EnCana generates first quarter cash flow of US$1.8 billion, or $2.25 per share - up 15 percent

CALGARY, April 25, 2007 /CNW/ - EnCana Corporation's (TSX & NYSE: ECA) first
quarter 2007 cash flow per share diluted increased 15 percent to US$2.25, or
about $1.8 billion, compared to the first quarter of 2006. Operating earnings
per share increased 38 percent to $1.10, or $858 million. Strong growth in
cash flow and operating earnings were due to higher natural gas production,
improved heavy oil differentials, strong refinery margins and gains from
EnCana's hedging program, which more than offset significantly lower benchmark
WTI oil and NYMEX natural gas prices.
"Our first quarter results illustrate, for the first time, the recently
completed transformation of EnCana into its unique position as an integrated
North American resource play company focused on developing unconventional
natural gas and in-situ oilsands. We have assembled a portfolio of high-
quality assets and an extensive land base where our company can apply its
expertise in unconventional resource development to deliver sustainable
results and returns for our shareholders. Cash flow and gas production are on
track with our 2007 forecasts while production from our integrated oilsands
business is ramping up," said Randy Eresman, President & Chief Executive
Officer.
One year ago, EnCana's 100 percent interest in Foster Creek and Christina
Lake in-situ oilsands projects generated less than 1 percent of the company's
total operating cash flow. In the first quarter of this year, EnCana's
integrated oilsands business, which are composed of a 50 percent interest in
each of Foster Creek, Christina Lake, and the refineries at Borger and Wood
River, generated $161 million, or more than 9 percent of total operating cash
flow. This increased significance to EnCana's financial performance is a
result of steady production growth and the addition of the company's
participation in the refining business.
First Quarter 2007 Highlights
-----------------------------
(all year-over-year comparisons are to the first quarter of 2006)
Financial
- Cash flow per share diluted increased 15 percent to $2.25, or
$1.8 billion
- Operating earnings per share diluted up 38 percent to $1.10, or
$858 million
- Net earnings of 64 cents per share, or $497 million, were negatively
impacted by a $423 million unrealized after-tax loss due to
mark-to-market accounting of commodity price hedges
- Generated $269 million in free cash flow (as defined in Note 1 on
page 7)
- Achieved a return on capital employed of 21 percent
- Purchased 23.3 million EnCana shares at an average share price of
$46.90 under the Normal Course Issuer Bid, representing 3 percent of
shares outstanding at December 31, 2006
- In February, EnCana doubled its quarterly dividend to 20 cents per
share, representing an annual yield of approximately 1.5 percent at
April 24, 2007
Operating (after establishing integrated oilsands business)
- Natural gas production of 3.4 billion cubic feet per day (Bcf/d),
slightly ahead of budget and in line with guidance
- Oil and NGLs production of 131,000 bbls/d, which is marginally behind
budget, primarily due to a slower than expected ramp up of production
at EnCana's oilsands projects. Consequently, full-year liquids
production guidance has been adjusted and posted on the company's
website at www.encana.com.
- Operating and administrative costs of $1.20 per thousand cubic feet
equivalent (Mcfe), in line with budget and guidance
- Core capital investment in continuing operations of $1.48 billion,
which is tracking below budget and guidance due to fewer wells
drilled than planned and lower than expected costs
Strategic events
- Created an integrated oilsands business with ConocoPhillips composed
of two 50/50 businesses - one upstream and one downstream - which
became effective January 2, 2007
- Completed sale of Chad assets for about $203 million, resulting in a
$59 million gain
Natural gas production on track with 2007 forecast, capital inflation
lower
"Natural gas production rose steadily in the first quarter due to strong
additions in coalbed methane (CBM), Bighorn, Jonah, Cutbank Ridge and East
Texas. Current gas production is about 3.48 billion cubic feet per day -
slightly ahead of our 2007 budget and solidly positioning us to achieve our
full-year guidance of 3.46 Bcf/d. Our 2007 capital program is also on track to
meet guidance. We are starting to see capital inflation lower than forecast in
some areas," Eresman said.
Integrated oilsands business generating strong cash flow, upstream
production up 11 percent in past year
EnCana's new integrated oilsands business generated first quarter
operating cash flow of $161 million, on track with the company's full-year
operating cash flow guidance of between $550 million and $650 million. In the
downstream business, the first quarter U.S. Gulf Coast 3-2-1 crack spread of
more than $10 per barrel is up 21 percent in the past year, and compares
favourably to a long-term average of between $5 to $6 per barrel. At the
Borger refinery in Texas, the addition of 20,000 barrels per day of upgrading
capacity is on schedule for completion this summer. In the upstream business,
first quarter total production from the Foster Creek and Christina Lake in-
situ oilsands projects increased about 11 percent in the past year, to about
46,500 bbls/d (about 23,250 bbls/d net to EnCana). The ramp up of production
has been slower than expected due to operational upsets in the water treatment
facilities at Foster Creek and a delayed start up of two wells at Christina
Lake. However, these impediments have been resolved and upstream production is
ramping up from both Foster Creek and Christina Lake with current levels of
about 55,000 bbls/d (about 27,500 bbls/d net to EnCana).
IMPORTANT NOTE:
---------------
EnCana reports in U.S. dollars unless otherwise noted and follows U.S.
protocols, which report production, sales and reserves on an after-royalties
basis. The company has reported its Ecuador operations and its natural gas
storage business as discontinued because EnCana sold them in 2006. Total
results, which include results from Ecuador and natural gas storage, are
reported in the company's financial statements included in this news release
and in supplementary documents posted on its website - www.encana.com. The
company's financial statements are prepared in accordance with Canadian
generally accepted accounting principles (GAAP).
<<
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Financial Summary - Total Consolidated
-------------------------------------------------------------------------
(for the three months ended March 31)
($ millions, except per share amounts) Q1 Q1 %
2007 2006 Change
-------------------------------------------------------------------------
Cash flow 1,752 1,691 + 4
Per share diluted 2.25 1.96 + 15
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Net earnings 497 1,474 n/a
Per share diluted 0.64 1.70 n/a
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Operating earnings(1) 858 694 + 24
Per share diluted 1.10 0.80 + 38
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Core capital investment from continuing
operations 1,483 1,946 - 24
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Earnings Reconciliation Summary - Total Consolidated
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net earnings from continuing operations 497 1,472 n/a
Net earnings from discontinued operations - 2 n/a
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-------------------------------------------------------------------------
Net earnings (loss) 497 1,474
(Add back losses & deduct gains)
Unrealized mark-to-market hedging gain (loss),
after-tax (423) 830
Unrealized foreign exchange gain (loss) on
translation of U.S. dollar Notes issued
from Canada, after-tax 3 (3)
Gain (loss) on discontinuance 59 (47)
-------------------------------------------------------------------------
Operating earnings(1) 858 694 + 24
Per share diluted 1.10 0.80 + 38
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-------------------------------------------------------------------------
(1) Operating earnings is a non-GAAP measure that shows net earnings
excluding non-operating items such as the after-tax impacts of the gain
on discontinuance, the after-tax gain/loss on unrealized mark-to-market
accounting for derivative instruments, the after-tax gain/loss on
translation of U.S. dollar denominated Notes issued from Canada and the
effect of the reduction in income tax rates.

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Production & Drilling Summary
-------------------------------------------------------------------------
Total Consolidated
-------------------------------------------------------------------------
(for the three months ended March 31) Q1 Q1 %
(After royalties) 2007 2006(1) Change
-------------------------------------------------------------------------
Natural Gas (MMcf/d) 3,400 3,343 + 2
-------------------------------------------------------------------------
Natural gas production per 1,000 shares
(Mcf) 398 355 + 12
-------------------------------------------------------------------------
Oil and NGLs (Mbbls/d) 131 194 - 32
-------------------------------------------------------------------------
Oil and NGLs production per 1,000 shares
(Mcfe) 92 123 - 25
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total Production (MMcfe/d) 4,184 4,505 - 7
-------------------------------------------------------------------------
Total per 1,000 shares (Mcfe) 490 478 + 3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net wells drilled 1,264 1,285 - 2
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(1) First quarter 2006 information has been adjusted on a pro forma basis
to reflect the integrated oilsands transaction and includes Ecuador
production, which was sold in the first quarter 2006.

Key resource play natural gas production up 9 percent in first quarter
First quarter 2007 natural gas production from key North American
resource plays increased 9 percent compared to the first quarter of 2006. This
was driven mainly by increases in gas production from Cutbank Ridge in
northeast British Columbia, Bighorn in west central Alberta, CBM in central
and southern Alberta, the Barnett Shale play in the Fort Worth basin and Jonah
in Wyoming.
Growth from key North American resource plays
-------------------------------------------------------------------------
Daily Production
-------------------------------------------------
Resource Play 2007 2006 2005
-------------------------------------------------
(After royalties) Full Full
Q1 Year Q4 Q3 Q2 Q1 Year
-------------------------------------------------------------------------
Natural Gas (MMcf/d)
Jonah 504 464 487 455 450 461 435
Piceance 334 326 335 331 324 316 307
East Texas 103 99 95 106 93 99 90
Fort Worth 106 101 99 104 108 93 70
Greater Sierra 186 213 212 209 224 208 219
Cutbank Ridge 210 170 199 167 173 140 92
Bighorn 104 91 99 97 95 72 55
CBM 251 194 211 209 179 177 112
Shallow Gas(1) 735 739 737 734 730 756 765
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total natural gas
(MMcf/d) 2,533 2,397 2,474 2,412 2,376 2,322 2,145
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Oil (Mbbls/d)
Foster Creek(2) 20 18 21 19 16 18 14
Christina Lake(2) 3 3 3 3 3 3 3
Pelican Lake 23 24 20 23 22 29 26
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Total oil (Mbbls/d) 46 45 44 45 41 50 43
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total (MMcfe/d) 2,811 2,667 2,736 2,680 2,624 2,624 2,403
-------------------------------------------------------------------------
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% change from Q1 2006 7.1
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% change from prior
period 5.4 11.0 2.1 2.1 - - 2.9
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(1) Shallow Gas volumes and net wells drilled have been restated to
report commingled volumes from multiple zones within the same geographic
area based upon regulatory approval.
(2) Foster Creek and Christina Lake production volumes in 2006 and 2005
have been restated on a pro forma basis to reflect the integrated
oilsands transaction.

Drilling activity in key North American resource plays
-------------------------------------------------------------------------
Net Wells Drilled
-------------------------------------------------
Resource Play 2007 2006 2005
-------------------------------------------------
Full Full
Q1 year Q4 Q3 Q2 Q1 Year
-------------------------------------------------------------------------
Natural Gas
Jonah 39 163 41 48 48 26 104
Piceance 65 220 50 48 59 63 266
East Texas 7 59 11 12 17 19 84
Fort Worth 14 97 19 22 27 29 59
Greater Sierra 23 115 5 16 34 60 164
Cutbank Ridge 27 116 19 35 36 26 135
Bighorn 28 52 7 7 18 20 51
CBM 408 729 157 156 35 381 1,245
Shallow Gas(1) 416 1,310 389 475 217 229 1,389
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Oil
Foster Creek(2) 8 3 - - - 3 20
Christina Lake(2) - 1 - - - 1 -
Pelican Lake - - - - - - 52
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total 1,035 2,865 698 819 491 857 3,568
-------------------------------------------------------------------------
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(1) Shallow Gas volumes and net wells drilled have been restated to
report commingled volumes from multiple zones within the same geographic
area based upon regulatory approval.
(2) Foster Creek and Christina Lake net wells in 2006 and 2005 have been
restated on a pro forma basis to reflect the integrated oilsands
transaction.

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First quarter 2007 natural gas and oil prices
-------------------------------------------------------------------------
Natural gas Q1 Q1 %
($/Mcf, realized prices include hedging) 2007 2006 Change
-------------------------------------------------------------------------
NYMEX 6.77 8.98 - 25
EnCana Realized Gas Price 7.24 7.15 + 1
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Oil and NGLs
($/bbl, realized prices include hedging)
-------------------------------------------------------------------------
WTI 58.23 63.48 - 8
Western Canadian Select (WCS) 41.77 34.72 + 20
Differential WTI/WCS 16.46 28.76 - 43
EnCana Realized Liquids Price 42.59 30.75 + 39
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U.S. Gulf Coast 3-2-1 Crack Spread 10.06 8.28 + 21
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Price risk management
Detailed risk management positions at March 31, 2007 are presented in
Note 18 to the unaudited Interim Consolidated Financial Statements. In the
first quarter of 2007, EnCana's commodity price risk management measures
resulted in realized gains of approximately $208 million after-tax, composed
of a $187 million gain on gas hedges, a $20 million gain on oil hedges and a
$1 million gain on other hedges.
More than 50 percent of expected natural gas and liquids production
during the last nine months of 2007 has downside price protection
For the last nine months of 2007, EnCana has about 1.77 Bcf/d of expected
gas production with downside price protection, composed of 1.53 Bcf/d under
fixed price contracts at an average NYMEX equivalent price of $8.47 per Mcf
and 240 million cubic feet per day with put options at a NYMEX equivalent
strike price of $6.00 per Mcf. EnCana also has about 126,000 bbls/d of
expected 2007 oil production with downside price protection, composed of
34,500 bbls/d under fixed price contracts at an average West Texas
Intermediate (WTI) price of $64.40 per bbl, plus put options on 91,500 bbls/d
at an average strike price of WTI $55.34 per bbl. This price hedging strategy
helps reduce uncertainty in cash flow during periods of commodity price
volatility.
North American natural gas prices are impacted by volatile pricing
disconnects caused primarily by transportation constraints between producing
regions and consuming regions. These price discounts are called basis
differentials. For 2007 EnCana has hedged 100 percent of its U.S. Rockies
basis exposure using a combination of downstream transportation and basis
hedges at NYMEX less $0.67 per Mcf. During the first quarter of 2007 the U.S.
Rockies-NYMEX natural gas price differential averaged NYMEX less $1.23 per
Mcf. In Canada for 2007, EnCana has hedged 33 percent of its AECO basis
differential at NYMEX less $0.72 per Mcf and has an additional 33 percent
subject to transport and aggregator contracts. In the first quarter of 2007,
the AECO basis differential averaged NYMEX less $0.40 per Mcf. During the
first quarter, EnCana's basis hedging resulted in a gain of about $38 million.
Corporate developments
----------------------
Quarterly dividend increased 100 percent to 20 cents per share
In February, EnCana doubled its first quarter 2007 dividend to 20 cents
per share. On April 24, EnCana's board of directors declared a quarterly
dividend of 20 cents per share, which is payable on June 29, 2007 to common
shareholders of record as of June 15, 2007.
EnCana Normal Course Issuer Bid purchases
In the first quarter of 2007. EnCana purchased 23.3 million EnCana shares
at an average share price of US$46.90 under the company's Normal Course Issuer
Bid. This represents about 3 percent of shares outstanding as at December 31,
2006. As at March 31, 2007, there were approximately 761 million common shares
issued and outstanding in total. During 2007, EnCana expects to purchase about
5 percent of the shares outstanding. The company plans to fund Normal Course
Issuer Bid purchases with cash flow and proceeds from divestitures.
Financial strength
------------------
EnCana maintains a strong balance sheet, targeting a net debt-to-
capitalization ratio between 30 and 40 percent. At March 31, 2007, the
company's net debt-to-capitalization ratio was 31:69. EnCana's net debt-to-
adjusted-EBITDA multiple, on a trailing 12-month basis, was 0.9 times at the
end of the first quarter. The company expects its net debt-to-capitalization
ratio to remain at the lower end of the targeted range.
In the first quarter of 2007, EnCana invested $1,483 million of capital
in continuing operations. Net divestitures were $274 million, resulting in net
capital investment in continuing operations of $1,209 million.
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CONFERENCE CALL TODAY
10 a.m. Mountain Time (Noon Eastern Time)
EnCana Corporation will host a conference call today, Wednesday April 25,
2007 starting at 10:00 a.m. MT (12:00 p.m. ET). To participate, please
dial (888) 802-2279 (toll-free in North America) or (913) 312-1265
approximately 10 minutes prior to the conference call. An archived
recording of the call will be available from approximately 3:00 p.m. MT
on April 25 until midnight April 29, 2007 by dialling (888) 203-1112 or
(719) 457-0820 and entering access code 2755584.
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.
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NOTE 1: Non-GAAP measures
This news release contains references to cash flow, total operating
earnings and free cash flow.
- Cash flow is a non-GAAP measure defined as Cash from Operating
Activities excluding net change in other assets and liabilities, net
change in non-cash working capital from continuing operations and net
change in non-cash working capital from discontinued operations, all
of which are defined on the Consolidated Statement of Cash Flows.
- Total operating earnings is a non-GAAP measure that shows net
earnings excluding non-operating items such as the after-tax impacts
of a gain on discontinuance, the after-tax gain/loss of unrealized
mark-to-market accounting for derivative instruments, the after-tax
gain/loss on translation of U.S. dollar denominated Notes issued in
Canada and the effect of the reduction in income tax rates.
Management believes that these excluded items reduce the
comparability of the company's underlying financial performance
between periods. The majority of the unrealized gains/losses that
relate to U.S. dollar debt issued in Canada are for debt with
maturity dates in excess of five years.
- Free cash flow is a non-GAAP measure that EnCana defines as cash flow
in excess of core capital investment.
These measures have been described and presented in this news release in
order to provide shareholders and potential investors with additional
information regarding EnCana's liquidity and its ability to generate funds to
finance its operations.
EnCana Corporation
With an enterprise value of approximately US$48 billion, EnCana is a
leading North American unconventional natural gas and integrated oilsands
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.
ADVISORY REGARDING RESERVES DATA AND OTHER OIL AND GAS INFORMATION -
EnCana's disclosure of reserves data and other oil and gas information is made
in reliance on an exemption granted to EnCana by Canadian securities
regulatory authorities which permits it to provide such disclosure in
accordance with U.S. disclosure requirements. The information provided by
EnCana may differ from the corresponding information prepared in accordance
with Canadian disclosure standards under National Instrument 51-101 (NI 51-
101). EnCana's reserves quantities represent net proved reserves calculated
using the standards contained in Regulation S-X of the U.S. Securities and
Exchange Commission. Further information about the differences between the
U.S. requirements and the NI 51-101 requirements is set forth under the
heading "Note Regarding Reserves Data and Other Oil and Gas Information" in
EnCana's Annual Information Form.
In this news release, certain crude oil and NGLs volumes have been
converted to cubic feet equivalent (cfe) on the basis of one barrel (bbl) to
six thousand cubic feet (Mcf). Also, certain natural gas volumes have been
converted to barrels of oil equivalent (BOE) on the same basis. BOE and cfe
may be misleading, particularly if used in isolation. A conversion ratio of
one bbl to six Mcf is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not represent value
equivalency at the well head.
Unbooked resource potential
EnCana defines unbooked resource potential as quantities of oil and
natural gas on existing landholdings that are not yet classified as proved
reserves, but which EnCana believes may be moved into the proved reserves
category and produced in the future. EnCana employs a probability-weighted
approach in the calculation of these quantities, including statistical
distributions of resource play performance and areal extent. Consequently,
EnCana's unbooked resource potential necessarily includes quantities of
probable and possible reserves and contingent resources, as these terms are
defined in the Canadian Oil and Gas Evaluation Handbook.
ADVISORY REGARDING FORWARD-LOOKING STATEMENTS - In the interests of
providing EnCana shareholders and potential investors with information
regarding EnCana, including management's assessment of EnCana's and its
subsidiaries' future plans and operations, certain statements contained in
this news release are forward-looking statements or information within the
meaning of applicable securities legislation, collectively referred to herein
as "forward-looking statements." Forward-looking statements in this news
release include, but are not limited to: future economic and operating
performance (including per share growth, net debt-to-capitalization ratio,
cash flow and increase in net asset value); anticipated ability to meet the
company's guidance forecasts; anticipated life of proved reserves; anticipated
unbooked resource potential; anticipated conversion of unbooked resource
potential to proved reserves; anticipated growth and success of resource plays
and the expected characteristics of resource plays; the expected proceeds from
planned divestitures; planned expansion of in-situ oilsands production;
anticipated crude oil and natural gas prices; anticipated expansion and
production at Foster Creek and Christina Lake; anticipated increased capacity
for the two U.S. refineries; anticipated drilling inventory; expected
proportion of total production and cash flows contributed by natural gas;
anticipated success of EnCana's market risk mitigation strategy and EnCana's
ability to reduce uncertainty in cash flow during periods of commodity price
volatility and provide downside price protection; anticipated purchases
pursuant to the Normal Course Issuer Bid and the source of funding therefor;
potential demand for natural gas; anticipated bitumen production in 2007 and
beyond; anticipated drilling; potential capital expenditures and investment;
potential oil, natural gas and NGLs production in 2007 and beyond; anticipated
costs and inflationary pressures; potential risks associated with drilling and
references to potential exploration. Readers are cautioned not to place undue
reliance on forward-looking statements, as there can be no assurance that the
plans, intentions or expectations upon which they are based will occur. By
their nature, forward-looking statements involve numerous assumptions, known
and unknown risks and uncertainties, both general and specific, that
contribute to the possibility that the predictions, forecasts, projections and
other forward-looking statements will not occur, which may cause the company's
actual performance and financial results in future periods to differ
materially from any estimates or projections of future performance or results
expressed or implied by such forward-looking statements. These risks and
uncertainties include, among other things: volatility of and assumptions
regarding oil and gas prices; assumptions based upon the company's current
guidance; fluctuations in currency and interest rates; product supply and
demand; market competition; risks inherent in the company's marketing
operations, including credit risks; imprecision of reserves estimates and
estimates of recoverable quantities of oil, natural gas and liquids from
resource plays and other sources not currently classified as proved reserves;
the ability of the company and ConocoPhillips to successfully manage and
operate the integrated North American heavy oil business and the ability of
the parties to obtain necessary regulatory approvals; refining and marketing
margins; potential disruption or unexpected technical difficulties in
developing new products and manufacturing processes; potential failure of new
products to achieve acceptance in the market; unexpected cost increases or
technical difficulties in constructing or modifying manufacturing or refining
facilities; unexpected difficulties in manufacturing, transporting or refining
synthetic crude oil; risks associated with technology; the company's ability
to replace and expand oil and gas reserves; its ability to generate sufficient
cash flow from operations to meet its current and future obligations; its
ability to access external sources of debt and equity capital; the timing and
the costs of well and pipeline construction; the company's ability to secure
adequate product transportation; changes in environmental and other
regulations or the interpretations of such regulations; political and economic
conditions in the countries in which the company operates; the risk of war,
hostilities, civil insurrection and instability affecting countries in which
the company operates and terrorist threats; risks associated with existing and
potential future lawsuits and regulatory actions made against the company; and
other risks and uncertainties described from time to time in the reports and
filings made with securities regulatory authorities by EnCana. Although EnCana
believes that the expectations represented by such forward-looking statements
are reasonable, there can be no assurance that such expectations will prove to
be correct. Readers are cautioned that the foregoing list of important factors
is not exhaustive.
Furthermore, the forward-looking statements contained in this news
release are made as of the date of this news release, and, except as required
by law, EnCana does not undertake any obligation to update publicly or to
revise any of the included forward-looking statements, whether as a result of
new information, future events or otherwise. The forward-looking statements
contained in this news release are expressly qualified by this cautionary
statement.

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

First quarter report
for the period ended March 31, 2007
CONSOLIDATED STATEMENT OF EARNINGS (unaudited)
Three Months Ended
March 31,
---------------------------
($ millions, except per share amounts) 2007 2006
-------------------------------------------------------------------------
REVENUES, NET OF ROYALTIES (Note 5)
Upstream $ 2,739 $ 2,604
Integrated Oilsands 1,556 189
Market Optimization 756 716
Corporate - Unrealized gain (loss)
on risk management (615) 1,263
-------------------------------------------------------------------------
4,436 4,772
EXPENSES (Note 5)
Production and mineral taxes 92 139
Transportation and selling 278 254
Operating 551 412
Purchased product 1,851 689
Depreciation, depletion and
amortization 843 765
Administrative 95 58
Interest, net (Note 8) 101 88
Accretion of asset retirement
obligation (Note 14) 14 12
Foreign exchange (gain) loss, net (Note 9) (12) 44
(Gain) on divestitures (Note 7) (59) (9)
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3,754 2,452
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NET EARNINGS BEFORE INCOME TAX 682 2,320
Income tax expense (Note 10) 185 848
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NET EARNINGS FROM CONTINUING
OPERATIONS 497 1,472
NET EARNINGS FROM DISCONTINUED
OPERATIONS (Note 6) - 2
-------------------------------------------------------------------------
NET EARNINGS $ 497 $ 1,474
-------------------------------------------------------------------------
-------------------------------------------------------------------------
NET EARNINGS FROM CONTINUING
OPERATIONS PER COMMON SHARE (Note 17)
Basic $ 0.65 $ 1.74
Diluted $ 0.64 $ 1.70
-------------------------------------------------------------------------
-------------------------------------------------------------------------
NET EARNINGS PER COMMON SHARE (Note 17)
Basic $ 0.65 $ 1.74
Diluted $ 0.64 $ 1.70
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See accompanying Notes to Consolidated Financial Statements.

CONSOLIDATED STATEMENT OF RETAINED EARNINGS (unaudited)
Three Months Ended
March 31,
---------------------------
($ millions) 2007 2006
-------------------------------------------------------------------------
RETAINED EARNINGS, BEGINNING OF YEAR $ 11,344 $ 9,481
Net Earnings 497 1,474
Dividends on Common Shares (153) (64)
Charges for Normal Course
Issuer Bid (Note 15) (816) (801)
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RETAINED EARNINGS, END OF PERIOD $ 10,872 $ 10,090
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CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (unaudited)
Three Months Ended
March 31,
---------------------------
($ millions) 2007 2006
-------------------------------------------------------------------------
NET EARNINGS $ 497 $ 1,474
OTHER COMPREHENSIVE INCOME, NET OF TAX
Foreign Currency Translation Adjustment 111 94
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COMPREHENSIVE INCOME $ 608 $ 1,568
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CONSOLIDATED STATEMENT OF ACCUMULATED OTHER COMPREHENSIVE INCOME
(unaudited)
Three Months Ended
March 31,
---------------------------
($ millions) 2007 2006
-------------------------------------------------------------------------
ACCUMULATED OTHER COMPREHENSIVE INCOME,
BEGINNING OF YEAR $ 1,375 $ 1,262
Foreign Currency Translation Adjustment 111 94
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ACCUMULATED OTHER COMPREHENSIVE INCOME,
END OF PERIOD $ 1,486 $ 1,356
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As at March 31, 2007, the accumulated other comprehensive income consists
of foreign currency translation adjustments of $1,486 million
(December 31, 2006 - $1,375 million; March 31, 2006 - $1,356 million).
See accompanying Notes to Consolidated Financial Statements.

CONSOLIDATED BALANCE SHEET (unaudited)
As at As at
March 31, December 31,
($ millions) 2007 2006
-------------------------------------------------------------------------
ASSETS
Current Assets
Cash and cash equivalents $ 337 $ 402
Accounts receivable and accrued
revenues 2,014 1,721
Current portion of partnership
contribution receivable (Note 4, 11) 357 -
Risk management (Note 18) 899 1,403
Inventories (Note 12) 567 176
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4,174 3,702
Property, Plant and
Equipment, net (Note 5) 28,806 28,213
Investments and Other Assets 512 533
Partnership Contribution
Receivable (Note 4, 11) 3,299 -
Risk Management (Note 18) 55 133
Goodwill 2,547 2,525
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(Note 5) $ 39,393 $ 35,106
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LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued
liabilities $ 3,210 $ 2,494
Income tax payable 934 926
Current portion of
partnership
contribution payable (Note 4, 11) 345 -
Risk management (Note 18) 60 14
Current portion of
long-term debt (Note 13) 260 257
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4,809 3,691
Long-Term Debt (Note 13) 6,977 6,577
Other Liabilities 151 79
Partnership Contribution
Payable (Note 4, 11) 3,311 -
Risk Management (Note 18) 17 2
Asset Retirement Obligation (Note 14) 1,085 1,051
Future Income Taxes 6,131 6,240
-------------------------------------------------------------------------
22,481 17,640
-------------------------------------------------------------------------
Shareholders' Equity
Share capital (Note 15) 4,493 4,587
Paid in surplus 61 160
Retained earnings 10,872 11,344
Accumulated other comprehensive income 1,486 1,375
-------------------------------------------------------------------------
Total Shareholders' Equity 16,912 17,466
-------------------------------------------------------------------------
$ 39,393 $ 35,106
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.

CONSOLIDATED STATEMENT OF CASH FLOWS (unaudited)
Three Months Ended
March 31,
---------------------------
($ millions) 2007 2006
-------------------------------------------------------------------------
OPERATING ACTIVITIES
Net earnings from continuing
operations $ 497 $ 1,472
Depreciation, depletion and
amortization 843 765
Future income taxes (Note 10) (190) 517
Unrealized (gain) loss on
risk management (Note 18) 614 (1,261)
Unrealized foreign exchange
(gain) loss (11) 60
Accretion of asset retirement
obligation (Note 14) 14 12
(Gain) on divestitures (Note 7) (59) (9)
Other 44 23
Cash flow from discontinued
operations - 112
Net change in other assets and
liabilities 20 (11)
Net change in non-cash working
capital from continuing operations 137 2,044
Net change in non-cash working
capital from discontinued
operations - (1,427)
-------------------------------------------------------------------------
Cash From Operating Activities 1,909 2,297
-------------------------------------------------------------------------
INVESTING ACTIVITIES
Capital expenditures (Note 5) (1,490) (1,961)
Proceeds on disposal of assets (Note 7) 281 255
Net change in investments and other 19 77
Net change in non-cash working
capital from continuing operations (58) 119
Discontinued operations - 1,313
-------------------------------------------------------------------------
Cash (Used in) Investing Activities (1,248) (197)
-------------------------------------------------------------------------
FINANCING ACTIVITIES
Net issuance (repayment) of
revolving long-term debt - (881)
Issuance of long-term debt 434 -
Issuance of common shares (Note 15) 76 52
Purchase of common shares (Note 15) (1,094) (978)
Dividends on common shares (153) (64)
Other 11 (10)
-------------------------------------------------------------------------
Cash (Used in) Financing
Activities (726) (1,881)
-------------------------------------------------------------------------
DEDUCT: FOREIGN EXCHANGE LOSS ON
CASH AND CASH EQUIVALENTS HELD
IN FOREIGN CURRENCY - -
-------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS (65) 219
CASH AND CASH EQUIVALENTS,
BEGINNING OF YEAR 402 105
-------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS,
END OF PERIOD $ 337 $ 324
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.

Notes to Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise specified)
1. BASIS OF PRESENTATION
The interim Consolidated Financial Statements include the accounts of
EnCana Corporation and its subsidiaries ("EnCana" or the "Company"), and
are presented in accordance with Canadian generally accepted accounting
principles. EnCana's continuing operations are in the business of
exploration for, and production and marketing of, natural gas, crude oil
and natural gas liquids, refining operations and power generation
operations.
The interim Consolidated Financial Statements have been prepared
following the same accounting policies and methods of computation as the
annual audited Consolidated Financial Statements for the year ended
December 31, 2006, except as noted below. The disclosures provided below
are incremental to those included with the annual audited Consolidated
Financial Statements. The interim Consolidated Financial Statements
should be read in conjunction with the annual audited Consolidated
Financial Statements and the notes thereto for the year ended
December 31, 2006.
2. CHANGES IN ACCOUNTING POLICIES AND PRACTICES
As disclosed in the December 31, 2006 annual audited Consolidated
Financial Statements, on January 1, 2007, the Company adopted the
Canadian Institute of Chartered Accountants ("CICA") Handbook Section
1530 "Comprehensive Income", Section 3251 "Equity", Section 3855
"Financial Instruments - Recognition and Measurement", and Section 3865
"Hedges". As required by the new standards, prior periods have not been
restated, except to reclassify the foreign currency translation
adjustment balance as described under Comprehensive Income.
The adoption of these standards has had no material impact on the
Company's net earnings or cash flows. The other effects of the
implementation of the new standards are discussed below.
Comprehensive Income
The new standards introduce comprehensive income, which consists of net
earnings and other comprehensive income ("OCI"). The Company's
Consolidated Financial Statements now include a Statement of
Comprehensive Income, which includes the components of comprehensive
income. For EnCana, OCI is currently comprised of the changes in the
foreign currency translation adjustment balance.
The cumulative changes in OCI are included in accumulated other
comprehensive income ("AOCI"), which is presented as a new category
within shareholders' equity in the Consolidated Balance Sheet. The
accumulated foreign currency translation adjustment, formerly presented
as a separate category within shareholders' equity, is now included in
AOCI. The Company's Consolidated Financial Statements now include a
Statement of Accumulated Other Comprehensive Income, which provides the
continuity of the AOCI balance.
The adoption of comprehensive income has been made in accordance with the
applicable transitional provisions. Accordingly, the March 31, 2007
period end accumulated foreign currency translation adjustment balance of
$1,486 million has been reclassified to AOCI (December 31, 2006 -
$1,375 million; March 31, 2006 - $1,356 million). In addition, the change
in the accumulated foreign currency translation adjustment balance for
the three months ended March 31, 2007 of $111 million, is now included in
OCI in the Statement of Comprehensive Income (three months ended
March 31, 2006 - $94 million).
Financial Instruments
The financial instruments standard establishes the recognition and
measurement criteria for financial assets, financial liabilities and
derivatives. All financial instruments are required to be measured at
fair value on initial recognition of the instrument, except for certain
related party transactions. Measurement in subsequent periods depends on
whether the financial instrument has been classified as
"held-for-trading", "available-for-sale", "held-to-maturity",
"loans and receivables", or "other financial liabilities" as defined by
the standard.
Financial assets and financial liabilities "held-for-trading" are
measured at fair value with changes in those fair values recognized in
net earnings. Financial assets "available-for-sale" are measured at fair
value, with changes in those fair values recognized in OCI. Financial
assets "held-to-maturity", "loans and receivables" and "other financial
liabilities" are measured at amortized cost using the effective interest
method of amortization. The methods used by the Company in determining
fair value of financial instruments are unchanged as a result of
implementing the new standard.
Cash and cash equivalents are designated as "held-for-trading" and are
measured at carrying value, which approximates fair value due to the
short-term nature of these instruments. Accounts receivable and accrued
revenues and the partnership contribution receivable are designated as
"loans and receivables". Accounts payable and accrued liabilities, the
partnership contribution payable and long-term debt are designated as
"other liabilities".
The adoption of the financial instruments standard has been made in
accordance with its transitional provisions. Accordingly, at
January 1, 2007, $52 million of other assets were reclassified to
long-term debt to reflect the adopted policy of capitalizing long-term
debt transaction costs, premiums and discounts within long-term debt. The
costs capitalized within long-term debt will be amortized using the
effective interest method. Previously, the Company deferred these costs
within other assets and amortized them straight-line over the life of the
related long-term debt. The adoption of the effective interest method of
amortization had no effect on opening retained earnings.
Risk management assets and liabilities are derivative financial
instruments classified as "held-for-trading" unless designated for hedge
accounting. Additional information on the Company's accounting treatment
of derivative financial instruments is contained in Note 1 of the
Company's annual audited Consolidated Financial Statements for the year
ended December 31, 2006.
3. UPDATE TO ACCOUNTING POLICIES AND PRACTICES
As a result of the new joint venture with ConocoPhillips, EnCana has
updated the following significant accounting policies and practices to
incorporate the refining business (see Note 4):
Revenue Recognition
Revenues associated with the sales of EnCana's natural gas, crude oil,
NGLs and petroleum and chemical products are recognized when title passes
from the Company to its customer. Natural gas and crude oil produced and
sold by EnCana below or above its working interest share in the related
resource properties results in production underliftings or overliftings.
Underliftings are recorded as inventory and overliftings are recorded as
deferred revenue. Realized gains and losses from the Company's natural
gas and crude oil commodity price risk management activities are recorded
in revenue when the product is sold.
Market optimization revenues and purchased product are recorded on a
gross basis when EnCana takes title to product and has risks and rewards
of ownership. Purchases and sales of inventory with the same counterparty
that are entered into in contemplation of each other are recorded on a
net basis. Revenues associated with the services provided where EnCana
acts as agent are recorded as the services are provided. Revenues
associated with the sale of natural gas storage services are recognized
when the services are provided. Sales of electric power are recognized
when power is provided to the customer.
Unrealized gains and losses from the Company's natural gas and crude oil
commodity price risk management activities are recorded as revenue based
on the related mark-to-market calculations at the end of the respective
period.
Inventory
Product inventories, including petroleum and chemical products, are
valued at the lower of average cost and net realizable value on a
first-in, first-out basis. Materials and supplies are valued at cost.
Property, Plant and Equipment
Upstream
EnCana accounts for natural gas and crude oil properties in accordance
with the Canadian Institute of Chartered Accountants' guideline on full
cost accounting in the oil and gas industry. Under this method, all
costs, including internal costs and asset retirement costs, directly
associated with the acquisition of, exploration for and the development
of, natural gas and crude oil reserves, are capitalized on a
country-by-country cost centre basis.
Costs accumulated within each cost centre are depreciated, depleted and
amortized using the unit-of-production method based on estimated proved
reserves determined using estimated future prices and costs. For purposes
of this calculation, oil is converted to gas on an energy equivalent
basis. Capitalized costs subject to depletion include estimated future
costs to be incurred in developing proved reserves. Proceeds from the
divestiture of properties are normally deducted from the full cost pool
without recognition of gain or loss unless that deduction would result in
a change to the rate of depreciation, depletion and amortization of
20 percent or greater, in which case a gain or loss is recorded. Costs of
major development projects and costs of acquiring and evaluating
significant unproved properties are excluded, on a cost centre basis,
from the costs subject to depletion until it is determined whether or not
proved reserves are attributable to the properties, or impairment has
occurred. Costs that have been impaired are included in the costs subject
to depreciation, depletion and amortization.
An impairment loss is recognized in net earnings when the carrying amount
of a cost centre is not recoverable and the carrying amount of the cost
centre exceeds its fair value. The carrying amount of the cost centre is
not recoverable if the carrying amount exceeds the sum of the
undiscounted cash flows from proved reserves. If the sum of the cash
flows is less than the carrying amount, the impairment loss is limited to
the amount by which the carrying amount exceeds the sum of:
i. the fair value of proved and probable reserves; and
ii. the costs of unproved properties that have been subject to a separate
impairment test.
Downstream Refining
Refining facilities are carried at cost, including asset retirement
costs, and depreciated on a straight-line basis over the estimated
service lives of the assets, which are approximately 25 years.
Midstream facilities
Midstream facilities, including natural gas storage facilities, natural
gas liquids extraction plant facilities and power generation facilities,
are carried at cost and depreciated on a straight-line basis over the
estimated service lives of the assets, which range from 20 to 25 years.
Capital assets related to pipelines are carried at cost and depreciated
or amortized using the straight-line method over their economic lives,
which range from 20 to 35 years.
Corporate
Costs associated with office furniture, fixtures, leasehold improvements,
information technology and aircraft are carried at cost and depreciated
on a straightline basis over the estimated service lives of the assets,
which range from 3 to 25 years. Assets under construction are not subject
to depreciation. Land is carried at cost.
Asset Retirement Obligation
The fair value of estimated asset retirement obligations is recognized in
the Consolidated Balance Sheet when identified and a reasonable estimate
of fair value can be made.
Asset retirement obligations include those legal obligations where the
Company will be required to retire tangible long-lived assets such as
producing well sites, offshore production platforms, natural gas
processing plants, and refining facilities. These obligations also
include items for which the Company has made promissory estoppel. The
asset retirement cost, equal to the initially estimated fair value of the
asset retirement obligation, is capitalized as part of the cost of the
related long-lived asset. Changes in the estimated obligation resulting
from revisions to estimated timing or amount of undiscounted cash flows
are recognized as a change in the asset retirement obligation and the
related asset retirement cost.
Asset retirement costs for natural gas and crude oil assets are amortized
using the unit-of-production method. Asset retirement costs for refining
facilities are amortized on a straight-line basis over the useful life of
the related asset. Amortization of asset retirement costs are included in
depreciation, depletion and amortization in the Consolidated Statement of
Earnings. Increases in the asset retirement obligation resulting from the
passage of time are recorded as accretion of asset retirement obligation
in the Consolidated Statement of Earnings.
Actual expenditures incurred are charged against the accumulated
obligation.
4. JOINT VENTURE WITH CONOCOPHILLIPS
On January 2, 2007, EnCana became a 50 percent partner in an integrated,
North American heavy oil business with ConocoPhillips which consists of
an upstream and a downstream entity. The upstream entity includes
contributed assets from EnCana, primarily Foster Creek and Christina Lake
oilsands properties, with a fair value of $7.5 billion and a note
receivable from ConocoPhillips of an equal amount. For the downstream
entity, ConocoPhillips contributed its Wood River and Borger refineries,
located in Illinois and Texas respectively, for a fair value of
$7.5 billion and EnCana contributed a note payable of $7.5 billion.
Further information about these notes is included in Note 11.
In accordance with Canadian generally accepted accounting principles,
these entities have been accounted for using the proportionate
consolidation method with the results of operations shown in a separate
business segment, Integrated Oilsands.
5. SEGMENTED INFORMATION
The Company has defined its continuing operations into the following
segments:
- Canada, United States and Other includes the Company's upstream
exploration for, and development and production of, natural gas,
crude oil and natural gas liquids and other related activities. The
majority of the Company's upstream operations are located in Canada
and the United States. Offshore and international exploration is
mainly focused on opportunities in Brazil, the Middle East, Greenland
and France.
- Integrated Oilsands is focused on two lines of business: the
exploration for, and development and production of heavy oil from
oilsands in Canada using in-situ recovery methods; and the refining
of crude oil into petroleum and chemical products located in the
United States. This segment represents EnCana's 50 percent interest
in the joint venture with ConocoPhillips.
- Market Optimization is conducted by the Midstream & Marketing
division. The Marketing groups' primary responsibility is the sale of
the Company's proprietary production. The results are included in the
Canada, United States and Integrated Oilsands segments.
Correspondingly, the Marketing groups also undertake market
optimization activities which comprise third party purchases and
sales of product that provide operational flexibility for
transportation commitments, product type, delivery points and
customer diversification. These activities are reflected in the
Market Optimization segment.
- Corporate includes unrealized gains or losses recorded on derivative
financial instruments. Once amounts are settled, the realized gains
and losses are recorded in the operating segment to which the
derivative instrument relates.
Market Optimization markets substantially all of the Company's upstream
production to third-party customers. Transactions between business
segments are based on market values and eliminated on consolidation. The
tables in this note present financial information on an after
eliminations basis.
Operations that have been discontinued are disclosed in Note 6.
Results of Continuing Operations (For the three months ended March 31)
Upstream
-----------------------------------------------------
Canada United States Other
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues,
Net of Royalties $ 1,763 $ 1,749 $ 885 $ 779 $ 91 $ 76
Expenses
Production and
mineral taxes 28 45 64 94 - -
Transportation
and selling 80 68 66 66 - -
Operating 237 213 75 68 81 67
Purchased product - - - - - -
Depreciation,
depletion and
amortization 490 490 260 210 6 7
-------------------------------------------------------------------------
Segment Income $ 928 $ 933 $ 420 $ 341 $ 4 $ 2
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Integrated Market
Total Upstream Oilsands Optimization
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues,
Net of Royalties $ 2,739 $ 2,604 $ 1,556 $ 189 $ 756 $ 716
Expenses
Production and
mineral taxes 92 139 - - - -
Transportation
and selling 146 134 124 117 8 3
Operating 393 348 152 45 7 18
Purchased product - - 1,119 - 732 689
Depreciation,
depletion and
amortization 756 707 66 37 3 3
-------------------------------------------------------------------------
Segment Income
(Loss) $ 1,352 $ 1,276 $ 95 $ (10) $ 6 $ 3
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Corporate Consolidated
-------------------------------------------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of Royalties $ (615) $ 1,263 $ 4,436 $ 4,772
Expenses
Production and mineral taxes - - 92 139
Transportation and selling - - 278 254
Operating (1) 1 551 412
Purchased product - - 1,851 689
Depreciation, depletion and
amortization 18 18 843 765
-------------------------------------------------------------------------
Segment Income (Loss) $ (632) $ 1,244 821 2,513
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Administrative 95 58
Interest, net 101 88
Accretion of asset retirement
obligation 14 12
Foreign exchange (gain) loss, net (12) 44
(Gain) on divestitures (59) (9)
-------------------------------------------------------------------------
139 193
-------------------------------------------------------------------------
Net Earnings Before Income Tax 682 2,320
Income tax expense 185 848
-------------------------------------------------------------------------
Net Earnings From Continuing
Operations $ 497 $ 1,472
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Results of Continuing Operations (For the three months ended March 31)
Geographic and Product Information (Continuing Operations)
Produced Gas
-------------------------------------------------------------------------
Canada United States Total
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues,
Net of Royalties $ 1,388 $ 1,441 $ 831 $ 718 $ 2,219 $ 2,159
Expenses
Production and
mineral taxes 20 36 58 89 78 125
Transportation
and selling 70 67 66 66 136 133
Operating 177 153 75 68 252 221
-------------------------------------------------------------------------
Operating Cash Flow $ 1,121 $ 1,185 $ 632 $ 495 $ 1,753 $ 1,680
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Oil & NGLs
-------------------------------------------------------------------------
Canada United States Total
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues,
Net of Royalties $ 375 $ 308 $ 54 $ 61 $ 429 $ 369
Expenses
Production and
mineral taxes 8 9 6 5 14 14
Transportation
and selling 10 1 - - 10 1
Operating 60 60 - - 60 60
-------------------------------------------------------------------------
Operating Cash Flow $ 297 $ 238 $ 48 $ 56 $ 345 $ 294
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Integrated Oilsands
-------------------------------------------------------------------------
Downstream
Oil Refining Other
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues,
Net of Royalties $ 220 $ 183 $ 1,343 $ - $ (7) $ 6
Expenses
Transportation
and selling 124 117 - - - -
Operating 49 38 100 - 3 7
Purchased product - - 1,134 - (15) -
-------------------------------------------------------------------------
Operating Cash Flow $ 47 $ 28 $ 109 $ - $ 5 $ (1)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Integrated
Oilsands
-------------------------------------------------------------------------
Total
-------------------------------------------------------------------------
2007 2006
-------------------------------------------------------------------------
Revenues, Net of Royalties $ 1,556 $ 189
Expenses
Transportation and selling 124 117
Operating 152 45
Purchased product 1,119 -
-------------------------------------------------------------------------
Operating Cash Flow $ 161 $ 27
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Capital Expenditures (Continuing Operations)
Three Months Ended
March 31,
---------------------------
2007 2006
-------------------------------------------------------------------------
Core Capital
Canada $ 871 $ 1,129
United States 439 537
Other 8 18
Integrated Oilsands 115 220
Market Optimization 1 29
Corporate 49 13
-------------------------------------------------------------------------
1,483 1,946
-------------------------------------------------------------------------
Acquisition Capital
Canada 7 8
United States - 7
-------------------------------------------------------------------------
7 15
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total $ 1,490 $ 1,961
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Property, Plant and Equipment and Total Assets
Property, Plant
and Equipment Total Assets
-------------------------------------------------------
As at As at
-------------------------------------------------------
March 31, December 31, March 31, December 31,
2007 2006 2007 2006
-------------------------------------------------------------------------
Canada $ 15,199 $ 17,702 $ 16,502 $ 19,060
United States 8,656 8,494 9,194 9,036
Other 118 263 138 300
Integrated Oilsands 4,361 1,322 8,904 1,379
Market Optimization 154 154 426 468
Corporate 318 278 4,229 4,863
-------------------------------------------------------------------------
Total $ 28,806 $ 28,213 $ 39,393 $ 35,106
-------------------------------------------------------------------------
-------------------------------------------------------------------------

On February 9, 2007, EnCana announced that it had completed the next
phase in the development of The Bow office project with the sale of
project assets and has entered into a 25 year lease agreement with a
third party developer. Corporate Property, Plant and Equipment includes
EnCana's accrual to date of $57 million related to this office project as
an asset under construction. A corresponding liability is included in
Other Liabilities in the Consolidated Balance Sheet. There is no effect
on the Company's net earnings or cash flows related to the capitalization
of The Bow office project.

6. DISCONTINUED OPERATIONS
All of the sales of discontinued operations were completed as of
December 31, 2006.
Midstream
During 2006, EnCana completed, in two separate transactions with a single
purchaser, the sale of its natural gas storage operations in Canada and
the United States. Total proceeds received were approximately
$1.5 billion and an after-tax gain on sale of $829 million was recorded.
Ecuador
On February 28, 2006, EnCana completed the sale of its Ecuador operations
for proceeds of $1.4 billion before indemnifications. A loss of
$279 million, including the impact of indemnifications, was recorded.
Indemnifications are discussed further in this note.
Amounts recorded as depreciation, depletion and amortization in 2006
represent provisions which were recorded against the net book value of
the Ecuador operations to recognize Management's best estimate of the
difference between the selling price and the underlying accounting value
of the related investments, as required by Canadian generally accepted
accounting principles.
Consolidated Statement of Earnings
The following table presents the effect of the discontinued operations in
the Consolidated Statement of Earnings:
For the three months ended March 31,
-------------------------------------------------------
United
Ecuador Kingdom Midstream Total
-------------------------------------------------------
2007 2006 2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues,
Net of
Royalties(*) $ - $ 200 $ - $ - $ - $ 435 $ - $ 635
-------------------------------------------------------------------------
Expenses
Production and
mineral taxes - 23 - - - - - 23
Transportation
and selling - 10 - - - - - 10
Operating - 25 - - - 19 - 44
Purchased product - - - - - 354 - 354
Depreciation,
depletion and
amortization - 84 - - - - - 84
Interest, net - (2) - - - - - (2)
Foreign exchange
(gain) loss, net - 1 - 1 - - - 2
(Gain) loss on
discontinuance - 47 - - - - - 47
-------------------------------------------------------------------------
- 188 - 1 - 373 - 562
-------------------------------------------------------------------------
Net Earnings (Loss)
Before Income Tax - 12 - (1) - 62 - 73
Income tax
expense - 59 - - - 12 - 71
-------------------------------------------------------------------------
Net Earnings (Loss)
From Discontinued
Operations $ - $ (47) $ - $ (1) $ - $ 50 $ - $ 2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) Revenues, net of royalties in Ecuador for 2006 include realized
losses of $1 million related to derivative financial instruments.

Contingencies
EnCana agreed to indemnify the purchaser of its Ecuador interests against
losses that may arise in certain circumstances which are defined in the
share sale agreements. The obligation to indemnify will arise should
losses exceed amounts specified in the sale agreements and is limited to
maximum amounts which are set forth in the share sale agreements.
During the second quarter of 2006, the Government of Ecuador seized the
Block 15 assets, in relation to which EnCana previously held a 40 percent
economic interest, from the operator which is an event requiring
indemnification under the terms of EnCana's sale agreement with the
purchaser. The purchaser requested payment and EnCana paid the maximum
amount in the third quarter, calculated in accordance with the terms of
the agreements, of approximately $265 million. EnCana does not expect
that any further significant indemnification payments relating to any
other business matters addressed in the share sale agreements will be
required to be made to the purchaser.
7. DIVESTITURES
Total proceeds received on sale of assets and investments was
$281 million (2006 - $255 million) as described below:
Canada and United States
In 2007, the Company has completed the divestiture of mature conventional
oil and natural gas assets for proceeds of $17 million
(2006 - $11 million).
Other
In January 2007, the Company completed the sale of its interests in Chad,
properties that are considered to be in the pre-production stage, for
proceeds of $207 million which results in a gain on sale of $59 million.
Market Optimization
In February 2006, the Company sold its investment in Entrega Gas Pipeline
LLC for approximately $244 million which resulted in a gain on sale of
$17 million.
Corporate
In February 2007, the Company sold The Bow office project assets for
proceeds of approximately $57 million, representing its investment at the
date of sale. Refer to Note 5 for further discussion of The Bow office
project assets.
8. INTEREST, NET
Three Months Ended
March 31,
---------------------------
2007 2006
-------------------------------------------------------------------------
Interest Expense - Long-Term Debt $ 100 $ 94
Interest Expense - Other(*) 63 5
Interest Income(*) (62) (11)
-------------------------------------------------------------------------
$ 101 $ 88
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) In 2007, Interest Expense - Other and Interest Income are primarily
due to the Partnership Contribution Payable and Receivable, respectively.
See Note 11.

9. FOREIGN EXCHANGE (GAIN) LOSS, NET
Three Months Ended
March 31,
---------------------------
2007 2006
-------------------------------------------------------------------------
Unrealized Foreign Exchange (Gain) Loss on:
Translation of U.S. dollar debt issued
from Canada $ (41) $ 4
Translation of U.S. dollar partnership
contribution receivable issued from Canada 38 -
Other Foreign Exchange (Gain) Loss (9) 40
-------------------------------------------------------------------------
$ (12) $ 44
-------------------------------------------------------------------------
-------------------------------------------------------------------------

10. INCOME TAXES
The provision for income taxes is as follows:
Three Months Ended
March 31,
---------------------------
2007 2006
-------------------------------------------------------------------------
Current
Canada $ 282 $ 308
United States 92 23
Other Countries 1 -
-------------------------------------------------------------------------
Total Current Tax 375 331
-------------------------------------------------------------------------
Future (190) 517
-------------------------------------------------------------------------
$ 185 $ 848
-------------------------------------------------------------------------
-------------------------------------------------------------------------

The following table reconciles income taxes calculated at the Canadian
statutory rate with the actual income taxes:
Three Months Ended
March 31,
---------------------------
2007 2006
-------------------------------------------------------------------------
Net Earnings Before Income Tax $ 682 $ 2,320
Canadian Statutory Rate 32.3% 35.9%
-------------------------------------------------------------------------
Expected Income Tax 220 833
Effect on Taxes Resulting from:
Non-deductible Canadian Crown payments - 31
Canadian resource allowance - (20)
Statutory and other rate differences 5 (16)
Non-taxable downstream partnership income (6) -
Non-taxable capital (gains) losses (20) (1)
Large corporations tax - 1
Other (14) 20
-------------------------------------------------------------------------
$ 185 $ 848
-------------------------------------------------------------------------
Effective Tax Rate 27.1% 36.6%
-------------------------------------------------------------------------
-------------------------------------------------------------------------

11. PARTNERSHIP CONTRIBUTION RECEIVABLE/PAYABLE
Partnership Contribution Receivable
On January 2, 2007, upon the creation of the integrated oilsands joint
venture, ConocoPhillips entered into a subscription agreement for a
50 percent interest in FCCL Oil Sands Partnership, the upstream entity,
in exchange for a promissory note of $7.5 billion. The note bears
interest at a rate of 5.3 percent per annum. Equal payments of principal
and interest are payable quarterly, with final payment due
January 2, 2017. The current and long-term partnership contribution
receivable shown in the Consolidated Balance Sheet represent EnCana's
50 percent share of this promissory note.
Partnership Contribution Payable
On January 2, 2007, upon the creation of the integrated oilsands joint
venture, EnCana issued a promissory note to WRB Refining LLC, the
downstream entity, in the amount of $7.5 billion in exchange for a
50 percent interest. The note bears interest at a rate of 6.0 percent per
annum. Equal payments of principal and interest are payable quarterly,
with final payment due January 2, 2017. The current and long-term
partnership contribution payable amounts shown in the Consolidated
Balance Sheet represent EnCana's 50 percent share of this promissory
note.

12. INVENTORIES
As at As at
March 31, December 31,
2007 2006
-------------------------------------------------------------------------
Product
Canada $ 21 $ 42
Integrated Oilsands 465 8
Market Optimization 81 126
-------------------------------------------------------------------------
$ 567 $ 176
-------------------------------------------------------------------------
-------------------------------------------------------------------------
13. LONG-TERM DEBT
As at As at
March 31, December 31,
2007 2006
-------------------------------------------------------------------------
Canadian Dollar Denominated Debt
Revolving credit and term loan borrowings $ 1,399 $ 1,456
Unsecured notes 1,236 793
-------------------------------------------------------------------------
2,635 2,249
-------------------------------------------------------------------------
U.S. Dollar Denominated Debt
Revolving credit and term loan borrowings 176 104
Unsecured notes 4,421 4,421
-------------------------------------------------------------------------
4,597 4,525
-------------------------------------------------------------------------
Increase in Value of Debt Acquired(*) 59 60
Debt Discounts and Financing Costs (54) -
Current Portion of Long-Term Debt (260) (257)
-------------------------------------------------------------------------
$ 6,977 $ 6,577
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) Certain of the notes and debentures of EnCana were acquired in
business combinations and were accounted for at their fair value at the
dates of acquisition. The difference between the fair value and the
principal amount of the debt is being amortized over the remaining life
of the outstanding debt acquired, approximately 21 years.
On March 12, 2007, EnCana completed a public offering in Canada of senior
unsecured medium term notes in the aggregate principal amount of
C$500 million. The notes have a coupon rate of 4.3 percent and mature on
March 12, 2012.

14. 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
March 31, December 31,
2007 2006
-------------------------------------------------------------------------
Asset Retirement Obligation,
Beginning of Year $ 1,051 $ 816
Liabilities Incurred 27 68
Liabilities Settled (15) (51)
Change in Estimated Future Cash Flows 2 172
Accretion Expense 14 50
Other 6 (4)
-------------------------------------------------------------------------
Asset Retirement Obligation, End of Period $ 1,085 $ 1,051
-------------------------------------------------------------------------
-------------------------------------------------------------------------
15. SHARE CAPITAL
March 31, 2007 December 31, 2006
(millions) Number Amount Number Amount
-------------------------------------------------------------------------
Common Shares
Outstanding,
Beginning of Year 777.9 $ 4,587 854.9 $ 5,131
Common Shares Issued
under Option Plans 3.8 76 8.6 179
Stock-based Compensation - 2 - 11
Common Shares Purchased (20.4) (172) (85.6) (734)
-------------------------------------------------------------------------
Common Shares
Outstanding,
End of Period 761.3 $ 4,493 777.9 $ 4,587
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Normal Course Issuer Bid
In 2007, the Company purchased 23.3 million Common Shares for total
consideration of approximately $1,094 million. Of the amount paid,
$196 million was charged to Share capital and $898 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.
EnCana has received regulatory approval each year under Canadian
securities laws to purchase Common Shares under five consecutive Normal
Course Issuer Bids ("Bids"). EnCana is entitled to purchase, for
cancellation, up to approximately 80.2 million Common Shares under the
renewed Bid which commenced on November 6, 2006 and terminates on
November 5, 2007.
Stock Options
EnCana has stock-based compensation plans that allow employees and
directors to purchase Common Shares of the Company. Option exercise
prices approximate the market price for the Common Shares on the date the
options were issued. Options granted under the plans are generally fully
exercisable after three years and expire five years after the date
granted. Options granted under predecessor and/or related company
replacement plans expire up to 10 years from the date the options were
granted.
The following tables summarize the information about options to purchase
Common Shares that do not have Tandem Share Appreciation Rights ("TSARs")
attached to them at March 31, 2007. Information related to TSARs is
included in Note 16.

Weighted
Average
Stock Options Exercise
(millions) Price (C$)
-------------------------------------------------------------------------
Outstanding, Beginning of Year 11.8 23.17
Exercised (3.8) 23.73
Forfeited - -
-------------------------------------------------------------------------
Outstanding, End of Period 8.0 22.92
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Exercisable, End of Period 8.0 22.92
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Outstanding Options Exercisable Options
-------------------------------------------------------------
Weighted
Number of Average Weighted Number of Weighted
Range of Options Remaining Average Options Average
Exercise Outstanding Contractual Exercise Outstanding Exercise
Price (C$) (millions) Life (years) Price (C$) (millions) Price (C$)
-------------------------------------------------------------------------
11.00 to 16.99 0.7 2.5 11.59 0.7 11.59
17.00 to 22.99 0.2 0.8 22.41 0.2 22.41
23.00 to 23.99 4.8 1.1 23.86 4.8 23.86
24.00 to 24.99 2.1 0.2 24.21 2.1 24.21
25.00 to 25.99 0.2 1.5 25.58 0.2 25.58
-------------------------------------------------------------------------
8.0 1.0 22.92 8.0 22.92
-------------------------------------------------------------------------
-------------------------------------------------------------------------
At March 31, 2007, the balance in Paid in surplus relates to stock-based
compensation programs.
16. COMPENSATION PLANS
The tables below outline certain information related to EnCana's
compensation plans at March 31, 2007. Additional information is contained
in Note 15 of the Company's annual audited Consolidated Financial
Statements for the year ended December 31, 2006.
A) Pensions
The following table summarizes the net benefit plan expense:

Three Months Ended
March 31,
---------------------------
2007 2006
-------------------------------------------------------------------------
Current Service Cost $ 4 $ 3
Interest Cost 4 4
Expected Return on Plan Assets (4) (4)
Expected Actuarial Loss on Accrued Benefit
Obligation 1 1
Expected Amortization of Past Service Costs - 1
Expense for Defined Contribution Plan 7 5
-------------------------------------------------------------------------
Net Benefit Plan Expense $ 12 $ 10
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the period ended March 31, 2007, no additional contributions have
been made to the defined benefit pension plans (2006 - nil).
B) Share Appreciation Rights ("SARs")
The following table summarizes the information about SARs at March 31,
2007:
Weighted
Average
Outstanding Exercise
SARs Price
-------------------------------------------------------------------------
U.S. Dollar Denominated (US$)
Outstanding, Beginning of Year 2,088 14.21
Exercised - -
-------------------------------------------------------------------------
Outstanding, End of Period 2,088 14.21
-------------------------------------------------------------------------
Exercisable, End of Period 2,088 14.21
-------------------------------------------------------------------------
-------------------------------------------------------------------------

For the period ended March 31, 2007, EnCana recorded no compensation
costs related to the outstanding SARs (2006 - costs of $4 million).
C) Tandem Share Appreciation Rights ("TSARs")
The following table summarizes the information about TSARs at March 31,
2007:
Weighted
Average
Outstanding Exercise
TSARs Price
-------------------------------------------------------------------------
Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 17,276,191 44.99
Granted 3,801,988 55.21
Exercised - SARs (573,100) 41.34
Exercised - Options (2,340) 35.95
Forfeited (336,374) 46.51
-------------------------------------------------------------------------
Outstanding, End of Period 20,166,365 45.23
-------------------------------------------------------------------------
Exercisable, End of Period 5,915,858 42.54
-------------------------------------------------------------------------
-------------------------------------------------------------------------

For the period ended March 31, 2007, EnCana recorded compensation costs
of $58 million related to the outstanding TSARs (2006 - $28 million).
D) Performance-based Tandem Share Appreciation Rights ("Performance
TSARs")
In 2007, EnCana introduced a program whereby employees may be granted
Performance TSARs under which the employee has the right to receive a
cash payment equal to the excess of the market price of EnCana Common
Shares at the time of exercise over the grant price. Performance TSARs
vest and expire under the same terms and service conditions as the
underlying option, and vesting is subject to the Company attaining
prescribed performance as measured by the annual recycle ratio.
Performance TSARs vest proportionately for a recycle ratio of greater
than one; the maximum number of Performance TSARs vest if the recycle
ratio is three or greater.
The following table summarizes the information about Performance TSARs at
March 31, 2007.
Weighted
Average
Outstanding Exercise
TSARs Price
-------------------------------------------------------------------------
Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year - -
Granted 7,275,575 56.09
Forfeited (97,800) 56.09
-------------------------------------------------------------------------
Outstanding, End of Period 7,177,775 56.09
-------------------------------------------------------------------------
Exercisable, End of Period - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the period ended March 31, 2007, EnCana recorded compensation costs
of $2 million related to the outstanding Performance TSARs.
E) Deferred Share Units ("DSUs")
The following table summarizes the information about DSUs at March 31,
2007:
Average
Outstanding Share
DSUs Price
-------------------------------------------------------------------------
Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 866,577 29.56
Granted, Directors 66,140 56.48
Exercised (294,922) 29.56
Units, in Lieu of Dividends 3,419 58.40
-------------------------------------------------------------------------
Outstanding, End of Period 641,214 32.49
-------------------------------------------------------------------------
Exercisable, End of Period 641,214 32.49
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the period ended March 31, 2007, EnCana recorded compensation costs
of $8 million related to the outstanding DSUs (2006 - $6 million).
F) Performance Share Units ("PSUs")
The following table summarizes the information about PSUs at March 31,
2007:
Average
Outstanding Share
PSUs Price
-------------------------------------------------------------------------
Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 4,766,329 27.48
Granted 6,937 58.40
Distributed (2,937,491) 24.05
Forfeited (106,323) 33.72
-------------------------------------------------------------------------
Outstanding, End of Period 1,729,452 33.03
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the period ended March 31, 2007, EnCana recorded compensation costs
of $10 million related to the outstanding PSUs (2006 - reduction to
compensation costs of $16 million).
At March 31, 2007, EnCana has approximately 2.6 million Common Shares
held in trust for issuance upon vesting of the PSUs (2006 - 5.5 million).
17. PER SHARE AMOUNTS
The following table summarizes the Common Shares used in calculating Net
Earnings per Common Share:
Three Months Ended
March 31,
---------------------------
(millions) 2007 2006
-------------------------------------------------------------------------
Weighted Average Common Shares Outstanding
- Basic 768.4 847.9
Effect of Dilutive Securities 11.2 16.9
-------------------------------------------------------------------------
Weighted Average Common Shares Outstanding
- Diluted 779.6 864.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
18. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
As a means of managing commodity price volatility, EnCana entered into
various financial instrument agreements and physical contracts. The
following information presents all positions for financial instruments.
Realized and Unrealized Gain (Loss) on Risk Management Activities
The following tables summarize the gains and losses on risk management
activities:
Realized Gain (Loss)
--------------------
Three Months Ended
March 31,
---------------------------
2007 2006
-------------------------------------------------------------------------
Revenues, Net of Royalties $ 315 $ (206)
Operating Expenses and Other 1 1
-------------------------------------------------------------------------
Gain (Loss) on Risk Management -
Continuing Operations 316 (205)
Gain (Loss) on Risk Management -
Discontinued Operations - 1
-------------------------------------------------------------------------
$ 316 $ (204)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Unrealized Gain (Loss)
----------------------
Three Months Ended
March 31,
---------------------------
2007 2006
-------------------------------------------------------------------------
Revenues, Net of Royalties $ (615) $ 1,263
Operating Expenses and Other 1 (2)
-------------------------------------------------------------------------
Gain (Loss) on Risk Management -
Continuing Operations (614) 1,261
Gain (Loss) on Risk Management -
Discontinued Operations - 23
-------------------------------------------------------------------------
$ (614) $ 1,284
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Amounts Recognized on Transition
Upon initial adoption of the current accounting policy for risk
management instruments on January 1, 2004, the fair value of all
outstanding financial instruments that were not considered accounting
hedges was recorded in the Consolidated Balance Sheet with an offsetting
net deferred loss amount (the "transition amount"). The transition amount
is recognized into net earnings over the life of the related contracts.
Changes in fair value after that time are recorded in the Consolidated
Balance Sheet with an associated unrealized gain or loss recorded in net
earnings.
Fair Value of Outstanding Risk Management Positions
The following table presents a reconciliation of the change in the
unrealized amounts from January 1, 2007 to March 31, 2007:
Total
Fair Market Unrealized
Value Gain (Loss)
-------------------------------------------------------------------------
Fair Value of Contracts, Beginning of Year $ 1,416 $ -
Change in Fair Value of Contracts in Place
at Beginning of Year and Contracts Entered
into During 2007 (301) (301)
Fair Value of Contracts in Place at
Transition that Expired During 2007 - 3
Fair Value of Contracts Realized During 2007 (316) (316)
-------------------------------------------------------------------------
Fair Value of Contracts Outstanding $ 799 $ (614)
Paid Premiums on Unexpired Options 78
-------------------------------------------------------------------------
Fair Value of Contracts and Premiums Paid,
End of Period $ 877
-------------------------------------------------------------------------
-------------------------------------------------------------------------

At March 31, 2007, the risk management amounts are recorded in the
Consolidated Balance Sheet as follows:
As at
March 31, 2007
-------------------------------------------------------------------------
Risk Management
Current asset $ 899
Long-term asset 55
Current liability 60
Long-term liability 17
-------------------------------------------------------------------------
Net Risk Management Asset $ 877
-------------------------------------------------------------------------
-------------------------------------------------------------------------

A summary of all unrealized estimated fair value financial positions is
as follows:
As at
March 31, 2007
-------------------------------------------------------------------------
Commodity Price Risk
Natural gas $ 868
Crude oil (7)
Power 14
Interest Rate Risk 4
Credit Derivatives (2)
-------------------------------------------------------------------------
Total Fair Value Positions $ 877
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Information with respect to credit derivatives and interest rate risk
contracts in place at December 31, 2006 is disclosed in Note 16 to the
Company's annual audited Consolidated Financial Statements. No new power
contracts have been entered into at March 31, 2007.
Natural Gas
At March 31, 2007, the Company's gas risk management activities from
financial contracts had an unrealized gain of $852 million and a fair
market value position of $868 million. The contracts were as follows:
Notional Fair
Volumes Market
(MMcf/d) Term Average Price Value
-------------------------------------------------------------------------
Sales Contracts
Fixed Price Contracts
NYMEX Fixed Price 1,501 2007 8.54 US$/Mcf $ 129
Other 8 2007 8.97 US$/Mcf 2
NYMEX Fixed Price 321 2008 8.24 US$/Mcf (43)
Options
Purchased NYMEX
Put Options 240 2007 6.00 US$/Mcf (10)
Basis Contracts
Fixed NYMEX to
AECO Basis 754 2007 (0.72) US$/Mcf 60
Fixed NYMEX to
Rockies Basis 533 2007 (0.65) US$/Mcf 348
Fixed NYMEX to
CIG Basis 390 2007 (0.76) US$/Mcf 239
Fixed NYMEX to
AECO Basis 191 2008 (0.78) US$/Mcf 8
Fixed NYMEX to
Rockies Basis 162 2008 (0.59) US$/Mcf 59
Fixed NYMEX to
CIG Basis 60 2008 (0.67) US$/Mcf 20
Fixed NYMEX to Rockies
Basis (NYMEX Adjusted) 329 2008 17% of NYMEX US$/Mcf 31
Fixed NYMEX to Mid-
Continent Basis
(NYMEX Adjusted) 120 2008 12% of NYMEX US$/Mcf 1
Fixed NYMEX to
CIG Basis 20 2009 (0.71) US$/Mcf 2
Fixed NYMEX to
AECO Basis 41 2010 (0.40) US$/Mcf 2
Purchase Contracts
Fixed Price Contracts
Other 8 2007 7.84 US$/Mcf -
-------------------------------------------------------------------------
848
Other Financial Positions(*) 4
-------------------------------------------------------------------------
Total Unrealized Gain on Financial Contracts 852
Paid Premiums on Unexpired Options 16
-------------------------------------------------------------------------
Total Fair Value Positions $ 868
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) Other financial positions are part of the ongoing operations of the
Company's proprietary production management.

Crude Oil
At March 31, 2007, the Company's oil risk management activities from
financial contracts had an unrealized loss of $69 million and a fair
market value position of $(7) million. The contracts were as follows:
Notional Fair
Volumes Market
(bbls/d) Term Average Price Value
-------------------------------------------------------------------------
Fixed WTI NYMEX Price 34,500 2007 64.40 US$/bbl $ (41)
Purchased WTI NYMEX
Put Options 91,500 2007 55.34 US$/bbl (25)
-------------------------------------------------------------------------
(66)
Other Financial
Positions(*) (3)
-------------------------------------------------------------------------
Total Unrealized Loss on
Financial Contracts (69)
Paid Premiums on
Unexpired Options 62
-------------------------------------------------------------------------
Total Fair Value Positions $ (7)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) Other financial positions are part of the ongoing operations of the
Company's proprietary production management.

Power
The Company has in place two derivative contracts, commencing January 1,
2007 for a period of 11 years, to manage its electricity consumption
costs. At March 31, 2007, these contracts had an unrealized gain of
$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. Court approval
of the federal court class action settlement of $2.4 million is pending,
court approval having been granted in the state court action. Also, as
previously disclosed, without admitting any liability whatsoever, WD
concluded settlements with the U.S. Commodity Futures Trading Commission
("CFTC") for $20 million and of a previously disclosed consolidated class
action lawsuit in the United States District Court in New York for
$8.2 million.
The remaining lawsuits were commenced by individual plaintiffs, one of
which is E. & J. Gallo Winery ("Gallo"). The Gallo lawsuit claims damages
in excess of $30 million. The other remaining lawsuits do not specify the
precise amount of damages claimed. California law allows for the
possibility that the amount of damages assessed could be tripled.
The Company and WD intend to vigorously defend against the outstanding
claims; however, the Company cannot predict the outcome of these
proceedings or any future proceedings against the Company, whether these
proceedings would lead to monetary damages which could have a material
adverse effect on the Company's financial position, or whether there will
be other proceedings arising out of these allegations.
20. RECLASSIFICATION
Certain information provided for prior periods has been reclassified to
conform to the presentation adopted in 2007.
>>

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

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

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

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

ECA stock price

TSX $14.92 Can -0.200

NYSE $11.67 USD -0.180

As of 2017-11-20 09:49. Minimum 15 minute delay