EnCana's second quarter cash flow exceeds US$2.5 billion, or $3.33 per share - up 55 percent

CALGARY, July 25 /CNW/ - Solid natural gas and oilsands production
growth, stronger realized gas prices and robust refining margins all
contributed to substantial increases in EnCana Corporation's (TSX & NYSE: ECA)
cash flow and operating earnings in the second quarter of 2007.
"Now transformed into a leading integrated producer of North American
unconventional natural gas and in-situ oilsands, our company is hitting its
stride. Our diverse portfolio of natural gas, oil and oilsands resource plays
and our interests in two refineries are generating strong financial and
operating performance. Second quarter cash flow and operating earnings are
significantly higher than one year ago, production is on track to meet our
full-year targets and capital costs are tracking below budget at mid-year. Our
sustainable low-risk business model is delivering on our expectations and we
are well positioned to create strong, long-term performance," said Randy
Eresman, EnCana's President & Chief Executive Officer.
"Based on our expectations for the remainder of the year and the strong
cash flow performance to date from our upstream operations and the
larger-than-expected contributions from our integrated oilsands business, we
are raising our annual guidance for total cash flow to a range of $7.8 billion
to $8.2 billion. Also, having already completed a significant portion of our
planned share purchase program, cash flow per share guidance is now between
$10.20 and $10.70, representing a forecast growth range of 19 to 25 percent
compared to 2006," Eresman said.
<<
Second Quarter 2007 Highlights
------------------------------
(all comparisons are to the second quarter of 2006)
Financial - US$
- Cash flow per share diluted increased 55 percent to $3.33, or
$2.55 billion (includes $0.17 billion, or 23 cents per share, of tax
recoveries due to legislative changes)
- Operating earnings per share diluted up 84 percent to $1.80, or
$1.38 billion (includes $0.23 billion, or 30 cents per share, of tax
recoveries due to legislative changes)
- Net earnings per share diluted down 26 percent to $1.89, or
$1.45 billion (in the second quarter of 2006 EnCana recorded about
$1.3 billion of non-operating gains, or $1.57 per share)
- Integrated oilsands business generated $500 million of operating cash
flow
- Core capital investment in continuing operations down 28 percent to
$1.17 billion
- Generated $1.38 billion of free cash flow (as defined in Note 1 on
page 7)
- Purchased approximately 12 million EnCana shares at an average price
of $59.23 under the Normal Course Issuer Bid
Operating - Upstream
- Natural gas production increased 4 percent to 3.51 billion cubic feet
per day (Bcf/d), up 14 percent per share
- Oil and natural gas liquids (NGLs) production up 1 percent on a pro
forma basis to more than 133,000 barrels per day (bbls/d), up
10 percent per share (see pro forma note 1, Production & Drilling
Summary, pg. 3)
- Total natural gas and liquids production increased 4 percent on a pro
forma basis to 4.31 billion cubic feet of gas equivalent per day
(Bcfe/d), up 13 percent per share
- Key natural gas resource play production up 12 percent
- Grew gross integrated oilsands production 43 percent to 56,000 bbls/d
(28,000 bbls/d net to EnCana) at Foster Creek and Christina Lake
- Operating and administrative costs of $1.17 per thousand cubic feet
equivalent (Mcfe) in line with guidance; an increase of 14 cents per
Mcfe compared to one year earlier, made up of 8 cents due to
increased long term compensation costs resulting from a higher EnCana
share price, 2 cents due to foreign exchange and 4 cents due to
inflation, energy and other activity-related costs
Operating - Downstream
- Refined products production averaged 421,000 bbls/d (210,500 bbls/d
net to EnCana)
- Refinery crude utilization of 88 percent is lower than the first
quarter of 2007 due to the planned turnaround and coker startup at
the Borger refinery. Year-to-date utilization is above expectations
at 92 percent largely due to a strong utilization rate of 100 percent
at the Wood River refinery.
- New 25,000 bbls/d Borger coker is operating well and is processing
Canadian heavy oil blended from bitumen
>>
Natural gas production on track with 2007 forecast
Natural gas production in the second quarter rose steadily with strong
year-over-year increases in a number of key resource plays - 49 percent in
East Texas, 37 percent in coalbed methane (CBM) and 31 percent in Cutbank
Ridge. EnCana's second largest resource play, Jonah, increased production
16 percent compared to one year ago. Gas production is currently about
3.5 Bcf/d, on track to achieve full-year guidance of 3.46 Bcf/d.
Integrated oilsands business has a strong start in 2007
The financial performance of EnCana's emerging integrated oilsands
business has been well above expectations to date, largely due to stronger
than anticipated refining margins. The second quarter U.S. Gulf Coast 3-2-1
crack spread averaged more than $24 per barrel, with the May average peaking
above $28 per barrel. Second quarter operating cash flow from the integrated
oilsands business was $500 million.
During the first quarter of 2007, the integrated oilsands business
delivered about 9 percent of EnCana's total operating cash flow. After six
months, that share has increased to about 14 percent, a notable rise to
$661 million, which is more than the company's original full-year forecast of
between $550 million and $650 million. As a result, EnCana has increased its
2007 guidance for integrated oilsands operating cash flow to $1.1 billion.
Updated guidance is posted on the company's website www.encana.com.
"Our shareholders have benefited from refinery margins that are well
above historical levels. While those margins are expected to soften in the
latter half of 2007 following the end of the summer driving season, they are
likely to stay strong for the foreseeable future due to limited spare refining
capacity, continued strong transportation fuels demand and a stable economy.
The financial performance of our integrated oilsands business in this, its
inaugural year, has exceeded our expectations and the operating performance is
tracking well against our objectives and targets - a great start to our newly
created partnership with ConocoPhillips," Eresman said.
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's financial statements are prepared in
accordance with Canadian generally accepted accounting principles (GAAP).

<<
-------------------------------------------------------------------------
Financial Summary - Total Consolidated
-------------------------------------------------------------------------
(for the period ended
June 30) 6 6
($ millions, except per Q2 Q2 % months months %
share amounts) 2007 2006 change 2007 2006 change
-------------------------------------------------------------------------
Cash flow(1) 2,549 1,815 +40 4,301 3,506 +23
Per share diluted 3.33 2.15 +55 5.56 4.10 +36
-------------------------------------------------------------------------
Operating earnings(1) 1,376 824 +67 2,234 1,518 +47
Per share diluted 1.80 0.98 +84 2.89 1.77 +63
-------------------------------------------------------------------------
Net earnings 1,446 2,157 -33 1,943 3,631 -46
Per share diluted 1.89 2.55 -26 2.51 4.24 -41
-------------------------------------------------------------------------
Core capital investment
from continuing
operations 1,172 1,632 -28 2,655 3,578 -26
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings Reconciliation Summary - Total Consolidated
-------------------------------------------------------------------------
Net earnings from
continuing operations 1,446 1,593 -9 1,943 3,065 -37
Net earnings from
discontinued operations - 564 n/a - 566 n/a
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net earnings (loss) 1,446 2,157 -33 1,943 3,631 -46
(Add back losses &
deduct gains)
Unrealized mark-to-market
hedging gain (loss),
after-tax 47 160 n/a (376) 990 n/a
Unrealized foreign exchange
gain (loss) on translation
of U.S. dollar Notes issued
from Canada, after-tax (14) 134 n/a (11) 131 n/a
Future tax recovery due
to Canada and Alberta tax
rates reductions 37 457 n/a 37 457 n/a
Gain on discontinuance,
after-tax - 582 n/a 59 535 n/a
-------------------------------------------------------------------------
Operating earnings(1) 1,376 824 +67 2,234 1,518 +47
Per share diluted 1.80 0.98 +84 2.89 1.77 +63
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Cash flow and Operating earnings are non-GAAP measures as defined in
Note 1 on page 7.

-------------------------------------------------------------------------
Production & Drilling Summary
-------------------------------------------------------------------------
Total Consolidated
-------------------------------------------------------------------------
(for the period ended 6 6
June 30) Q2 Q2 % months months %
(After royalties) 2007 2006(1) change 2007 2006(1) change
-------------------------------------------------------------------------
Natural Gas (MMcf/d) 3,506 3,361 +4 3,454 3,352 +3
-------------------------------------------------------------------------
Natural gas production
per 1,000 shares (Mcf) 421 369 +14 819 723 +13
-------------------------------------------------------------------------
Oil and NGLs (Mbbls/d) 133 132 +1 132 163 -19
-------------------------------------------------------------------------
Oil and NGLs production
per 1,000 shares (Mcfe) 96 87 +10 188 211 -11
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total Production
(MMcfe/d) 4,306 4,154 +4 4,246 4,328 -2
-------------------------------------------------------------------------
Total per 1,000 shares
(Mcfe) 517 456 +13 1,007 934 +8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net wells drilled 569 558 +2 1,833 1,836 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) 2006 information has been adjusted on a pro forma basis to reflect
the integrated oilsands transaction; the first six months of 2006
includes production from EnCana's Ecuador assets, which were sold in
the first quarter 2006.

Key natural gas resource play production up 12 percent from past year
Second quarter 2007 natural gas production from key North American
resource plays increased 12 percent to 2.67 Bcf/d compared to 2.38 Bcf/d in
the second quarter of 2006. This was driven mainly by double-digit production
increases in six of the company's nine gas resource plays, led by East Texas,
CBM in central and southern Alberta, Cutbank Ridge in northeast British
Columbia, Bighorn in west-central Alberta, Jonah in Wyoming and the Barnett
Shale play in the Fort Worth basin. Gross oilsands production from Foster
Creek and Christina Lake was up 43 percent to about 56,000 bbls/d (about
28,000 bbls/d net to EnCana). Overall, second quarter gas and oil resource
play production increased 8 percent in the past year (13 percent on a pro
forma basis as reflected in the table below).
Growth from key North American resource plays
-------------------------------------------------------------------------
Daily Production
-----------------------------------------------------------
Resource Play 2007 2006 2005
-----------------------------------------------------------
(After Full Full
royalties) YTD Q2 Q1 Year Q4 Q3 Q2 Q1 Year
-------------------------------------------------------------------------
Natural Gas
(MMcf/d)
Jonah 514 523 504 464 487 455 450 461 435
Piceance 342 349 334 326 335 331 324 316 307
East Texas 121 139 103 99 95 106 93 99 90
Fort Worth 115 124 106 101 99 104 108 93 70
Greater
Sierra 202 219 186 213 212 209 224 208 219
Cutbank
Ridge 218 226 210 170 199 167 173 140 92
Bighorn 109 115 104 91 99 97 95 72 55
CBM(1) 248 245 251 194 211 209 179 177 112
Shallow
Gas(2) 732 729 735 739 737 734 730 756 765
-------------------------------------------------------------------------
Total
natural gas
(MMcf/d) 2,601 2,669 2,533 2,397 2,474 2,412 2,376 2,322 2,145
-------------------------------------------------------------------------
Oil (Mbbls/d)
Foster
Creek(3) 23 25 20 18 21 19 16 18 14
Christina
Lake(3) 3 3 3 3 3 3 3 3 3
Pelican
Lake(4) 23 23 23 24 20 23 22 29 26
-------------------------------------------------------------------------
Total oil
(Mbbls/d) 49 51 46 45 44 45 41 50 43
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total
(MMcfe/d) 2,892 2,972 2,811 2,667 2,736 2,680 2,624 2,624 2,403
-------------------------------------------------------------------------
% change
from prior
period 5.7 2.7 11.0 2.1 2.1 - -2.9
-------------------------------------------------------------------------
(1) CBM integrated volumes were restated in 2006 to report commingled
volumes from the coal and sand intervals based on regulatory
approval.
(2) Shallow Gas volumes were restated in the first quarter 2007 to report
commingled volumes from multiple zones within the same geographic
area based upon regulatory approval.
(3) Foster Creek and Christina Lake volumes in 2006 and 2005 were
restated in the first quarter 2007 on a pro forma basis to reflect
the integrated oilsands transaction.
(4) Pelican Lake reached royalty payout in April 2006.

Drilling activity in key North American resource plays
-------------------------------------------------------------------------
Net Wells Drilled
-----------------------------------------------------------
Resource Play 2007 2006 2005
-----------------------------------------------------------
Full Full
YTD Q2 Q1 Year Q4 Q3 Q2 Q1 Year
-------------------------------------------------------------------------
Natural Gas
Jonah 81 42 39 163 41 48 48 26 104
Piceance 137 72 65 220 50 48 59 63 266
East Texas 18 11 7 59 11 12 17 19 84
Fort Worth 43 29 14 97 19 22 27 29 59
Greater
Sierra 55 32 23 115 5 16 34 60 164
Cutbank
Ridge 52 25 27 116 19 35 36 26 135
Bighorn 37 9 28 52 7 7 18 20 51
CBM(1) 426 18 408 729 157 156 35 381 1,245
Shallow
Gas(2) 657 241 416 1,310 389 475 217 229 1,389
-------------------------------------------------------------------------
Oil
Foster
Creek(3) 9 1 8 3 - - - 3 20
Christina
Lake(3) 2 2 - 1 - - - 1 -
Pelican
Lake - - - - - - - - 52
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total 1,517 482 1,035 2,865 698 819 491 857 3,568
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) CBM integrated net wells drilled were restated in 2006 to report
commingled volumes from the coal and sand intervals based on
regulatory approval.
(2) Shallow Gas net wells drilled were restated in the first quarter 2007
as a result of reporting commingled volumes from multiple zones
within the same geographic area based upon regulatory approval.
(3) Foster Creek and Christina Lake net wells drilled in 2006 and 2005
were restated in the first quarter 2007 on a pro forma basis to
reflect the integrated oilsands transaction.

-------------------------------------------------------------------------
Second quarter 2007 natural gas and oil prices
-------------------------------------------------------------------------
6 6
Q2 Q2 % months months %
2007 2006 change 2007 2006 change
-------------------------------------------------------------------------
Natural gas
($/Mcf, realized prices
include hedging)
NYMEX 7.55 6.78 +11 7.16 7.88 -9
EnCana Realized Gas Price 7.62 6.50 +17 7.43 6.82 +9
-------------------------------------------------------------------------
Oil and NGLs
($/bbl, realized prices
include hedging)
WTI 65.02 70.72 -8 61.68 67.13 -8
Western Canadian Select
(WCS) 45.84 53.17 -14 43.85 43.98 0
Differential WTI/WCS 19.18 17.55 +9 17.83 23.15 -23
EnCana Realized Liquids
Price 45.47 49.01 -7 44.02 39.66 +11
-------------------------------------------------------------------------
U.S. Gulf Coast 3-2-1
Crack Spread 24.28 17.26 +41 17.17 12.77 +34
-------------------------------------------------------------------------
>>
Price risk management
Risk management positions at June 30, 2007 are presented in Note 19 to
the unaudited Interim Consolidated Financial Statements. In the second quarter
of 2007, EnCana's commodity price risk management measures resulted in
realized gains of approximately $246 million after-tax, composed of a
$256 million gain on gas hedges and a $10 million loss on oil hedges.
About 0.7 Bcf/d of 2008 gas production hedged at $8.56 per Mcf
EnCana has hedged about 0.7 billion cubic feet per day of expected 2008
gas production, at a price of $8.56 per Mcf. For the last half of 2007, EnCana
has about 1.8 Bcf/d of gas production with downside price protection, composed
of 1.59 Bcf/d under fixed price contracts at an average NYMEX equivalent price
of $8.58 per Mcf and 240 million cubic feet per day with put options at a
NYMEX equivalent strike price of $6.00 per Mcf. EnCana has hedged
23,000 bbls/d of 2008 oil production at a price of WTI $70.13 per bbl. EnCana
also has about 126,000 bbls/d of 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. The basis hedges were transacted at an annual average differential of
NYMEX less $0.67 per Mcf. During the second quarter of 2007 the U.S. Rockies-
NYMEX natural gas price differential averaged $3.70 per Mcf. In Canada for
2007, EnCana has hedged 33 percent of its AECO basis differential at $0.72 per
Mcf. In the second quarter of 2007, the AECO basis differential averaged $0.90
per Mcf. During the second quarter, EnCana's basis hedging resulted in a
realized gain of about $306 million. EnCana has an additional 32 percent of
Canadian basis differential subject to transport and aggregator contracts.
Corporate developments
----------------------
Quarterly dividend of 20 cents per share approved
EnCana's board of directors has approved a quarterly dividend of 20 cents
per share, which is payable on September 28, 2007 to common shareholders of
record as of September 14, 2007.
EnCana Normal Course Issuer Bid purchases
Through the first six months of 2007, EnCana has purchased 35.4 million
shares at an average share price of US$51.10 under the company's Normal Course
Issuer Bid. This represents about 4.6 percent of shares outstanding as at
December 31, 2006. As at June 30, 2007, there were approximately 753 million
common shares issued and outstanding. During 2007, EnCana expects to purchase
about 5 percent of the shares outstanding as of the start of the year. 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 June 30, 2007, the
company's net debt-to-capitalization ratio was 29:71. EnCana's net debt-to-
adjusted-EBITDA multiple, on a trailing 12-month basis, was 0.8 times at the
end of the second quarter. The company expects its net debt-to-capitalization
ratio to remain at the lower end of the targeted range.
In the second quarter of 2007, EnCana invested $1,172 million of capital
in continuing operations. Net divestitures were $148 million, resulting in net
capital investment in continuing operations of $1,024 million.
-------------------------------------------------------------------------
CONFERENCE CALL TODAY
11 a.m. Mountain Time (1 p.m. Eastern Time)
EnCana Corporation will host a conference call today, Wednesday July 25,
2007 starting at 11:00 a.m. MT (1:00 p.m. ET). To participate, please
dial (866) 904-6908 (toll-free in North America) or (416) 915-8329
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 July 25 until midnight July 29, 2007 by dialing (866) 245-6755 or
(416) 915-1035 and entering access code 81286.
A live audio webcast of the conference call will also be available via
EnCana's website, www.encana.com, under Investor Relations. The webcast
will be archived for approximately 90 days.
-------------------------------------------------------------------------
<<
NOTE 1: Non-GAAP measures
This news release contains references to cash flow, 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.
- 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 from Canada,
and the partnership contribution receivable and the effect of the
reduction in income tax rates. Management believes that these
excluded items reduce the comparability of the company's underlying
financial performance between periods. The majority of the unrealized
gains/losses that relate to U.S. dollar denominated Notes issued from
Canada are for debt with maturity dates in excess of five years.
- Free cash flow is a non-GAAP measure that EnCana defines as cash flow
in excess of 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$55 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.
ADVISORY REGARDING FORWARD-LOOKING STATEMENTS - In the interests of
providing EnCana shareholders and potential investors with information
regarding EnCana, including management's assessment of EnCana's and its
subsidiaries' future plans and operations, certain statements contained in
this news release are forward-looking statements or information within the
meaning of applicable securities legislation, collectively referred to herein
as "forward-looking statements." Forward-looking statements in this news
release include, but are not limited to: future economic and operating
performance (including per share growth, net debt-to-capitalization ratio,
sustainable growth and returns, cash flow, cash flow per share and increases
in net asset value); anticipated ability to meet the company's guidance
forecasts; anticipated life of proved reserves; anticipated growth and success
of resource plays and the expected characteristics of resource plays; planned
expansion of in-situ oilsands production; anticipated crude oil and natural
gas prices, including basis differentials for various regions; the expected
impact of proposed Rockies Express Pipeline on Rockies basis differentials;
anticipated expansion and production at Foster Creek and Christina Lake;
anticipated increased capacity for the two U.S. refineries; anticipated
integrated oilsands cash flow; projections for future crack spreads and
anticipated refining profits; anticipated drilling inventory; expected
proportion of total production and cash flows contributed by natural gas;
anticipated success of EnCana's market risk mitigation strategy 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 June 30, 2007
EnCana Corporation
U.S. DOLLARS

CONSOLIDATED STATEMENT OF EARNINGS (unaudited)

Three Months Ended Six Months Ended
June 30, June 30,
($ millions, except per ---------------------------------------
share amounts) 2007 2006 2007 2006
-------------------------------------------------------------------------
REVENUES, NET OF ROYALTIES (Note 6)
Upstream $ 2,975 $ 2,591 $ 5,714 $ 5,195
Integrated Oilsands 1,867 276 3,423 465
Market Optimization 722 825 1,478 1,541
Corporate - Unrealized gain
(loss) on risk management 49 230 (566) 1,493
-------------------------------------------------------------------------
5,613 3,922 10,049 8,694
EXPENSES (Note 6)
Production and mineral taxes 57 51 149 190
Transportation and selling 234 270 512 524
Operating 565 395 1,116 807
Purchased product 1,836 794 3,687 1,483
Depreciation, depletion
and amortization 899 790 1,742 1,555
Administrative 95 75 190 133
Interest, net (Note 9) 94 83 195 171
Accretion of asset
retirement obligation (Note 15) 15 12 29 24
Foreign exchange
(gain) loss, net (Note 10) 7 (202) (5) (158)
(Gain) loss on
divestitures (Note 8) 1 (8) (58) (17)
-------------------------------------------------------------------------
3,803 2,260 7,557 4,712
-------------------------------------------------------------------------
NET EARNINGS BEFORE INCOME TAX 1,810 1,662 2,492 3,982
Income tax expense (Note 11) 364 69 549 917
-------------------------------------------------------------------------
NET EARNINGS FROM CONTINUING
OPERATIONS 1,446 1,593 1,943 3,065
NET EARNINGS FROM DISCONTINUED
OPERATIONS (Note 7) - 564 - 566
-------------------------------------------------------------------------
NET EARNINGS $ 1,446 $ 2,157 $ 1,943 $ 3,631
-------------------------------------------------------------------------
-------------------------------------------------------------------------
NET EARNINGS FROM CONTINUING
OPERATIONS PER COMMON
SHARE (Note 18)
Basic $ 1.91 $ 1.92 $ 2.54 $ 3.65
Diluted $ 1.89 $ 1.88 $ 2.51 $ 3.58
-------------------------------------------------------------------------
-------------------------------------------------------------------------
NET EARNINGS PER COMMON
SHARE (Note 18)
Basic $ 1.91 $ 2.60 $ 2.54 $ 4.33
Diluted $ 1.89 $ 2.55 $ 2.51 $ 4.24
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.

CONSOLIDATED STATEMENT OF RETAINED EARNINGS (unaudited)
Six Months Ended
June 30,
------------------
($ millions) 2007 2006
-------------------------------------------------------------------------
RETAINED EARNINGS, BEGINNING OF YEAR $ 11,344 $ 9,481
Net Earnings 1,943 3,631
Dividends on Common Shares (304) (146)
Charges for Normal Course Issuer Bid (Note 16) (1,421) (1,700)
-------------------------------------------------------------------------
RETAINED EARNINGS, END OF PERIOD $ 11,562 $ 11,266
-------------------------------------------------------------------------
-------------------------------------------------------------------------

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
--------------------------------------
($ millions) 2007 2006 2007 2006
-------------------------------------------------------------------------
NET EARNINGS $ 1,446 $ 2,157 $ 1,943 $ 3,631
OTHER COMPREHENSIVE INCOME,
NET OF TAX
Foreign Currency Translation
Adjustment 828 444 939 538
-------------------------------------------------------------------------
COMPREHENSIVE INCOME $ 2,274 $ 2,601 $ 2,882 $ 4,169
-------------------------------------------------------------------------
-------------------------------------------------------------------------

CONSOLIDATED STATEMENT OF ACCUMULATED OTHER COMPREHENSIVE INCOME
(unaudited)
Six Months Ended
June 30,
-----------------
($ millions) 2007 2006
-------------------------------------------------------------------------
ACCUMULATED OTHER COMPREHENSIVE INCOME, BEGINNING
OF YEAR $ 1,375 $ 1,262
Foreign Currency Translation Adjustment 939 538
-------------------------------------------------------------------------
ACCUMULATED OTHER COMPREHENSIVE INCOME, END OF
PERIOD $ 2,314 $ 1,800
-------------------------------------------------------------------------
-------------------------------------------------------------------------
As at June 30, 2007, the accumulated other comprehensive income consists
of foreign currency translation adjustments of $2,314 million
(December 31, 2006 - $1,375 million; June 30, 2006 - $1,800 million).
See accompanying Notes to Consolidated Financial Statements.

CONSOLIDATED BALANCE SHEET (unaudited)
As at As at
June 30, December 31,
($ millions) 2007 2006
-------------------------------------------------------------------------
ASSETS
Current Assets
Cash and cash equivalents $ 555 $ 402
Accounts receivable and
accrued revenues 2,244 1,721
Current portion of partnership
contribution receivable (Note 5, 12) 289 -
Risk management (Note 19) 913 1,403
Inventories (Note 13) 691 176
-------------------------------------------------------------------------
4,692 3,702
Property, Plant and Equipment,
net (Note 6) 30,263 28,213
Investments and Other Assets 566 533
Partnership Contribution
Receivable (Note 5, 12) 3,297 -
Risk Management (Note 19) 55 133
Goodwill 2,722 2,525
-------------------------------------------------------------------------
(Note 6) $ 41,595 $ 35,106
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued liabilities $ 3,526 $ 2,494
Income tax payable 749 926
Current portion of partnership
contribution payable (Note 5, 12) 280 -
Risk management (Note 19) 53 14
Current portion of long-term
debt (Note 14) 471 257
-------------------------------------------------------------------------
5,079 3,691
Long-Term Debt (Note 14) 6,955 6,577
Other Liabilities 180 79
Partnership Contribution
Payable (Note 5, 12) 3,309 -
Risk Management (Note 19) 13 2
Asset Retirement Obligation (Note 15) 1,177 1,051
Future Income Taxes 6,477 6,240
-------------------------------------------------------------------------
23,190 17,640
-------------------------------------------------------------------------
Shareholders' Equity
Share capital (Note 16) 4,472 4,587
Paid in surplus 57 160
Retained earnings 11,562 11,344
Accumulated other
comprehensive income 2,314 1,375
-------------------------------------------------------------------------
Total Shareholders' Equity 18,405 17,466
-------------------------------------------------------------------------
$ 41,595 $ 35,106
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.

CONSOLIDATED STATEMENT OF CASH FLOWS (unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
--------------------------------------
($ millions) 2007 2006 2007 2006
-------------------------------------------------------------------------
OPERATING ACTIVITIES
Net earnings from
continuing operations $ 1,446 $ 1,593 $ 1,943 $ 3,065
Depreciation, depletion
and amortization 899 790 1,742 1,555
Future income taxes (Note 11) 79 (228) (111) 289
Unrealized (gain) loss
on risk management (Note 19) (55) (230) 559 (1,491)
Unrealized foreign
exchange (gain) loss 70 (143) 59 (83)
Accretion of asset
retirement obligation (Note 15) 15 12 29 24
(Gain) loss on
divestitures (Note 8) 1 (8) (58) (17)
Other 94 53 138 76
Cash flow from
discontinued operations - (24) - 88
Net change in other
assets and liabilities (16) 38 4 27
Net change in non-cash
working capital from
continuing operations (365) 1,508 (228) 3,552
Net change in non-cash
working capital from
discontinued operations - (1,036) - (2,463)
-------------------------------------------------------------------------
Cash From Operating Activities 2,168 2,325 4,077 4,622
-------------------------------------------------------------------------
INVESTING ACTIVITIES
Capital expenditures (Note 6) (1,189) (1,903) (2,679) (3,864)
Proceeds on disposal
of assets (Note 8) 165 2 446 257
Net change in investments
and other (25) (59) (6) 18
Net change in non-cash
working capital from
continuing operations (45) (270) (103) (151)
Discontinued operations - 1,064 - 2,377
-------------------------------------------------------------------------
Cash (Used in) Investing
Activities (1,094) (1,166) (2,342) (1,363)
-------------------------------------------------------------------------
FINANCING ACTIVITIES
Net issuance (repayment)
of revolving long-term debt (40) (101) (38) (982)
Issuance of long-term debt - - 432 -
Issuance of common
shares (Note 16) 77 49 153 101
Purchase of common
shares (Note 16) (713) (1,095) (1,807) (2,073)
Dividends on common
shares (151) (82) (304) (146)
Other (14) (1) (3) (11)
-------------------------------------------------------------------------
Cash (Used in) Financing
Activities (841) (1,230) (1,567) (3,111)
-------------------------------------------------------------------------
DEDUCT: FOREIGN EXCHANGE LOSS
ON CASH AND CASH EQUIVALENTS
HELD IN FOREIGN CURRENCY 15 - 15 -
-------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS 218 (71) 153 148
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD 337 324 402 105
-------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS,
END OF PERIOD $ 555 $ 253 $ 555 $ 253
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 June 30, 2007 period
end accumulated foreign currency translation adjustment balance of
$2,314 million has been reclassified to AOCI (December 31, 2006 -
$1,375 million; June 30, 2006 - $1,800 million). In addition, the change
in the accumulated foreign currency translation adjustment balance for
the three months and six months ended June 30, 2007 of $828 million and
$939 million, respectively, is now included in OCI in the Statement of
Comprehensive Income (three months and six months ended June 30, 2006 -
$444 million and $538 million, respectively).
Financial Instruments
The financial instruments standard establishes the recognition and
measurement criteria for financial assets, financial liabilities and
derivatives. All financial instruments are required to be measured at
fair value on initial recognition of the instrument, except for certain
related party transactions. Measurement in subsequent periods depends on
whether the financial instrument has been classified as
"held-for-trading", "available-for-sale", "held-to-maturity", "loans and
receivables", or "other financial liabilities" as defined by the
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 financial liabilities".
The adoption of the financial instruments standard has been made in
accordance with its transitional provisions. Accordingly, at January 1,
2007, $52 million of other assets were reclassified to long-term debt to
reflect the adopted policy of capitalizing long-term debt transaction
costs, premiums and discounts within long-term debt. The costs
capitalized within long-term debt will be amortized using the effective
interest method. Previously, the Company deferred these costs within
other assets and amortized them straight-line over the life of the
related long-term debt. The adoption of the effective interest method of
amortization had no effect on opening retained earnings.
Risk management assets and liabilities are derivative financial
instruments classified as "held-for-trading" unless designated for hedge
accounting. Additional information on the Company's accounting treatment
of derivative financial instruments is contained in Note 1 of the
Company's annual audited Consolidated Financial Statements for the year
ended December 31, 2006.
3. UPDATE TO ACCOUNTING POLICIES AND PRACTICES
As a result of the new joint venture with ConocoPhillips, EnCana has
updated the following significant accounting policies and practices to
incorporate the refining business (see Note 5):
Revenue Recognition
Revenues associated with the sales of EnCana's natural gas, crude oil,
NGLs and petroleum and chemical products are recognized when title passes
from the Company to its customer. Natural gas and crude oil produced and
sold by EnCana below or above its working interest share in the related
resource properties results in production underliftings or overliftings.
Underliftings are recorded as inventory and overliftings are recorded as
deferred revenue. Realized gains and losses from the Company's natural
gas and crude oil commodity price risk management activities are recorded
in revenue when the product is sold.
Market optimization revenues and purchased product are recorded on a
gross basis when EnCana takes title to product and has risks and rewards
of ownership. Purchases and sales of inventory with the same counterparty
that are entered into in contemplation of each other are recorded on a
net basis. Revenues associated with the services provided where EnCana
acts as agent are recorded as the services are provided. Revenues
associated with the sale of natural gas storage services are recognized
when the services are provided. Sales of electric power are recognized
when power is provided to the customer.
Unrealized gains and losses from the Company's natural gas and crude oil
commodity price risk management activities are recorded as revenue based
on the related mark-to-market calculations at the end of the respective
period.
Inventory
Product inventories, including petroleum and chemical products, are
valued at the lower of average cost and net realizable value on a
first-in, first-out basis. 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 straight-line 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. RECENT ACCOUNTING PRONOUNCEMENT
As of January 1, 2008, EnCana is required to adopt the CICA Section 3031
"Inventories", which will replace the existing inventories standard. The
new standard requires inventory to be valued on a first-in, first-out or
weighted average basis. As EnCana's inventory accounting policies are
consistent with these requirements, the application of this standard will
not have a material impact on the Consolidated Financial Statements.
5. 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 12.
In accordance with Canadian generally accepted accounting principles,
these entities have been accounted for using the proportionate
consolidation method with the results of operations shown in a separate
business segment, Integrated Oilsands.
6. SEGMENTED INFORMATION
The Company has defined its continuing operations into the following
segments:
- Canada, United States and Other includes the Company's upstream
exploration for, and development and production of natural gas, crude
oil and natural gas liquids and other related activities. The
majority of the Company's upstream operations are located in Canada
and the United States. Offshore and international exploration is
mainly focused on opportunities in 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 7.
Results of Continuing Operations (For the three months ended June 30)
Upstream
-----------------------------------------------
Canada United States Other
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of
Royalties $1,829 $1,758 $1,059 $ 766 $ 87 $ 67
Expenses
Production and mineral
taxes 31 24 26 27 - -
Transportation and
selling 83 78 77 52 - -
Operating 243 208 85 75 73 50
Purchased product - - - - - -
Depreciation, depletion
and amortization 524 500 275 216 6 12
-------------------------------------------------------------------------
Segment Income $ 948 $ 948 $ 596 $ 396 $ 8 $ 5
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Total Integrated Market
Upstream Oilsands Optimization
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of
Royalties $2,975 $2,591 $1,867 $ 276 $ 722 $ 825
Expenses
Production and
mineral taxes 57 51 - - - -
Transportation and
selling 160 130 72 130 2 10
Operating 401 333 161 50 10 13
Purchased product - - 1,134 - 702 794
Depreciation, depletion
and amortization 805 728 69 40 4 2
-------------------------------------------------------------------------
Segment Income $1,552 $1,349 $ 431 $ 56 $ 4 $ 6
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Corporate Consolidated
-------------------------------------------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of Royalties $ 49 $ 230 $5,613 $3,922
Expenses
Production and mineral taxes - - 57 51
Transportation and selling - - 234 270
Operating (7) (1) 565 395
Purchased product - - 1,836 794
Depreciation, depletion and
amortization 21 20 899 790
-------------------------------------------------------------------------
Segment Income $ 35 $ 211 2,022 1,622
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Administrative 95 75
Interest, net 94 83
Accretion of asset retirement obligation 15 12
Foreign exchange (gain) loss, net 7 (202)
(Gain) loss on divestitures 1 (8)
-------------------------------------------------------------------------
212 (40)
-------------------------------------------------------------------------
Net Earnings Before Income Tax 1,810 1,662
Income tax expense 364 69
-------------------------------------------------------------------------
Net Earnings From Continuing Operations $1,446 $1,593
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Results of Continuing Operations (For the three months ended June 30)
Geographic and Product Information (Continuing Operations)
Produced Gas
-------------------------------------------------------------------------
Canada United States Total
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of
Royalties $1,446 $1,296 $ 989 $ 695 $2,435 $1,991
Expenses
Production and mineral
taxes 22 15 20 23 42 38
Transportation and
selling 73 71 77 52 150 123
Operating 180 153 85 75 265 228
-------------------------------------------------------------------------
Operating Cash Flow $1,171 $1,057 $ 807 $ 545 $1,978 $1,602
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Oil & NGLs
-------------------------------------------------------------------------
Canada United States Total
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of
Royalties $ 383 $ 462 $ 70 $ 71 $ 453 $ 533
Expenses
Production and
mineral taxes 9 9 6 4 15 13
Transportation and
selling 10 7 - - 10 7
Operating 63 55 - - 63 55
-------------------------------------------------------------------------
Operating Cash Flow $ 301 $ 391 $ 64 $ 67 $ 365 $ 458
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Integrated Oilsands
-------------------------------------------------------------------------
Downstream
Oil Refining Other
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of
Royalties $ 172 $ 271 $1,717 $ - $ (22) $ 5
Expenses
Transportation and
selling 72 130 - - - -
Operating 39 44 119 - 3 6
Purchased product - - 1,157 - (23) -
-------------------------------------------------------------------------
Operating Cash Flow $ 61 $ 97 $ 441 $ - $ (2) $ (1)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Integrated
Oilsands
-------------------------------------------------------------------------
Total
-------------------------------------------------------------------------
2007 2006
-------------------------------------------------------------------------
Revenues, Net of Royalties $1,867 $ 276
Expenses
Transportation and selling 72 130
Operating 161 50
Purchased product 1,134 -
-------------------------------------------------------------------------
Operating Cash Flow $ 500 $ 96
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Results of Continuing Operations (For the six months ended June 30)
Upstream
-----------------------------------------------
Canada United States Other
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of
Royalties $3,592 $3,507 $1,944 $1,545 $ 178 $ 143
Expenses
Production and mineral
taxes 59 69 90 121 - -
Transportation and
selling 163 146 143 118 - -
Operating 480 421 160 143 154 117
Purchased product - - - - - -
Depreciation, depletion
and amortization 1,014 990 535 426 12 19
-------------------------------------------------------------------------
Segment Income $1,876 $1,881 $1,016 $ 737 $ 12 $ 7
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Total Integrated Market
Upstream Oilsands Optimization
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of
Royalties $5,714 $5,195 $3,423 $ 465 $1,478 $1,541
Expenses
Production and
mineral taxes 149 190 - - - -
Transportation and
selling 306 264 196 247 10 13
Operating 794 681 313 95 17 31
Purchased product - - 2,253 - 1,434 1,483
Depreciation, depletion
and amortization 1,561 1,435 135 77 7 5
-------------------------------------------------------------------------
Segment Income $2,904 $2,625 $ 526 $ 46 $ 10 $ 9
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Corporate Consolidated
-------------------------------------------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of Royalties $ (566) $1,493 $10,049 $8,694
Expenses
Production and mineral taxes - - 149 190
Transportation and selling - - 512 524
Operating (8) - 1,116 807
Purchased product - - 3,687 1,483
Depreciation, depletion and
amortization 39 38 1,742 1,555
-------------------------------------------------------------------------
Segment Income (Loss) $ (597) $1,455 2,843 4,135
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Administrative 190 133
Interest, net 195 171
Accretion of asset retirement obligation 29 24
Foreign exchange (gain) loss, net (5) (158)
(Gain) loss on divestitures (58) (17)
-------------------------------------------------------------------------
351 153
-------------------------------------------------------------------------
Net Earnings Before Income Tax 2,492 3,982
Income tax expense 549 917
-------------------------------------------------------------------------
Net Earnings From Continuing Operations $1,943 $3,065
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Results of Continuing Operations (For the six months ended June 30)
Geographic and Product Information (Continuing Operations)
Produced Gas
-------------------------------------------------------------------------
Canada United States Total
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of
Royalties $2,834 $2,737 $1,820 $1,413 $4,654 $4,150
Expenses
Production and mineral
taxes 42 51 78 112 120 163
Transportation and
selling 143 138 143 118 286 256
Operating 357 306 160 143 517 449
-------------------------------------------------------------------------
Operating Cash Flow $2,292 $2,242 $1,439 $1,040 $3,731 $3,282
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Oil & NGLs
-------------------------------------------------------------------------
Canada United States Total
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of
Royalties $ 758 $ 770 $ 124 $ 132 $ 882 $ 902
Expenses
Production and mineral
taxes 17 18 12 9 29 27
Transportation and
selling 20 8 - - 20 8
Operating 123 115 - - 123 115
-------------------------------------------------------------------------
Operating Cash Flow $ 598 $ 629 $ 112 $ 123 $ 710 $ 752
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Integrated Oilsands
-------------------------------------------------------------------------
Downstream
Oil Refining Other
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of
Royalties $ 392 $ 454 $3,060 $ - $ (29) $ 11
Expenses
Transportation and
selling 196 247 - - - -
Operating 88 82 219 - 6 13
Purchased product - - 2,291 - (38) -
-------------------------------------------------------------------------
Operating Cash Flow $ 108 $ 125 $ 550 $ - $ 3 $ (2)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Integrated
Oilsands
-------------------------------------------------------------------------
Total
-------------------------------------------------------------------------
2007 2006
-------------------------------------------------------------------------
Revenues, Net of Royalties $3,423 $ 465
Expenses
Transportation and selling 196 247
Operating 313 95
Purchased product 2,253 -
-------------------------------------------------------------------------
Operating Cash Flow $ 661 $ 123
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Capital Expenditures (Continuing Operations)
Three Months Ended Six Months Ended
June 30, June 30,
----------------------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Core Capital
Canada $ 591 $ 778 $ 1,462 $ 1,907
United States 422 633 861 1,170
Other 29 21 37 39
Integrated Oilsands 110 175 225 395
Market Optimization 2 9 3 38
Corporate 18 16 67 29
-------------------------------------------------------------------------
1,172 1,632 2,655 3,578
-------------------------------------------------------------------------
Acquisition Capital
Canada - - 7 8
United States 3 250 3 257
Integrated Oilsands 14 21 14 21
-------------------------------------------------------------------------
17 271 24 286
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total $ 1,189 $ 1,903 $ 2,679 $ 3,864
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Property, Plant and Equipment and Total Assets
Property, Plant
and Equipment Total Assets
-------------------------------------------------------
As at As at
-------------------------------------------------------
June 30, December 31, June 30, December 31,
2007 2006 2007 2006
-------------------------------------------------------------------------
Canada $ 16,385 $ 17,702 $ 17,608 $ 19,060
United States 8,797 8,494 9,268 9,036
Other 147 263 226 300
Integrated Oilsands 4,432 1,322 9,392 1,379
Market Optimization 165 154 430 468
Corporate 337 278 4,671 4,863
-------------------------------------------------------------------------
Total $ 30,263 $ 28,213 $ 41,595 $ 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 $75 million related to this office project as
an asset under construction. A corresponding liability is included in
Other Liabilities in the Consolidated Balance Sheet. There is no effect
on the Company's net earnings or cash flows related to the capitalization
of The Bow office project.
7. DISCONTINUED OPERATIONS
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 June 30,
--------------------------------------------------------
United
Ecuador Kingdom Midstream Total
--------------------------------------------------------
2007 2006 2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of
Royalties $ - $ - $ - $ - $ - $ 28 $ - $ 28
-------------------------------------------------------------------------
Expenses
Production and
mineral taxes - - - - - - - -
Transportation
and selling - - - - - - - -
Operating - - - - - 10 - 10
Purchased
product - - - - - - - -
Depreciation,
depletion and
amortization - - - - - - - -
Interest, net - - - - - - - -
Foreign exchange
(gain) loss, net - - - (1) - 9 - 8
(Gain) loss on
discontinuance - 232 - - - (768) - (536)
-------------------------------------------------------------------------
- 232 - (1) - (749) - (518)
-------------------------------------------------------------------------
Net Earnings (Loss)
Before Income Tax - (232) - 1 - 777 - 546
Income tax
expense - - - 2 - (20) - (18)
-------------------------------------------------------------------------
Net Earnings (Loss)
From Discontinued
Operations $ - $(232) $ - $ (1) $ - $ 797 $ - $ 564
-------------------------------------------------------------------------
-------------------------------------------------------------------------

For the six months ended June 30,
--------------------------------------------------------
United
Ecuador Kingdom Midstream Total
--------------------------------------------------------
2007 2006 2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of
Royalties(x) $ - $ 200 $ - $ - $ - $ 463 $ - $ 663
-------------------------------------------------------------------------
Expenses
Production and
mineral taxes - 23 - - - - - 23
Transportation
and selling - 10 - - - - - 10
Operating - 25 - - - 29 - 54
Purchased product - - - - - 354 - 354
Depreciation,
depletion and
amortization - 84 - - - - - 84
Interest, net - (2) - - - - - (2)
Foreign exchange
(gain) loss,
net - 1 - - - 9 - 10
(Gain) loss on
discontinuance - 279 - - - (768) - (489)
-------------------------------------------------------------------------
- 420 - - - (376) - 44
-------------------------------------------------------------------------
Net Earnings (Loss)
Before Income Tax - (220) - - - 839 - 619
Income tax
expense - 59 - 2 - (8) - 53
-------------------------------------------------------------------------
Net Earnings (Loss)
From Discontinued
Operations $ - $(279) $ - $ (2) $ - $ 847 $ - $ 566
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x) Revenues, net of royalties in Ecuador for 2006 include realized
losses of $1 million related to derivative financial instruments.

Contingencies
EnCana agreed to indemnify the purchaser of its Ecuador interests against
losses that may arise in certain circumstances which are defined in the
share sale agreements. The obligation to indemnify will arise should
losses exceed amounts specified in the sale agreements and is limited to
maximum amounts which are set forth in the share sale agreements.
During the second quarter of 2006, the Government of Ecuador seized the
Block 15 assets, in relation to which EnCana previously held a 40 percent
economic interest, from the operator which is an event requiring
indemnification under the terms of EnCana's sale agreement with the
purchaser. The purchaser requested payment and EnCana paid the maximum
amount in the third quarter, calculated in accordance with the terms of
the agreements, of approximately $265 million. EnCana does not expect
that any further significant indemnification payments relating to any
other business matters addressed in the share sale agreements will be
required to be made to the purchaser.
8. DIVESTITURES
Total year-to-date proceeds received on sale of assets and investments
were $446 million (2006 - $257 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 $23 million (2006 -
$13 million).
Other
In May 2007, the Company completed the sale of certain assets in the
Mackenzie Delta and Beaufort Sea for proceeds of $159 million.
In January 2007, the Company completed the sale of its interests in Chad,
properties that 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 6 for further discussion of The Bow office
project assets.
9. INTEREST, NET
Three Months Ended Six Months Ended
June 30, June 30,
---------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Interest Expense - Long-Term Debt $ 118 $ 87 $ 218 $ 181
Interest Expense - Other(x) 43 5 106 10
Interest Income(x) (67) (9) (129) (20)
-------------------------------------------------------------------------
$ 94 $ 83 $ 195 $ 171
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x) In 2007, Interest Expense - Other and Interest Income are primarily
due to the Partnership Contribution Payable and Receivable,
respectively. See Note 12.

10. FOREIGN EXCHANGE (GAIN) LOSS, NET
Three Months Ended Six Months Ended
June 30, June 30,
---------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Unrealized Foreign Exchange
(Gain) Loss on:
Translation of U.S. dollar
debt issued from Canada $ (289) $ (163) $ (330) $ (159)
Translation of U.S. dollar
partnership contribution
receivable issued from Canada 305 - 343 -
Other Foreign Exchange (Gain) Loss (9) (39) (18) 1
-------------------------------------------------------------------------
$ 7 $ (202) $ (5) $ (158)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

11. INCOME TAXES
The provision for income taxes is as follows:
Three Months Ended Six Months Ended
June 30, June 30,
---------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Current
Canada $ 61 $ 281 $ 343 $ 589
United States 220 13 312 36
Other Countries 4 3 5 3
-------------------------------------------------------------------------
Total Current Tax 285 297 660 628
-------------------------------------------------------------------------
Future 79 (228) (111) 289
-------------------------------------------------------------------------
$ 364 $ 69 $ 549 $ 917
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The following table reconciles income taxes calculated at the Canadian
statutory rate with the actual income taxes:
Three Months Ended Six Months Ended
June 30, June 30,
---------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Net Earnings Before Income Tax $ 1,810 $ 1,662 $ 2,492 $ 3,982
Canadian Statutory Rate 32.3% 34.8% 32.3% 34.8%
-------------------------------------------------------------------------
Expected Income Tax 585 578 805 1,384
Effect on Taxes Resulting from:
Non-deductible Canadian Crown
payments - 21 - 52
Canadian resource allowance - 2 - (18)
Statutory and other rate
differences 19 (1) 24 (17)
Effect of tax rate changes(x) (37) (457) (37) (457)
Effect of legislative changes (231) - (231) -
Non-taxable downstream partnership
income (13) - (19) -
Non-taxable capital (gains)
losses 8 (32) (12) (33)
Large corporations tax - (1) - -
Other 33 (41) 19 6
-------------------------------------------------------------------------
$ 364 $ 69 $ 549 $ 917
-------------------------------------------------------------------------
Effective Tax Rate 20.1% 4.2% 22.0% 23.0%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x) The Canadian federal government, during the second quarters of 2007
and 2006, and the Alberta government, during the second quarter of
2006, enacted income tax rate changes.

12. 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.
13. INVENTORIES
As at As at
June 30, December 31,
2007 2006
-------------------------------------------------------------------------
Product
Canada $ - $ 42
Integrated Oilsands 561 8
Market Optimization 130 126
-------------------------------------------------------------------------
$ 691 $ 176
-------------------------------------------------------------------------
-------------------------------------------------------------------------

14. LONG-TERM DEBT
As at As at
June 30, December 31,
2007 2006
-------------------------------------------------------------------------
Canadian Dollar Denominated Debt
Revolving credit and term loan borrowings $ 1,336 $ 1,456
Unsecured notes 1,340 793
-------------------------------------------------------------------------
2,676 2,249
-------------------------------------------------------------------------
U.S. Dollar Denominated Debt
Revolving credit and term loan borrowings 325 104
Unsecured notes 4,421 4,421
-------------------------------------------------------------------------
4,746 4,525
-------------------------------------------------------------------------
Increase in Value of Debt Acquired(x) 63 60
Debt Discounts and Financing Costs (59) -
Current Portion of Long-Term Debt (471) (257)
-------------------------------------------------------------------------
$ 6,955 $ 6,577
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x) Certain of the notes and debentures of EnCana were acquired in
business combinations and were accounted for at their fair value at
the dates of acquisition. The difference between the fair value and
the principal amount of the debt is being amortized over the
remaining life of the outstanding debt acquired, approximately
21 years.

On March 12, 2007, EnCana completed a public offering in Canada of senior
unsecured medium term notes in the aggregate principal amount of
C$500 million. The notes have a coupon rate of 4.3 percent and mature on
March 12, 2012.
15. ASSET RETIREMENT OBLIGATION
The following table presents the reconciliation of the beginning and
ending aggregate carrying amount of the obligation associated with the
retirement of oil and gas assets and refining facilities:
As at As at
June 30, December 31,
2007 2006
-------------------------------------------------------------------------
Asset Retirement Obligation, Beginning of Year $ 1,051 $ 816
Liabilities Incurred 36 68
Liabilities Settled (33) (51)
Change in Estimated Future Cash Flows 4 172
Accretion Expense 29 50
Other 90 (4)
-------------------------------------------------------------------------
Asset Retirement Obligation, End of Period $ 1,177 $ 1,051
-------------------------------------------------------------------------
-------------------------------------------------------------------------
16. SHARE CAPITAL
June 30, 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 7.4 153 8.6 179
Stock-based Compensation - 12 - 11
Common Shares Purchased (32.5) (280) (85.6) (734)
-------------------------------------------------------------------------
Common Shares Outstanding,
End of Period 752.8 $ 4,472 777.9 $ 4,587
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Normal Course Issuer Bid
To June 30, 2007, the Company purchased 35.4 million Common Shares for
total consideration of approximately $1,807 million. Of the amount paid,
$304 million was charged to Share capital and $1,503 million was charged
to Retained earnings. Included in the Common Shares Purchased in 2007 are
2.9 million Common Shares distributed, valued at $24 million, from the
EnCana Employee Benefit Plan Trust that vested under EnCana's Performance
Share Unit Plan (see Note 17). For these Common Shares distributed, there
was an $82 million adjustment to Retained earnings with a reduction to
Paid in surplus of $106 million.
EnCana has received regulatory approval each year under Canadian
securities laws to purchase Common Shares under five consecutive Normal
Course Issuer Bids ("Bids"). EnCana is entitled to purchase, for
cancellation, up to approximately 80.2 million Common Shares under the
renewed Bid which commenced on November 6, 2006 and terminates on
November 5, 2007.
Stock Options
EnCana has stock-based compensation plans that allow employees and
directors to purchase Common Shares of the Company. Option exercise
prices approximate the market price for the Common Shares on the date the
options were issued. Options granted under the plans are generally fully
exercisable after three years and expire five years after the date
granted. Options granted under predecessor and/or related company
replacement plans expire up to 10 years from the date the options were
granted.
The following tables summarize the information about options to purchase
Common Shares that do not have Tandem Share Appreciation Rights ("TSARs")
attached to them at June 30, 2007. Information related to TSARs is
included in Note 17.
Weighted
Stock Average
Options Exercise
(millions) Price (C$)
-------------------------------------------------------------------------
Outstanding, Beginning of Year 11.8 23.17
Exercised (7.4) 23.79
Forfeited (0.1) 22.90
-------------------------------------------------------------------------
Outstanding, End of Period 4.3 22.13
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Exercisable, End of Period 4.3 22.13
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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 0.6 2.3 11.58 0.6 11.58
17.00 to 22.99 0.1 0.9 22.54 0.1 22.54
23.00 to 23.99 3.3 0.8 23.88 3.3 23.88
24.00 to 24.99 0.2 0.9 24.43 0.2 24.43
25.00 to 25.99 0.1 1.2 25.62 0.1 25.62
-------------------------------------------------------------------------
4.3 1.1 22.13 4.3 22.13
-------------------------------------------------------------------------
-------------------------------------------------------------------------
At June 30, 2007, the balance in Paid in surplus relates to stock-based
compensation programs.
17. COMPENSATION PLANS
The tables below outline certain information related to EnCana's
compensation plans at June 30, 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 Six Months Ended
June 30, June 30,
---------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Current Service Cost $ 4 $ 4 $ 8 $ 7
Interest Cost 5 4 9 8
Expected Return on Plan Assets (5) (4) (9) (8)
Expected Actuarial Loss on
Accrued Benefit Obligation 1 2 2 3
Expected Amortization of Past
Service Costs 1 - 1 1
Amortization of Transitional
Obligation (1) (1) (1) (1)
Expense for Defined Contribution
Plan 9 6 16 11
-------------------------------------------------------------------------
Net Benefit Plan Expense $ 14 $ 11 $ 26 $ 21
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the period ended June 30, 2007, contributions of $4 million have been
made to the defined benefit pension plans (2006 - $6 million).
B) Share Appreciation Rights ("SARs")
The following table summarizes the information about SARs at June 30,
2007:
Weighted
Average
Outstanding Exercise
SARs Price
-------------------------------------------------------------------------
U.S. Dollar Denominated (US$)
Outstanding, Beginning of Year 2,088 14.21
Exercised (2,088) 14.21
-------------------------------------------------------------------------
Outstanding, End of Period - -
-------------------------------------------------------------------------
Exercisable, End of Period - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the period ended June 30, 2007, EnCana has not recorded any
compensation costs related to the outstanding SARs (2006 - nil).
C) Tandem Share Appreciation Rights ("TSARs")
The following table summarizes the information about TSARs at June 30,
2007:
Weighted
Average
Outstanding Exercise
TSARs Price
-------------------------------------------------------------------------
Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 17,276,191 44.99
Granted 4,236,038 56.79
Exercised - SARs (1,549,509) 40.96
Exercised - Options (7,405) 39.82
Forfeited (816,702) 42.42
-------------------------------------------------------------------------
Outstanding, End of Period 19,138,613 45.95
-------------------------------------------------------------------------
Exercisable, End of Period 5,337,229 42.60
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the period ended June 30, 2007, EnCana recorded compensation costs of
$157 million related to the outstanding TSARs (2006 - $58 million).
D) Performance-based Tandem Share Appreciation Rights ("Performance
TSARs")
In 2007, under the terms of the existing Employee Stock Option Plan,
EnCana granted Performance TSARs under which the employee has the right
to receive a cash payment equal to the excess of the market price of
EnCana Common Shares at the time of exercise over the grant price.
Performance TSARs vest and expire under the same terms and service
conditions as the underlying option, and vesting is subject to the
Company attaining prescribed performance as measured by the annual
recycle ratio. Performance TSARs vest proportionately for a recycle ratio
of greater than one; the maximum number of Performance TSARs vest if the
recycle ratio is three or greater.
The following table summarizes the information about Performance TSARs at
June 30, 2007:
Weighted
Average
Outstanding Exercise
TSARs Price
-------------------------------------------------------------------------
Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year - -
Granted 7,275,575 56.09
Forfeited (268,200) 56.09
-------------------------------------------------------------------------
Outstanding, End of Period 7,007,375 56.09
-------------------------------------------------------------------------
Exercisable, End of Period - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the period ended June 30, 2007, EnCana recorded compensation costs of
$9 million related to the outstanding Performance TSARs.
E) Deferred Share Units ("DSUs")
The following table summarizes the information about DSUs at June 30,
2007:
Average
Outstanding Share
DSUs Price
-------------------------------------------------------------------------
Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 866,577 29.56
Granted, Directors 77,081 56.80
Exercised (334,615) 29.56
Units, in Lieu of Dividends 5,497 61.09
-------------------------------------------------------------------------
Outstanding, End of Period 614,540 33.26
-------------------------------------------------------------------------
Exercisable, End of Period 614,540 33.26
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the period ended June 30, 2007, EnCana recorded compensation costs of
$11 million related to the outstanding DSUs (2006 - $8 million).
F) Performance Share Units ("PSUs")
The following table summarizes the information about PSUs at June 30,
2007:
Average
Outstanding Share
PSUs Price
-------------------------------------------------------------------------
Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 4,766,329 27.48
Granted 12,462 60.62
Distributed (2,937,491) 24.05
Forfeited (146,735) 33.74
-------------------------------------------------------------------------
Outstanding, End of Period 1,694,565 33.12
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the period ended June 30, 2007, EnCana recorded compensation costs of
$15 million related to the outstanding PSUs (2006 - reduction to
compensation costs of $1 million).
At June 30, 2007, EnCana has approximately 2.6 million Common Shares held
in trust for issuance upon vesting of the PSUs (2006 - 5.5 million).
18. PER SHARE AMOUNTS
The following table summarizes the Common Shares used in calculating Net
Earnings per Common Share:
Three Months Ended Six Months Ended
------------------------------------------
March 31, June 30, June 30,
------------------------------------------
(millions) 2007 2007 2006 2007 2006
-------------------------------------------------------------------------
Weighted Average Common Shares
Outstanding - Basic 768.4 758.5 829.6 763.5 838.7
Effect of Dilutive Securities 11.2 6.7 15.5 9.7 16.7
-------------------------------------------------------------------------
Weighted Average Common Shares
Outstanding - Diluted 779.6 765.2 845.1 773.2 855.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------

19. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
As a means of managing commodity price volatility, EnCana entered into
various financial instrument agreements and physical contracts. The
following information presents all positions for financial instruments.
Realized and Unrealized Gain (Loss) on Risk Management Activities
The following tables summarize the gains and losses on risk management
activities:
Realized Gain (Loss)
---------------------------------------
Three Months Ended Six Months Ended
June 30, June 30,
---------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of Royalties $ 382 $ 160 $ 697 $ (46)
Operating Expenses and Other - 2 1 3
-------------------------------------------------------------------------
Gain (Loss) on Risk Management -
Continuing Operations 382 162 698 (43)
Gain (Loss) on Risk Management -
Discontinued Operations - 3 - 4
-------------------------------------------------------------------------
$ 382 $ 165 $ 698 $ (39)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Unrealized Gain (Loss)
---------------------------------------
Three Months Ended Six Months Ended
June 30, June 30,
---------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of Royalties $ 49 $ 230 $ (566) $ 1,493
Operating Expenses and Other 6 - 7 (2)
-------------------------------------------------------------------------
Gain (Loss) on Risk Management -
Continuing Operations 55 230 (559) 1,491
Gain (Loss) on Risk Management -
Discontinued Operations - (1) - 22
-------------------------------------------------------------------------
$ 55 $ 229 $ (559) $ 1,513
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 June 30, 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 132 132
Fair Value of Contracts in Place at Transition
that Expired During 2007 - 7
Fair Value of Contracts Realized During 2007 (698) (698)
-------------------------------------------------------------------------
Fair Value of Contracts Outstanding $ 850 $ (559)
Paid Premiums on Unexpired Options 52
-------------------------------------------------------------------------
Fair Value of Contracts and Premiums Paid,
End of Period $ 902
-------------------------------------------------------------------------
-------------------------------------------------------------------------
At June 30, 2007, the risk management amounts are recorded in the
Consolidated Balance Sheet as follows:
As at
June 30, 2007
-------------------------------------------------------------------------
Risk Management
Current asset $ 913
Long-term asset 55
Current liability 53
Long-term liability 13
-------------------------------------------------------------------------
Net Risk Management Asset $ 902
-------------------------------------------------------------------------
-------------------------------------------------------------------------
A summary of all unrealized estimated fair value financial positions is
as follows:
As at
June 30, 2007
-------------------------------------------------------------------------
Commodity Price Risk
Natural gas $ 930
Crude oil (50)
Power 21
Interest Rate Risk 3
Credit Derivatives (2)
-------------------------------------------------------------------------
Total Fair Value Positions $ 902
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Information with respect to credit derivatives and interest rate risk
contracts in place at December 31, 2006 is disclosed in Note 16 to the
Company's annual audited Consolidated Financial Statements.
Natural Gas
At June 30, 2007, the Company's gas risk management activities from
financial contracts had an unrealized gain of $919 million and a fair
market value position of $930 million. The contracts were as follows:
Notional
Volumes Fair Market
(MMcf/d) Term Average Price Value
-------------------------------------------------------------------------
Sales Contracts
Fixed Price Contracts
NYMEX Fixed Price 1,570 2007 8.63 US$/Mcf $ 365
NYMEX Fixed Price 698 2008 8.56 US$/Mcf 68
Options
Purchased NYMEX
Put Options 240 2007 6.00 US$/Mcf (3)
Basis Contracts
Canada 747 2007 (0.72) US$/Mcf 42
United States 912 2007 (0.70) US$/Mcf 357
Canada 191 2008 (0.78) US$/Mcf 9
United States 696 2008 (1.08) US$/Mcf 74
United States 20 2009 (0.71) US$/Mcf 3
Canada 41 2010 (0.40) US$/Mcf 2
-------------------------------------------------------------------------
917
Other Financial Positions(x) 2
-------------------------------------------------------------------------
Total Unrealized Gain on
Financial Contracts 919
Paid Premiums on Unexpired
Options 11
-------------------------------------------------------------------------
Total Fair Value Positions $ 930
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x) Other financial positions are part of the ongoing operations of the
Company's proprietary production management.

Crude Oil
At June 30, 2007, the Company's oil risk management activities from
financial contracts had an unrealized loss of $91 million and a fair
market value position of $(50) million. The contracts were as follows:
Notional
Volumes Fair Market
(bbls/d) Term Average Price Value
-------------------------------------------------------------------------
Sales Contracts
Fixed Price Contracts
WTI NYMEX Fixed Price 34,500 2007 64.40 US$/bbl $ (43)
WTI NYMEX Fixed Price 23,000 2008 70.13 US$/bbl (18)
Options
Purchased WTI NYMEX
Put Options 91,500 2007 55.34 US$/bbl (30)
-------------------------------------------------------------------------
(91)
Other Financial Positions(x) -
-------------------------------------------------------------------------
Total Unrealized Loss on
Financial Contracts (91)
Paid Premiums on Unexpired
Options 41
-------------------------------------------------------------------------
Total Fair Value Positions $ (50)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x) 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 June 30, 2007, these contracts had an unrealized gain of
$21 million.
20. CONTINGENCIES
Legal Proceedings
The Company is involved in various legal claims associated with the
normal course of operations. The Company believes it has made adequate
provision for such legal claims.
Discontinued Merchant Energy Operations
During the period between 2003 and 2005, EnCana and its indirect wholly
owned U.S. marketing subsidiary, WD Energy Services Inc. ("WD"), along
with other energy companies, were named as defendants in several
lawsuits, some of which were class action lawsuits, relating to sales of
natural gas from 1999 to 2002. The lawsuits allege that the defendants
engaged in a conspiracy with unnamed competitors in the natural gas
markets in California in violation of U.S. and California anti-trust and
unfair competition laws.
Without admitting any liability in the lawsuits, WD agreed to settle all
of the class action lawsuits in both state and federal court, for
payment, of $20.5 million and $2.4 million, respectively. 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.
21. 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 $14.27 Can 0

NYSE $11.11 USD 0

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