the Company has
changed its calculation of these metrics as follows: Net Debt to
Capitalization has been changed to Debt to Capitalization and Net Debt to
Adjusted EBITDA has been changed to Debt to Adjusted EBITDA. Debt is
defined as the current and long-term portions of Long-Term Debt.
Previously, Net Debt was defined as Long-Term Debt plus Current
Liabilities less Current Assets. The Company believes this presentation
is more comparable between periods by excluding the impact of unrealized
mark-to-market accounting gains and losses on working capital.
     EnCana targets a Debt to Capitalization ratio of between 30 and 40
percent. At December 31, 2008, EnCana's Debt to Capitalization ratio was
28 percent (December 31, 2007 - 32 percent) calculated as follows:
                                                               As at
--------------------------
December 31, December 31,
2008 2007
-------------------------------------------------------------------------
Debt $ 9,005 $ 9,543
Total Shareholders' Equity 22,974 20,704
-------------------------------------------------------------------------
Total Capitalization $ 31,979 $ 30,247
-------------------------------------------------------------------------
Debt to Capitalization ratio 28% 32%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     Without giving effect to the change in calculation as described above,
EnCana's Net Debt to Capitalization ratio would have been 23 percent at
December 31, 2008 (December 31, 2007 - 34 percent).
     EnCana targets a Debt to Adjusted EBITDA of 1.0 to 2.0 times. At December
31, 2008, Debt to Adjusted EBITDA was 0.7x (December 31, 2007 - 1.1x)
calculated on a trailing twelve-month basis as follows:


                                                               As at
--------------------------
December 31, December 31,
2008 2007
-------------------------------------------------------------------------
Debt $ 9,005 $ 9,543
-------------------------------------------------------------------------
Net Earnings from Continuing Operations $ 5,944 $ 3,884
Add (deduct):
Interest, net 586 428
Income tax expense 2,633 937
Depreciation, depletion and amortization 4,223 3,816
Accretion of asset retirement obligation 79 64
Foreign exchange (gain) loss, net 423 (164)
(Gain) loss on divestitures (140) (65)
-------------------------------------------------------------------------
Adjusted EBITDA $ 13,748 $ 8,900
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Debt to Adjusted EBITDA 0.7x 1.1x
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     Without giving effect to the change in calculation as described above,
EnCana's Net Debt to Adjusted EBITDA would have been 0.5x at December 31,
2008 (December 31, 2007 - 1.2x).
     EnCana has a long-standing practice of maintaining capital discipline,
managing its capital structure and adjusting its capital structure
according to market conditions to maintain flexibility while achieving
the objectives stated above. To manage the capital structure, the Company
may adjust capital spending, adjust dividends paid to shareholders,
purchase shares for cancellation pursuant to normal course issuer bids,
issue new shares, issue new debt or repay existing debt.
     The Company's capital management objectives, evaluation measures,
definitions and targets have remained unchanged over the periods
presented, except as noted above. EnCana is subject to certain financial
covenants in its credit facility agreements and is in compliance with all
financial covenants.
     16. COMPENSATION PLANS


     The tables below outline certain information related to EnCana's
compensation plans at December 31, 2008. Additional information is
contained in Note 17 of the Company's annual audited Consolidated
Financial Statements for the year ended December 31, 2007.
     A)  Pensions
     The following table summarizes the net benefit plan expense:

                                   Three Months Ended     Twelve Months Ended
December 31, December 31,
---------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
     Current Service Cost           $   3       $   5       $  15       $  16
Interest Cost 5 5 21 19
Expected Return on Plan Assets (5) (5) (19) (19)
Amortization of Net Actuarial
Losses 1 1 4 4
Expected Amortization of Past
Service Costs 1 1 2 2
Amortization of Transitional
Obligation (1) (1) (2) (2)
Expense for Defined
Contribution Plan 14 9 44 34
-------------------------------------------------------------------------
Net Benefit Plan Expense $ 18 $ 15 $ 65 $ 54
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     For the year ended December 31, 2008, contributions of $8 million have
been made to the defined benefit pension plans (2007 - $8 million).
     B)  Tandem Share Appreciation Rights ("TSARs")
     The following table summarizes the information related to the TSARs at
December 31, 2008:



Weighted
Outstanding Average
TSARs Exercise Price
-------------------------------------------------------------------------
     Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 18,854,141 48.44
Granted 4,420,272 70.11
Exercised - SARs (3,173,443) 43.68
Exercised - Options (82,936) 42.00
Forfeited (606,095) 55.27
-------------------------------------------------------------------------
Outstanding, End of Year 19,411,939 53.97
-------------------------------------------------------------------------
Exercisable, End of Year 8,452,111 46.45
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     For the year ended December 31, 2008, EnCana recorded a reduction of
compensation costs of $47 million related to the outstanding TSARs (2007
- costs of $225 million).
     C) Performance Tandem Share Appreciation Rights ("Performance TSARs")
     The following table summarizes the information related to the Performance
TSARs at December 31, 2008:
                                                                     Weighted
Average
Outstanding Exercise
TSARs Price
-------------------------------------------------------------------------
     Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 6,930,925 56.09
Granted 7,058,538 69.40
Exercised - SARs (287,299) 56.09
Exercised - Options (5,123) 56.09
Forfeited (717,316) 59.65
-------------------------------------------------------------------------
Outstanding, End of Year 12,979,725 63.13
-------------------------------------------------------------------------
Exercisable, End of Year 1,461,276 56.09
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     For the year ended December 31, 2008, EnCana recorded a reduction of
compensation costs of $6 million related to the outstanding Performance
TSARs (2007 - costs of $21 million).
     D) Share Appreciation Rights ("SARs")
     In 2008, EnCana granted SARs to certain employees which entitles the
employee to receive a cash payment equal to the excess of the market
price of EnCana's Common Shares at the time of exercise over the grant
price. SARs are exercisable at 30 percent of the number granted after
one year, an additional 30 percent of the number granted after two years
and are fully exercisable after three years and expire five years after
the grant date.
     The following table summarizes the information related
to the SARs at December 31, 2008:
                                                                     Weighted
Average
Outstanding Exercise
SARs Price
-------------------------------------------------------------------------
     Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year - -
Granted 1,314,115 72.07
Forfeited (29,050) 69.42
-------------------------------------------------------------------------
Outstanding, End of Year 1,285,065 72.13
-------------------------------------------------------------------------
Exercisable, End of Year - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     For the year ended December 31, 2008, EnCana has not recorded any
compensation costs related to the outstanding SARs.

E) Performance Share Appreciation Rights ("Performance SARs")
     In 2008, EnCana granted Performance SARs to certain employees which
entitles the employee to receive a cash payment equal to the excess of
the market price of EnCana's Common Shares at the time of exercise over
the grant price. Performance SARs vest and expire under the same terms
and service conditions as SARs and are also subject to EnCana attaining
prescribed performance relative to pre-determined key measures.
Performance SARs that do not vest when eligible are forfeited.
     The following table summarizes the information related to the Performance
SARs at December 31, 2008:
                                                                     Weighted
Average
Outstanding Exercise
SARs Price
-------------------------------------------------------------------------
     Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year - -
Granted 1,677,030 69.40
Forfeited (56,100) 69.40
-------------------------------------------------------------------------
Outstanding, End of Year 1,620,930 69.40
-------------------------------------------------------------------------
Exercisable, End of Year - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     For the year ended December 31, 2008, EnCana has not recorded any
compensation costs related to the outstanding Performance SARs.
     F) Deferred Share Units ("DSUs")
     The following table summarizes the information related to the DSUs at
December 31, 2008:


                                                                  Outstanding
DSUs
-------------------------------------------------------------------------
     Canadian Dollar Denominated
Outstanding, Beginning of Year 589,174
Granted 85,792
Redeemed (34,008)
Units, in Lieu of Dividends 15,883
-------------------------------------------------------------------------
Outstanding, End of Year 656,841
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     For the year ended December 31, 2008, EnCana recorded compensation costs
of $2 million related to the outstanding DSUs (2007 - $14 million).
     G) Performance Share Units ("PSUs")
     The following table summarizes the information related to the PSUs at
December 31, 2008:
Average
Outstanding Share
PSUs Price
-------------------------------------------------------------------------
     Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 1,685,036 38.79
Granted 408,686 70.77
Distributed (2,042,541) 45.34
Forfeited (51,181) 38.32
-------------------------------------------------------------------------
Outstanding, End of Year - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     For the year ended December 31, 2008, EnCana recorded compensation costs
of $1 million related to the outstanding PSUs (2007 - $43 million).
     17. PER SHARE AMOUNTS
     The following table summarizes the Common Shares used in calculating Net
Earnings per Common Share:


                                                     Three Months Ended
-----------------------------------
March June September
31, 30, 30,
-----------------------------------
(millions) 2008 2008 2008
-------------------------------------------------------------------------
     Weighted Average Common Shares
Outstanding - Basic 749.5 750.2 750.3
Effect of Dilutive Securities 3.5 1.1 1.0
-------------------------------------------------------------------------
Weighted Average Common Shares
Outstanding - Diluted 753.0 751.3 751.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Three Months Ended Twelve Months Ended
---------------------------------------------
December 31, December 31,
---------------------------------------------
(millions) 2008 2007 2008 2007
-------------------------------------------------------------------------
Weighted Average Common Shares
Outstanding - Basic 750.3 749.8 750.1 756.8
Effect of Dilutive Securities 1.0 5.3 1.7 7.8
-------------------------------------------------------------------------
Weighted Average Common Shares
Outstanding - Diluted 751.3 755.1 751.8 764.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------

18. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
     EnCana's financial assets and liabilities are comprised of cash and cash
equivalents, accounts receivable and accrued revenues, accounts payable
and accrued liabilities, the partnership contribution receivable and
payable, risk management assets and liabilities, and long-term debt.
Risk management assets and liabilities arise from the use of derivative
financial instruments. Fair values of financial assets and liabilities,
summarized information related to risk management positions, and
discussion of risks associated with financial assets and liabilities are
presented as follows.
     A) Fair Value of Financial Assets and Liabilities
     The fair values of cash and cash equivalents, accounts receivable and
accrued revenues, and accounts payable and accrued liabilities
approximate their carrying amount due to the short-term maturity of those
instruments.
     The fair values of the partnership contribution receivable and
partnership contribution payable approximate their carrying amount due to
the specific nature of these instruments in relation to the creation of
the integrated oil joint venture. Further information about these notes
is disclosed in Note 10 to the Company's annual audited Consolidated
Financial Statements for the year ended December 31, 2007.
     Risk management assets and liabilities are recorded at their estimated
fair value based on the mark-to-market method of accounting, using quoted
market prices or, in their absence, third-party market indications and
forecasts.
     Long-term debt is carried at amortized cost using the effective interest
method of amortization. The estimated fair values of long-term
borrowings have been determined based on market information where
available, or by discounting future payments of interest and principal at
estimated interest rates expected to be available to the Company at
period end.
     The fair value of financial assets and liabilities were as follows:
                                                  As at                 As at
December 31, 2008 December 31, 2007
-------------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------------------------------------------------------------------------
Financial Assets
Held-for-Trading:
Cash and cash equivalents $ 383 $ 383 $ 553 $ 553
Risk management assets(x) 3,052 3,052 403 403
Loans and Receivables:
Accounts receivable and
accrued revenues 1,568 1,568 2,381 2,381
Partnership contribution
receivable(x) 3,147 3,147 3,444 3,444
Financial Liabilities
Held-for-Trading:
Risk management
liabilities(x) $ 50 $ 50 $ 236 $ 236
Other Financial Liabilities:
Accounts payable and
accrued liabilities 2,871 2,871 3,982 3,982
Long-term debt(x) 9,005 8,242 9,543 9,763
Partnership contribution
payable(x) 3,163 3,163 3,451 3,451
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x) Including current portion.

B) Risk Management Assets and Liabilities
     Net Risk Management Position                           As at       As at
December December
31, 31,
2008 2007
-------------------------------------------------------------------------


     Risk Management
Current asset $ 2,818 $ 385
Long-term asset 234 18
-------------------------------------------------------------------------
3,052 403
-------------------------------------------------------------------------
     Risk Management
Current liability 43 207
Long-term liability 7 29
-------------------------------------------------------------------------
50 236
-------------------------------------------------------------------------
Net Risk Management Asset (Liability) $ 3,002 $ 167
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Summary of Unrealized Risk Management Positions
                           As at December 31, 2008    As at December 31, 2007
-----------------------------------------------------
Risk Management Risk Management
-----------------------------------------------------
Asset Liability Net Asset Liability Net
-------------------------------------------------------------------------
     Commodity Prices
Natural gas $2,941 $ 10 $2,931 $ 375 $ 29 $ 346
Crude oil 92 40 52 6 205 (199)
Power 19 - 19 19 - 19
Interest Rates - - - 2 - 2
Credit - - - 1 2 (1)
-------------------------------------------------------------------------
Total Fair Value $3,052 $ 50 $3,002 $ 403 $ 236 $ 167
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Net Fair Value Methodologies Used to Calculate Unrealized Risk Management
Positions
                                                            As at       As at
December December
31, 31,
2008 2007
-------------------------------------------------------------------------
     Prices actively quoted                                $2,055      $  105
Prices sourced from observable data or market
corroboration 947 62
-------------------------------------------------------------------------
Total Fair Value $3,002 $ 167
-------------------------------------------------------------------------
-------------------------------------------------------------------------


     Prices actively quoted refers to the fair value of contracts valued using
quoted prices in an active market. Prices sourced from observable data or
market corroboration refers to the fair value of contracts valued in part
using active quotes and in part using observable, market-corroborated
data.
     Net Fair Value of Commodity Price Positions at December 31, 2008
                                   Notional                              Fair
Volumes Term Average Price Value
-------------------------------------------------------------------------
     Natural Gas Contracts
Fixed Price Contracts
       NYMEX Fixed Price       1,648 MMcf/d    2009    9.28 US$/Mcf    $1,981
NYMEX Fixed Price 35 MMcf/d 2010 9.21 US$/Mcf 23
     Purchased Options


       NYMEX Call              (150) MMcf/d    2009   11.67 US$/Mcf       (22)
NYMEX Put 516 MMcf/d 2009 9.10 US$/Mcf 536
     Basis Contracts
       Canada                     71 MMcf/d    2009                         -
United States 917 MMcf/d 2009 111
Canada and
United States(x) 2010-2013 193
-------------------------------------------------------------------------
2,822
Other Financial Positions(xx) (1)
-------------------------------------------------------------------------
Total Unrealized Gain
on Financial Contracts 2,821
Premiums Paid on
Unexpired Options 110
-------------------------------------------------------------------------
Natural Gas Fair
Value Position $2,931
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x) EnCana has entered into swaps to protect against widening natural
gas price differentials between production areas, including Canada,
the U.S. Rockies and Texas, and various sales points. These basis
swaps are priced using both fixed prices and basis prices determined
as a percentage of NYMEX.
(xx) Other financial positions are part of the ongoing operations of the
Company's proprietary production management.
                                                                   Fair Value
-------------------------------------------------------------------------
Crude Oil Contracts
Crude Oil Fair Value Position(x) $ 52
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     (x)The Crude Oil financial positions are part of the ongoing operations
of the Company's proprietary production and condensate management and
its share of downstream refining positions.
                                                                   Fair Value
-------------------------------------------------------------------------
Power Purchase Contracts
Power Fair Value Position $ 19
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     Net Earnings Impact of Realized and Unrealized Gains (Losses) on Risk
Management Positions
                                               Realized Gain (Loss)
-------------------------------------------
Three Months Ended Twelve Months Ended
December 31, December 31,
-------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of Royalties $ 646 $ 408 $ (309) $ 1,601
Operating Expenses and Other 30 (1) 28 3
-------------------------------------------------------------------------
Gain (Loss) on Risk
Management $ 676 $ 407 $ (281) $ 1,604
-------------------------------------------------------------------------
-------------------------------------------------------------------------
                                               Unrealized Gain (Loss)
-------------------------------------------
Three Months Ended Twelve Months Ended
December 31, December 31,
-------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of Royalties $ 1,084 $ (566) $ 2,717 $ (1,239)
Operating Expenses and Other 6 (3) 12 4
-------------------------------------------------------------------------
Gain (Loss) on Risk
Management $ 1,090 $ (569) $ 2,729 $ (1,235)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     Reconciliation of Unrealized Risk Management Positions from January 1 to
December 31, 2008
                                                        2008             2007
--------------------------------
Total Total
Unrealized Unrealized
Fair Gain Gain
Value (Loss) (Loss)
-------------------------------------------------------------------------
Fair Value of Contracts, Beginning
of Year $ 167
Change in Fair Value of Contracts in
Place at Beginning of Year and Contracts
Entered into During the Year 2,448 $ 2,448 $ 353
Fair Value of Contracts in Place at
Transition that Expired During the Year - - 16
Foreign Exchange Loss on Canadian
Dollar Contracts (4) - -
Fair Value of Contracts Realized During
the Year 281 281 (1,604)
-------------------------------------------------------------------------
Fair Value of Contracts Outstanding $ 2,892 $ 2,729 $ (1,235)
Premiums Paid on Unexpired Options 110
-------------------------------------------------------------------------
Fair Value of Contracts and Premiums
Paid, End of Year $ 3,002
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     Commodity Price Sensitivities
     The following table summarizes the sensitivity of the fair value of the
Company's risk management positions to fluctuations in commodity prices,
with all other variables held constant. When assessing the potential
impact of these commodity price changes, the Company believes 10%
volatility is a reasonable measure. Fluctuations in commodity prices
could have resulted in unrealized gains (losses) impacting net earnings
as at December 31, 2008 as follows:
                                                      Favorable    Unfavorable
10% Change 10% Change
-------------------------------------------------------------------------
Natural gas price $ 424 $ (418)
Crude oil price 7 (7)
Power price 9 (9)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     C) Risks Associated with Financial Assets and Liabilities
     The Company is exposed to financial risks arising from its financial
assets and liabilities. Financial risks include market risks (such as
commodity prices, foreign exchange and interest rates), credit risk and
liquidity risk. The fair value or future cash flows of financial assets
or liabilities may fluctuate due to movement in market prices and the
exposure to credit and liquidity risks.
     Commodity Price Risk
     Commodity price risk arises from the effect that fluctuations of future
commodity prices may have on the fair value or future cash flows of
financial assets and liabilities. To partially mitigate exposure to
commodity price risk, the Company has entered into various financial
derivative instruments. The use of these derivative instruments is
governed under formal policies and is subject to limits established by
the Board of Directors. The Company's policy is to not use derivative
financial instruments for speculative purposes.
     Natural Gas - To partially mitigate the natural gas commodity price risk,
the Company has entered into option contracts and swaps, which fix the
NYMEX prices. To help protect against widening natural gas price
differentials in various production areas, EnCana has entered into swaps
to manage the price differentials between these production areas and
various sales points.
     Crude Oil - The Company has partially mitigated its exposure to commodity
price risk on its condensate supply with fixed price swaps.
     Power - The Company has in place two Canadian dollar denominated
derivative contracts, which commenced January 1, 2007 for a period of 11
years, to manage its electricity consumption costs.
     Credit Risk
     Credit risk arises from the potential the Company may incur a loss if a
counterparty to a financial instrument fails to meet its obligation in
accordance with agreed terms. This credit risk exposure is mitigated
through the use of Board-approved credit policies governing the Company's
credit portfolio and with credit practices that limit transactions
according to counterparties' credit quality. All foreign currency
agreements are with major financial institutions in Canada and the United
States or with counterparties having investment grade credit ratings. A
substantial portion of the Company's accounts receivable are with
customers in the oil and gas industry and are subject to normal industry
credit risks. As at December 31, 2008, over 95% of EnCana's accounts
receivable and financial derivative credit exposures are with investment
grade counterparties.
     At December 31, 2008, EnCana had 2 counterparties whose net settlement
position individually account for more than 10 percent of the fair value
of the outstanding in-the-money net financial instrument contracts by
counterparty. The maximum credit risk exposure associated with accounts
receivable and accrued revenues, risk management assets and the
partnership contribution receivable is the total carrying value.
     Liquidity Risk

     Liquidity risk is the risk the Company will encounter difficulties in
meeting a demand to fund its financial liabilities as they come due. The
Company manages its liquidity risk through cash and debt management. As
disclosed in Note 15, EnCana targets a Debt to Capitalization ratio
between 30 and 40 percent and a Debt to Adjusted EBITDA of 1.0 to 2.0
times to steward the Company's overall debt position.
     In managing liquidity risk, the Company has access to a wide range of
funding at competitive rates through commercial paper, capital markets
and banks. As at December 31, 2008, EnCana had available unused committed
bank credit facilities in the amount of $2.6 billion and unused capacity
under shelf prospectuses, the availability of which is dependent on
market conditions, for $5.0 billion. The Company believes it has
sufficient funding through the use of these facilities to meet
foreseeable borrowing requirements.
     EnCana maintains investment grade credit ratings on its senior unsecured
debt. On May 12, 2008, following the announcement of the proposed
Arrangement (See Note 4), Standard & Poor's Ratings Service assigned a
rating of A- and placed the Company on "CreditWatch Negative", DBRS
Limited assigned a rating of A(low) and placed the Company "Under Review
with Developing Implications", and Moody's Investors Service assigned a
rating of Baa2 and changed the outlook to "Stable" from "Positive".
     The timing of cash outflows relating to financial liabilities are
outlined in the table below:
                        Less Than      1 - 3      4 - 5
1 Year Years Years Thereafter Total
-------------------------------------------------------------------------
     Accounts Payable
and Accrued
Liabilities $ 2,871 $ - $ - $ - $ 2,871
Risk Management
Liabilities 43 7 - - 50
Long-Term Debt(x) 727 1,589 3,344 10,392 16,052
Partnership
Contribution
Payable(x) 489 978 978 1,588 4,033
-------------------------------------------------------------------------
-------------------------------------------------------------------------
     (x)Principal and interest, including current portion.
     Included in EnCana's total long-term debt obligations of $16,052 million
at December 31, 2008 are $1,657 million in principal obligations related
to Bankers' Acceptances, Commercial Paper and LIBOR loans. These amounts
are fully supported and Management expects that they will continue to be
supported by revolving credit and term loan facilities that have no
repayment requirements within the next year. The revolving credit and
term loan facilities are fully revolving for a period of up to five
years. Based on the current maturity dates of the credit facilities,
these amounts are included in cash outflows for the period disclosed as
4 - 5 Years. Further information on Long-term Debt is contained in
Note 12.
     Foreign Exchange Risk
     Foreign exchange risk arises from changes in foreign exchange rates that
may affect the fair value or future cash flows of the Company's financial
assets or liabilities. As EnCana operates primarily in North America,
fluctuations in the exchange rate between the U.S./Canadian dollar can
have a significant effect on the Company's reported results. EnCana's
functional currency is Canadian dollars, however, the Company reports its
results in U.S. dollars as most of its revenue is closely tied to the
U.S. dollar and to facilitate a more direct comparison to other North
American oil and gas companies. As the effects of foreign exchange
fluctuations are embedded in the Company's results, the total effect of
foreign exchange fluctuations are not separately identifiable.
     To mitigate the exposure to the fluctuating U.S./Canadian exchange rate,
EnCana maintains a mix of both U.S. dollar and Canadian dollar debt.
     As disclosed in Note 9, EnCana's foreign exchange (gain) loss is
primarily comprised of unrealized foreign exchange gains and losses on
the translation of U.S. dollar debt issued from Canada and the
translation of the U.S. dollar partnership contribution receivable issued
from Canada. At December 31, 2008, EnCana had $5,350 million in U.S.
dollar debt issued from Canada ($5,421 million at December 31, 2007) and
$3,147 million related to the U.S. dollar partnership contribution
receivable ($3,444 million at December 31, 2007). A $0.01 change in the
U.S. to Canadian dollar exchange rate would have resulted in an
$18 million change in foreign exchange (gain) loss at December 31, 2008.
     Interest Rate Risk
     Interest rate risk arises from changes in market interest rates that may
affect the fair value or future cash flows from the Company's financial
assets or liabilities. The Company partially mitigates its exposure to
interest rate changes by maintaining a mix of both fixed and floating
rate debt.


     At December 31, 2008, the increase or decrease in net earnings for each
one percent change in interest rates on floating rate debt amounts to
$12 million (2007 - $14 million).
     19. 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.
Also, without admitting any liability whatsoever, WD concluded
settlements with a group of individual plaintiffs for $23 million.
     The remaining lawsuit was commenced by E. & J. Gallo Winery ("Gallo").
The Gallo lawsuit claims damages in excess of $30 million. California law
allows for the possibility that the amount of damages assessed could be
tripled.
     The Company and WD intend to vigorously defend against this outstanding
claim; 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.
     20. RECLASSIFICATION
     Certain information provided for prior periods has been reclassified to
conform to the presentation adopted in 2008.
>>

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

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

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

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

ECA stock price

TSX $14.27 Can 0

NYSE $11.11 USD 0

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