EnCana generates third quarter cash flow of US$2.2 billion, or $2.93 per share - up 27 percent

Net earnings per share down 25 percent to $1.24, or $934 million Natural gas production increases 8 percent to 3.6 billion cubic feet per day

CALGARY, Oct. 25 /CNW/ - EnCana Corporation (TSX & NYSE: ECA) continued
to generate solid cash flow during the third quarter of 2007 due to strong
natural gas production growth and favourable gas price hedges that offset
weaker gas prices, plus solid performance from the downstream segment of the
company's integrated oilsands business.
"This strong performance is the result of the actions we have taken over
the last several years to establish EnCana as a leading producer of
unconventional natural gas and integrated in-situ oilsands, a company with a
unique, low-risk, sustainable growth profile. Our financial and operating
performance is on track for 2007, which is evidence that our resource play
model is working extremely well. Natural gas production is up 16 percent per
share, led by production from our key gas resource plays: Cutbank Ridge in
northeast British Columbia, East Texas, Bighorn in west-central Alberta and
Jonah in Wyoming. As well, we continue to expand our integrated oilsands
business and capture value from strong refining margins in our downstream
operations," said Randy Eresman, EnCana's President & Chief Executive Officer.
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).
Third Quarter 2007 Highlights
-----------------------------
(all comparisons are to the third quarter of 2006)
<<
Financial - US$
- Cash flow per share diluted increased 27 percent to $2.93, or
$2.2 billion
- Operating earnings per share diluted down 3 percent to $1.27, or
$961 million, which is lower compared to the same quarter of 2006
in part due to a $255 million after-tax gain on the sale of a
Brazil asset in the third quarter of 2006
- Net earnings per share diluted down 25 percent to $1.24, or
$934 million
- Realized gains of $323 million, after tax, from commodity price
risk management measures
- Integrated oilsands downstream business generated $344 million of
pre-tax cash flow from U.S. refineries
- Capital investment up 7 percent to $1.58 billion
- Generated $643 million of free cash flow (as defined in Note 1 on
page 7)
- Purchased approximately 3.5 million EnCana shares at an average
price of $61.60 under the Normal Course Issuer Bid, completing the
company's planned purchase of 5 percent of shares in 2007
Operating - Upstream
- Natural gas production increased 8 percent to 3.63 billion cubic
feet per day (Bcf/d), up 16 percent per share
- Oil and natural gas liquids (NGLs) production up 1 percent on a
pro forma basis to about 136,000 barrels per day (bbls/d), up
9 percent per share (see note 1, Production & Drilling
Summary, page 3)
- Total natural gas and liquids production increased 7 percent on a
pro forma basis to 4.45 billion cubic feet of gas equivalent per
day (Bcfe/d), up 15 percent per share
- Key natural gas resource play production up 15 percent
- Oilsands production grew 33 percent to about 57,000 bbls/d (about
29,000 bbls/d net to EnCana) at Foster Creek and Christina Lake
- Operating and administrative costs of $1.01 per thousand cubic
feet equivalent (Mcfe)
Operating - Downstream
- Refined products production averaged 484,000 bbls/d
(242,000 bbls/d net to EnCana)
- Began processing Canadian bitumen blend through the Borger
refinery in July, a major milestone for the refinery
- Refinery crude utilization of 102 percent was higher than the
second quarter of 2007 due to the resumption of normal operations
at the Borger refinery after the installation and start-up of the
new coker in late June. Year-to-date utilization of 95 percent, or
430,000 bbls/d crude throughput (215,000 bbls/d net to EnCana),
continues to exceed expectations due to record throughput at the
Wood River refinery.
>>
Natural gas production on track with 2007 forecast
Natural gas production in the third quarter rose steadily with strong
year-over-year increases in a number of key resource plays - 47 percent in
Cutbank Ridge, 36 percent in East Texas, 32 percent in Bighorn, 29 percent in
Jonah and 22 percent in coalbed methane (CBM). Gas production to date in 2007
has averaged about 3.5 Bcf/d, in line with full-year guidance of 3.46 Bcf/d.
Current production is about 3.6 Bcf/d. The company is on track to modestly
exceed its full-year natural gas production guidance. EnCana expects it will
likely achieve closer to 4 percent growth in gas production as opposed to its
original 3 percent growth forecast.
Integrated oilsands business solid performance continues
The financial performance of EnCana's emerging integrated oilsands
business continues to be strong. Regional and local market factors have an
impact on refining crack spreads. EnCana's two refineries are located in
markets influenced by U.S. Mid-continent and Chicago 3-2-1 crack spreads which
have been strong relative to U.S. Gulf Coast and NYMEX crack spreads. Third
quarter pre-tax cash flow from the integrated oilsands business was
$411 million, composed of $344 million from downstream and $67 million from
upstream. During the first nine months of 2007, the integrated oilsands
business delivered more than $1 billion of pre-tax cash flow, about 14 percent
of EnCana's total pre-tax cash flow.
"The financial and operating performance of our integrated oilsands
business continues to validate our market integration initiatives," Eresman
said. "The downstream performance also reflects the strength of
ConocoPhillips' management and operating teams and their commitment and
contribution to the success of this business venture."
Deep Panuke gas project off Nova Scotia moves ahead
EnCana's Board of Directors has sanctioned the development of the
company's Deep Panuke natural gas project located about 175 kilometres
offshore Nova Scotia. The $700 million project (about $550 million net to
EnCana) is expected to start production in 2010 and is expected to deliver
between 200 million and 300 million cubic feet of natural gas per day to
markets in Canada and the northeast United States.
"Over the past five years, EnCana employees, the Government of Nova
Scotia, federal and provincial regulators and the Atlantic energy community
have worked diligently to achieve this important milestone. We are excited to
move ahead with the development of the Deep Panuke discovery," Eresman said.
<<
-------------------------------------------------------------------------
Financial Summary - Total Consolidated
-------------------------------------------------------------------------
(for the period ended
Sept 30) 9 9
($ millions, except per Q3 Q3 % months months %
share amounts) 2007 2006 change 2007 2006 change
-------------------------------------------------------------------------
Cash flow(1) 2,218 1,894 + 17 6,519 5,400 + 21
Per share diluted 2.93 2.30 + 27 8.49 6.39 + 33
-------------------------------------------------------------------------
Operating earnings(1) 961 1,078 - 11 3,195 2,596 + 23
Per share diluted 1.27 1.31 - 3 4.16 3.07 + 36
-------------------------------------------------------------------------
Net earnings 934 1,358 - 31 2,877 4,989 - 42
Per share diluted 1.24 1.65 - 25 3.75 5.90 - 36
-------------------------------------------------------------------------
Capital investment 1,575 1,474 + 7 4,230 5,052 - 16
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings Reconciliation Summary - Total Consolidated
-------------------------------------------------------------------------
Net earnings from
continuing operations 934 1,343 - 30 2,877 4,408 - 35
Net earnings from
discontinued operations - 15 n/a - 581 n/a
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net earnings (loss)
(Add back losses &
deduct gains) 934 1,358 - 31 2,877 4,989 - 42
Unrealized mark-to-market
hedging gain (loss),
after-tax (69) 285 n/a (445) 1,275 n/a
Unrealized foreign
exchange gain (loss)
on translation of
U.S. dollar Notes issued
from Canada, after-tax 17 (3) n/a 6 128 n/a
Future tax recovery due
to Canada and Alberta
tax rate reductions - - n/a 37 457 n/a
Gain (loss) on
discontinuance,
after-tax 25 (2) n/a 84 533 n/a
-------------------------------------------------------------------------
Operating earnings(1) 961 1,078 - 11 3,195 2,596 + 23
Per share diluted 1.27 1.31 - 3 4.16 3.07 + 36
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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
Sept 30) 9 9
(After royalties) Q3 Q3 % months months %
2007 2006(1) change 2007 2006(1) change
-------------------------------------------------------------------------
Natural gas
(MMcf/d) 3,630 3,359 + 8 3,513 3,354 + 5
-------------------------------------------------------------------------
Natural gas production
per 1,000 shares (Mcf) 445 382 + 16 1,263 1,100 + 15
-------------------------------------------------------------------------
Oil and NGLs (Mbbls/d) 136 135 + 1 133 153 - 13
-------------------------------------------------------------------------
Oil and NGLs production
per 1,000 shares (Mcfe) 100 92 + 9 288 302 - 5
-------------------------------------------------------------------------
Total Production (MMcfe/d) 4,448 4,170 + 7 4,314 4,275 + 1
-------------------------------------------------------------------------
Total per 1,000 shares
(Mcfe) 545 474 + 15 1,551 1,402 + 11
-------------------------------------------------------------------------
Net wells drilled 1,339 1,001 + 34 3,171 2,841 + 12
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) 2006 information has been adjusted on a pro forma basis to reflect
the integrated oilsands transaction; the nine 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 15 percent from past year
Third quarter 2007 natural gas production from key resource plays
increased 15 percent to 2.78 Bcf/d compared to 2.41 Bcf/d in the third quarter
of 2006. This increased production was driven mainly by double-digit
production increases in six of the company's nine gas resource plays, led by
Cutbank Ridge in northeast British Columbia, East Texas, Bighorn in
west-central Alberta, Jonah in Wyoming, the Barnett Shale play in the Fort
Worth basin, and CBM in central and southern Alberta. The growth in Cutbank
Ridge is the result of continued production growth from the Cadomin zone,
along with an increasing contribution from the Montney and Doig formations.
The increase in Jonah, EnCana's second largest resource play, can be
attributed to improved response from frac stimulations and increased
availability of capacity on regional pipelines due to system expansion and
added compression on the gas gathering system.
Oilsands production from Foster Creek and Christina Lake was up 33
percent to about 57,000 bbls/d (about 29,000 bbls/d net to EnCana). Overall,
third quarter gas and oil resource play production increased 15 percent in the
past year, on a pro forma basis.
<<
Growth from key North American resource plays
-------------------------------------------------------------------------
Daily Production
------------------------------------------------------------
Resource Play 2007 2006 2005
------------------------------------------------------------
(After Full Full
royalties) YTD Q3 Q2 Q1 Year Q4 Q3 Q2 Q1 Year
-------------------------------------------------------------------------
Natural gas
(MMcf/d)
Jonah 539 588 523 504 464 487 455 450 461 435
Piceance 346 354 349 334 326 335 331 324 316 307
East Texas 129 144 139 103 99 95 106 93 99 90
Fort Worth 119 128 124 106 101 99 104 108 93 70
Greater
Sierra 208 220 219 186 213 212 209 224 208 219
Cutbank
Ridge 227 245 226 210 170 199 167 173 140 92
Bighorn 116 128 115 104 91 99 97 95 72 55
CBM (1) 251 256 245 251 194 211 209 179 177 112
Shallow
Gas(2) 725 713 729 735 739 737 734 730 756 765
-------------------------------------------------------------------------
Total
natural gas
(MMcf/d) 2,660 2,776 2,669 2,533 2,397 2,474 2,412 2,376 2,322 2,145
-------------------------------------------------------------------------
Oil (Mbbls/d)
Foster
Creek(3) 24 26 25 20 18 21 19 16 18 14
Christina
Lake(3) 3 3 3 3 3 3 3 3 3 3
Pelican
Lake(4) 23 24 23 23 24 20 23 22 29 26
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total oil
(Mbbls/d) 50 53 51 46 45 44 45 41 50 43
-------------------------------------------------------------------------
Total
(MMcfe/d) 2,959 3,090 2,972 2,811 2,667 2,736 2,680 2,624 2,624 2,403
-------------------------------------------------------------------------
% change
from Q3
2006 15
-------------------------------------------------------------------------
% change
from prior
period 4.0 5.7 2.7 11 2.1 2.1 - -2.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) CBM volumes were restated in 2006 to account for commingled volumes
from the coal and sand intervals based upon 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 Q3 Q2 Q1 Year Q4 Q3 Q2 Q1 Year
-------------------------------------------------------------------------
Natural gas
Jonah 112 31 42 39 163 41 48 48 26 104
Piceance 209 72 72 65 220 50 48 59 63 266
East Texas 27 9 11 7 59 11 12 17 19 84
Fort Worth 60 17 29 14 97 19 22 27 29 59
Greater
Sierra 82 27 32 23 115 5 16 34 60 164
Cutbank
Ridge 70 18 25 27 116 19 35 36 26 135
Bighorn 52 15 9 28 52 7 7 18 20 51
CBM (1) 749 323 18 408 729 157 156 35 381 1,245
Shallow
Gas(2) 1,265 608 241 416 1,310 389 475 217 229 1,389
-------------------------------------------------------------------------
Total gas
wells 2,626 1,120 479 1,027 2,861 698 819 491 853 3,497
-------------------------------------------------------------------------
Oil
Foster
Creek(3) 17 8 1 8 3 - - - 3 20
Christina
Lake(3) 3 1 2 - 1 - - - 1 -
Pelican
Lake - - - - - - - - - 52
-------------------------------------------------------------------------
Total oil
wells 20 9 3 8 4 - - - 4 72
-------------------------------------------------------------------------
Total 2,646 1,129 482 1,035 2,865 698 819 491 857 3,569
-------------------------------------------------------------------------
(1) CBM net wells drilled were restated in 2006 to account for commingled
volumes from the coal and sand intervals based upon 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.

-------------------------------------------------------------------------
Third quarter 2007 natural gas and oil prices
-------------------------------------------------------------------------
Q3 Q3 % 9 months 9 months %
2007 2006 change 2007 2006 change
-------------------------------------------------------------------------
Natural gas
($/Mcf, realized prices
include hedging)
NYMEX 6.16 6.58 - 6 6.83 7.45 - 8
EnCana Realized Gas
Price 6.75 6.57 + 3 7.19 6.74 + 7
-------------------------------------------------------------------------
Oil and NGLs
($/bbl, realized prices
include hedging)
WTI 75.15 70.54 + 7 66.22 68.26 - 3
Western Canadian
Select (WCS) 52.71 51.71 + 2 46.86 46.55 + 1
Differential WTI/WCS 22.44 18.83 + 19 19.36 21.71 - 11
EnCana Realized Liquids
Price 49.01 46.92 + 4 45.71 42.03 + 9
-------------------------------------------------------------------------
3-2-1 Crack Spread
($/bbl)
U.S. Gulf Coast 11.74 11.00 + 7 15.36 12.18 + 26
U.S. Mid-Continent 20.92 17.75 + 18 22.34 15.72 + 42
Chicago 18.48 15.29 + 21 20.50 14.67 + 40
-------------------------------------------------------------------------
>>
Price risk management
Risk management positions at September 30, 2007 are presented in Note 19
to the unaudited Interim Consolidated Financial Statements. In the third
quarter of 2007, EnCana's commodity price risk management measures resulted in
realized gains of approximately $323 million after-tax, composed of a
$364 million gain on gas hedges and a $41 million loss on oil and other
hedges.
About 1.1 Bcf/d of 2008 gas production hedged at $8.30 per Mcf
EnCana currently has fixed price contracts on about 1.1 Bcf/d of expected
2008 gas production, at a NYMEX equivalent price of about $8.30 per Mcf. For
the fourth quarter of 2007, EnCana has about 1.8 Bcf/d of gas production with
downside price protection, composed of 1.6 Bcf/d under fixed price contracts
at an average NYMEX equivalent price of $8.77 per Mcf and 240 MMcf/d with put
options at a NYMEX equivalent strike price of $6.00 per Mcf. EnCana has hedged
23,000 bbls/d of expected 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.
U.S. Rockies and Canadian basis differential hedges
North American natural gas prices are impacted by volatile pricing
disconnects caused primarily by transportation constraints between producing
regions and consuming regions. EnCana's production gives rise to exposure to
these price discounts, also known as basis differentials. For the remainder of
2007 EnCana has hedged 100 percent of its expected U.S. Rockies basis exposure
using a combination of downstream transportation and basis hedges. The basis
hedges have an effective annual average differential of NYMEX less 67 cents
per Mcf. During the third quarter of 2007 the U.S. Rockies-NYMEX natural gas
price differential averaged $3.22 per Mcf. For 2008, EnCana has hedged 100
percent of its expected U.S. Rockies basis exposure using a combination of
downstream transportation and basis hedges, including some hedges that are
based on a percentage of NYMEX prices. At the end of the third quarter, the
basis hedges had an effective annual average differential of NYMEX less $1.01
per Mcf. In Canada for 2007, EnCana has hedged 33 percent of its expected AECO
basis exposure at 72 cents per Mcf. EnCana has an additional 31 percent of
expected Canadian basis exposure subject to transport and aggregator
contracts. In the third quarter of 2007, the AECO basis differential averaged
84 cents per Mcf. In Canada for 2008, EnCana has hedged 8 percent of its
expected production at an average AECO basis differential of 78 cents per Mcf.
During the third quarter of 2007, EnCana's basis hedging resulted in a
realized gain before tax of about $255 million.
Corporate developments
----------------------
Alberta Royalty Review
The Government of Alberta is in the midst of a comprehensive review of
the province's oil and natural gas royalty structure. Until detailed and
specific information of any royalty changes is outlined publicly and
thoroughly evaluated by the company, EnCana is unable to comment on how
potential changes may impact the company's operations.
Columbia River Basin
EnCana has concluded its exploration program in the Columbia River Basin
in Washington state after drilling three wells, Anderville Farms Inc. No. 1,
Anderson 11-5, and Brown 7-24. Each well indicated the presence of natural
gas. Although commercial flow rates were not established in these wells, there
remains potential for large natural gas accumulations in the basin, which has
only been partially tested. Exxel Energy Corp. took over operatorship and
ownership of the Brown well in late September and is planning to conduct
additional completion testing on the well. Because this is a non-core play for
EnCana, the company anticipates that any future activities on EnCana's acreage
position will likely be funded by third-party capital under farm-in or similar
arrangements. As a result, EnCana has no immediate plans for additional
drilling.
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 December 31, 2007 to common shareholders of
record as of December 14, 2007.
Normal Course Issuer Bid
In the past 12 months under its Normal Course Issuer Bid, EnCana
purchased 63.4 million common shares, representing approximately 7.9 percent
of the company's outstanding shares on November 1, 2006, at an average price
of approximately US$51.54 per common share.
Financial strength
------------------
EnCana maintains a strong balance sheet, targeting a net
debt-to-capitalization ratio between 30 and 40 percent. At September 30, 2007,
the company's net debt-to-capitalization ratio was 27:73. At the end of the
third quarter EnCana's net debt-to-adjusted-EBITDA multiple, on a trailing
12-month basis, was 0.8 times. The company expects its net
debt-to-capitalization ratio to remain at the lower end of the targeted range.
In the third quarter of 2007, EnCana invested $1,575 million in capital.
Net acquisitions were $16 million, resulting in net capital investment in
continuing operations of $1,591 million.
<<
-------------------------------------------------------------------------
CONFERENCE CALL TODAY
11 a.m. Mountain Time (1 p.m. Eastern Time)
EnCana Corporation will host a conference call today, Thursday,
October 25, 2007 starting at 11:00 a.m. MT (1:00 p.m. ET). To
participate, please dial (866) 215-9524 (toll-free in North America) or
(416) 915-9619 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 October 25 until midnight October 29, 2007 by dialing
(888) 203-1112 or (719) 457-0820 and entering access code 6834269.
A live audio webcast of the conference call will also be available
via EnCana's website, www.encana.com Investor Relations. The
webcast will be archived for approximately 90 days.
-------------------------------------------------------------------------
>>
NOTE 1: Non-GAAP measures
This news release contains references to cash flow, pre-tax cash flow,
operating earnings and free cash flow.
<<
- Cash flow is a non-GAAP measure defined as 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.
- Pre-tax cash flow is calculated as cash flow before cash taxes.
- Operating earnings is a non-GAAP measure that shows net earnings
excluding non-operating items such as the after-tax impacts of a
gain/loss on discontinuance, the after-tax gain/loss of unrealized
mark-to-market accounting for derivative instruments, the after-tax
gain/loss on translation of U.S. dollar denominated Notes issued from
Canada and the partnership contribution receivable and the effect of
the reduction in income tax rates. Management believes that these
excluded items reduce the comparability of the company's underlying
financial performance between periods. The majority of the unrealized
gains/losses that relate to U.S. dollar denominated Notes issued from
Canada are for debt with maturity dates in excess of five years.
- Free cash flow is a non-GAAP measure that EnCana defines as cash flow
in excess of total capital investment and is used to determine the
funds available for other investing and/or financing activities.
>>
These measures have been described and presented in this news release in
order to provide shareholders and potential investors with additional
information regarding EnCana's liquidity and its ability to generate funds to
finance its operations.
EnCana Corporation
With an enterprise value of approximately 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; the
anticipated production, timing thereof, and expenditures associated with the
Deep Panuke Project; anticipated potential of and third party capital for the
Columbia River Basin; 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 Borger and
Wood River 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 royalty, tax, environmental and
other laws or regulations or the interpretations of such laws or regulations;
political and economic conditions in the countries in which the company
operates; the risk of war, hostilities, civil insurrection and instability
affecting countries in which the company operates and terrorist threats; risks
associated with existing and potential future lawsuits and regulatory actions
made against the company; and other risks and uncertainties described from
time to time in the reports and filings made with securities regulatory
authorities by EnCana. Although EnCana believes that the expectations
represented by such forward-looking statements are reasonable, there can be no
assurance that such expectations will prove to be correct. Readers are
cautioned that the foregoing list of important factors is not exhaustive.
Furthermore, the forward-looking statements contained in this news
release are made as of the date of this news release, and, except as required
by law, EnCana does not undertake any obligation to update publicly or to
revise any of the included forward-looking statements, whether as a result of
new information, future events or otherwise. The forward-looking statements
contained in this news release are expressly qualified by this cautionary
statement.

<<
Third quarter report
for the period ended September 30, 2007
CONSOLIDATED STATEMENT OF EARNINGS (unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
($ millions, except per ---------------------------------------
share amounts) 2007 2006 2007 2006
-------------------------------------------------------------------------
REVENUES, NET OF ROYALTIES (Note 6)
Upstream $ 2,883 $ 2,622 $ 8,597 $ 7,817
Integrated Oilsands 2,191 248 5,614 713
Market Optimization 629 731 2,107 2,272
Corporate - Unrealized gain
(loss) on risk management (107) 428 (673) 1,921
-------------------------------------------------------------------------
5,596 4,029 15,645 12,723
EXPENSES (Note 6)
Production and mineral taxes 79 79 228 269
Transportation and selling 220 271 732 795
Operating 530 420 1,646 1,227
Purchased product 2,192 677 5,879 2,160
Depreciation, depletion
and amortization 988 791 2,730 2,346
Administrative 73 54 263 187
Interest, net (Note 9) 102 83 297 254
Accretion of asset
retirement obligation (Note 15) 17 13 46 37
Foreign exchange
(gain) loss, net (Note 10) 74 - 69 (158)
(Gain) loss on
divestitures (Note 8) (29) (304) (87) (321)
-------------------------------------------------------------------------
4,246 2,084 11,803 6,796
-------------------------------------------------------------------------
NET EARNINGS BEFORE INCOME TAX 1,350 1,945 3,842 5,927
Income tax expense (Note 11) 416 602 965 1,519
-------------------------------------------------------------------------
NET EARNINGS FROM
CONTINUING OPERATIONS 934 1,343 2,877 4,408
NET EARNINGS FROM
DISCONTINUED OPERATIONS (Note 7) - 15 - 581
-------------------------------------------------------------------------
NET EARNINGS $ 934 $ 1,358 $ 2,877 $ 4,989
-------------------------------------------------------------------------
-------------------------------------------------------------------------
NET EARNINGS FROM CONTINUING
OPERATIONS PER COMMON
SHARE (Note 18)
Basic $ 1.24 $ 1.66 $ 3.79 $ 5.32
Diluted $ 1.24 $ 1.63 $ 3.75 $ 5.21
-------------------------------------------------------------------------
-------------------------------------------------------------------------
NET EARNINGS PER COMMON
SHARE (Note 18)
Basic $ 1.24 $ 1.68 $ 3.79 $ 6.02
Diluted $ 1.24 $ 1.65 $ 3.75 $ 5.90
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.

CONSOLIDATED STATEMENT OF RETAINED EARNINGS (unaudited)
Nine Months Ended
September 30,
-------------------
($ millions) 2007 2006
-------------------------------------------------------------------------
RETAINED EARNINGS, BEGINNING OF YEAR $ 11,344 $ 9,481
Net Earnings 2,877 4,989
Dividends on Common Shares (453) (226)
Charges for Normal Course Issuer Bid (Note 16) (1,618) (2,450)
-------------------------------------------------------------------------
RETAINED EARNINGS, END OF PERIOD $ 12,150 $ 11,794
-------------------------------------------------------------------------
-------------------------------------------------------------------------

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------------------------
($ millions) 2007 2006 2007 2006
-------------------------------------------------------------------------
NET EARNINGS $ 934 $ 1,358 $ 2,877 $ 4,989
OTHER COMPREHENSIVE INCOME,
NET OF TAX
Foreign Currency Translation
Adjustment 859 (7) 1,798 531
-------------------------------------------------------------------------
COMPREHENSIVE INCOME $ 1,793 $ 1,351 $ 4,675 $ 5,520
-------------------------------------------------------------------------
-------------------------------------------------------------------------

CONSOLIDATED STATEMENT OF ACCUMULATED OTHER COMPREHENSIVE INCOME
(unaudited)
Nine Months Ended
September 30,
-------------------
($ millions) 2007 2006
-------------------------------------------------------------------------
ACCUMULATED OTHER COMPREHENSIVE INCOME,
BEGINNING OF YEAR $ 1,375 $ 1,262
Foreign Currency Translation Adjustment 1,798 531
-------------------------------------------------------------------------
ACCUMULATED OTHER COMPREHENSIVE INCOME,
END OF PERIOD $ 3,173 $ 1,793
-------------------------------------------------------------------------
-------------------------------------------------------------------------
As at September 30, 2007, the accumulated other comprehensive income
consists of foreign currency translation adjustments of $3,173 million
(December 31, 2006 - $1,375 million; September 30, 2006 -
$1,793 million).
See accompanying Notes to Consolidated Financial Statements.

CONSOLIDATED BALANCE SHEET (unaudited)
As at As at
September 30, December 31,
($ millions) 2007 2006
-------------------------------------------------------------------------
ASSETS
Current Assets
Cash and cash equivalents $ 515 $ 402
Accounts receivable and accrued revenues 2,146 1,721
Current portion of partnership
contribution receivable (Note 5, 12) 293 -
Risk management (Note 19) 820 1,403
Inventories (Note 13) 775 176
-------------------------------------------------------------------------
4,549 3,702
Property, Plant and Equipment, net (Note 6) 32,156 28,213
Investments and Other Assets 604 533
Partnership Contribution
Receivable (Note 5, 12) 3,223 -
Risk Management (Note 19) 57 133
Goodwill 2,873 2,525
-------------------------------------------------------------------------
(Note 6) $ 43,462 $ 35,106
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued liabilities $ 3,717 $ 2,494
Income tax payable 687 926
Current portion of partnership
contribution payable (Note 5, 12) 284 -
Risk management (Note 19) 98 14
Current portion of long-term debt (Note 14) 1,000 257
-------------------------------------------------------------------------
5,786 3,691
Long-Term Debt (Note 14) 6,246 6,577
Other Liabilities 205 79
Partnership Contribution Payable (Note 5, 12) 3,236 -
Risk Management (Note 19) 12 2
Asset Retirement Obligation (Note 15) 1,272 1,051
Future Income Taxes 6,865 6,240
-------------------------------------------------------------------------
23,622 17,640
-------------------------------------------------------------------------
Shareholders' Equity
Share capital (Note 16) 4,457 4,587
Paid in surplus 60 160
Retained earnings 12,150 11,344
Accumulated other comprehensive income 3,173 1,375
-------------------------------------------------------------------------
Total Shareholders' Equity 19,840 17,466
-------------------------------------------------------------------------
$ 43,462 $ 35,106
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.

CONSOLIDATED STATEMENT OF CASH FLOWS (unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------------------------
($ millions) 2007 2006 2007 2006
-------------------------------------------------------------------------
OPERATING ACTIVITIES
Net earnings from
continuing operations $ 934 $ 1,343 $ 2,877 $ 4,408
Depreciation, depletion
and amortization 988 791 2,730 2,346
Future income taxes (Note 11) 102 401 (9) 690
Cash tax on sale
of assets (Note 8) - 49 - 49
Unrealized (gain) loss
on risk management (Note 19) 107 (428) 666 (1,919)
Unrealized foreign
exchange (gain) loss 83 4 142 (79)
Accretion of asset
retirement obligation (Note 15) 17 13 46 37
(Gain) loss on
divestitures (Note 8) (29) (304) (87) (321)
Other 16 14 154 90
Cash flow from
discontinued operations - 11 - 99
Net change in other
assets and liabilities 1 21 5 48
Net change in non-cash
working capital from
continuing operations (19) (247) (247) 3,305
Net change in non-cash
working capital from
discontinued operations - (13) - (2,476)
-------------------------------------------------------------------------
Cash From Operating Activities 2,200 1,655 6,277 6,277
-------------------------------------------------------------------------
INVESTING ACTIVITIES
Capital expenditures (Note 6) (1,650) (1,486) (4,329) (5,350)
Proceeds on disposal
of assets (Note 8) 59 377 505 634
Cash tax on sale
of assets (Note 8) - (49) - (49)
Net change in
investments and other 32 (56) 26 (38)
Net change in non-cash
working capital from
continuing operations 69 (18) (34) (169)
Discontinued operations - - - 2,377
-------------------------------------------------------------------------
Cash (Used in) Investing
Activities (1,490) (1,232) (3,832) (2,595)
-------------------------------------------------------------------------
FINANCING ACTIVITIES
Net issuance (repayment)
of revolving long-term debt (871) 470 (909) (512)
Issuance of
long-term debt (Note 14) 492 - 924 -
Repayment of
long-term debt - (73) - (73)
Issuance of
common shares (Note 16) 5 39 158 140
Purchase of
common shares (Note 16) (218) (900) (2,025) (2,973)
Dividends on common
shares (149) (80) (453) (226)
Other 2 2 (1) (9)
-------------------------------------------------------------------------
Cash (Used in)
Financing Activities (739) (542) (2,306) (3,653)
-------------------------------------------------------------------------
DEDUCT: FOREIGN EXCHANGE LOSS
ON CASH AND CASH EQUIVALENTS
HELD IN FOREIGN CURRENCY 11 - 26 -
-------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS (40) (119) 113 29
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD 555 253 402 105
-------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS,
END OF PERIOD $ 515 $ 134 $ 515 $ 134
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 September 30, 2007
period end accumulated foreign currency translation adjustment balance of
$3,173 million has been reclassified to AOCI (December 31, 2006 -
$1,375 million; September 30, 2006 - $1,793 million). In addition, the
change in the accumulated foreign currency translation adjustment balance
for the three months and nine months ended September 30, 2007 of
$859 million and $1,798 million, respectively, is now included in OCI in
the Statement of Comprehensive Income (three months and nine months ended
September 30, 2006 - $(7) million and $531 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 the Foster Creek and Christina
Lake oil sands 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 Atlantic Canada, the Middle East and
France.
- Integrated Oilsands is focused on two lines of business: the
exploration for, and development and production of heavy oil from oil
sands 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
September 30)
Upstream
------------------------------------------------
Canada United States Other
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues,
Net of Royalties $1,760 $1,745 $1,020 $ 811 $ 103 $ 66
Expenses
Production and
mineral taxes 27 27 52 52 - -
Transportation
and selling 81 77 77 64 - -
Operating 238 218 68 64 79 57
Purchased product - - - - - -
Depreciation, depletion
and amortization 558 505 299 222 30 6
-------------------------------------------------------------------------
Segment Income (Loss) $ 856 $ 918 $ 524 $ 409 $ (6) $ 3
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Total Integrated Market
Upstream Oilsands Optimization
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of
Royalties $2,883 $2,622 $2,191 $ 248 $ 629 $ 731
Expenses
Production and
mineral taxes 79 79 - - - -
Transportation
and selling 158 141 62 126 - 4
Operating 385 339 134 62 11 18
Purchased product - - 1,584 - 608 677
Depreciation, depletion
and amortization 887 733 72 37 4 3
-------------------------------------------------------------------------
Segment Income (Loss) $1,374 $1,330 $ 339 $ 23 $ 6 $ 29
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Corporate Consolidated
-------------------------------------------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of Royalties $ (107) $ 428 $5,596 $4,029
Expenses
Production and mineral taxes - - 79 79
Transportation and selling - - 220 271
Operating - 1 530 420
Purchased product - - 2,192 677
Depreciation, depletion
and amortization 25 18 988 791
-------------------------------------------------------------------------
Segment Income (Loss) $ (132) $ 409 1,587 1,791
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Administrative 73 54
Interest, net 102 83
Accretion of asset retirement obligation 17 13
Foreign exchange (gain) loss, net 74 -
(Gain) loss on divestitures (29) (304)
-------------------------------------------------------------------------
237 (154)
-------------------------------------------------------------------------
Net Earnings Before Income Tax 1,350 1,945
Income tax expense 416 602
-------------------------------------------------------------------------
Net Earnings From Continuing Operations $ 934 $1,343
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Results of Continuing Operations (For the three months ended
September 30)
Geographic and Product Information (Continuing Operations)
Produced Gas
-------------------------------------------------------------------------
Canada United States Total
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net
of Royalties $1,327 $1,302 $ 934 $ 735 $2,261 $2,037
Expenses
Production and
mineral taxes 20 18 49 47 69 65
Transportation
and selling 70 74 77 64 147 138
Operating 173 157 68 64 241 221
-------------------------------------------------------------------------
Operating Cash Flow $1,064 $1,053 $ 740 $ 560 $1,804 $1,613
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Oil & NGLs
-------------------------------------------------------------------------
Canada United States Total
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net
of Royalties $ 433 $ 443 $ 86 $ 76 $ 519 $ 519
Expenses
Production and
mineral taxes 7 9 3 5 10 14
Transportation
and selling 11 3 - - 11 3
Operating 65 61 - - 65 61
-------------------------------------------------------------------------
Operating Cash Flow $ 350 $ 370 $ 83 $ 71 $ 433 $ 441
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Integrated Oilsands
-------------------------------------------------------------------------
Downstream
Oil Refining Other
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues,
Net of Royalties $ 160 $ 239 $2,049 $ - $ (18) $ 9
Expenses
Transportation
and selling 62 126 - - - -
Operating 35 56 98 - 1 6
Purchased product - - 1,607 - (23) -
-------------------------------------------------------------------------
Operating Cash Flow $ 63 $ 57 $ 344 $ - $ 4 $ 3
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Integrated
Oilsands
-------------------------------------------------------------------------
Total
-------------------------------------------------------------------------
2007 2006
-------------------------------------------------------------------------
Revenues, Net of Royalties $2,191 $ 248
Expenses
Transportation and selling 62 126
Operating 134 62
Purchased product 1,584 -
-------------------------------------------------------------------------
Operating Cash Flow $ 411 $ 60
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Results of Continuing Operations (For the nine months ended September 30)
Upstream
-----------------------------------------------
Canada United States Other
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues,
Net of Royalties $5,352 $5,252 $2,964 $2,356 $ 281 $ 209
Expenses
Production and
mineral taxes 86 96 142 173 - -
Transportation
and selling 244 223 220 182 - -
Operating 718 639 228 207 233 174
Purchased product - - - - - -
Depreciation, depletion
and amortization 1,572 1,495 834 648 42 25
-------------------------------------------------------------------------
Segment Income (Loss) $2,732 $2,799 $1,540 $1,146 $ 6 $ 10
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Total Integrated Market
Upstream Oilsands Optimization
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net
of Royalties $8,597 $7,817 $5,614 $ 713 $2,107 $2,272
Expenses
Production and
mineral taxes 228 269 - - - -
Transportation
and selling 464 405 258 373 10 17
Operating 1,179 1,020 447 157 28 49
Purchased product - - 3,837 - 2,042 2,160
Depreciation, depletion
and amortization 2,448 2,168 207 114 11 8
-------------------------------------------------------------------------
Segment Income (Loss) $4,278 $3,955 $ 865 $ 69 $ 16 $ 38
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Corporate Consolidated
-------------------------------------------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of Royalties $ (673) $1,921 $15,645 $12,723
Expenses
Production and mineral taxes - - 228 269
Transportation and selling - - 732 795
Operating (8) 1 1,646 1,227
Purchased product - - 5,879 2,160
Depreciation, depletion
and amortization 64 56 2,730 2,346
-------------------------------------------------------------------------
Segment Income (Loss) $ (729) $1,864 4,430 5,926
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Administrative 263 187
Interest, net 297 254
Accretion of asset retirement obligation 46 37
Foreign exchange (gain) loss, net 69 (158)
(Gain) loss on divestitures (87) (321)
-------------------------------------------------------------------------
588 (1)
-------------------------------------------------------------------------
Net Earnings Before Income Tax 3,842 5,927
Income tax expense 965 1,519
-------------------------------------------------------------------------
Net Earnings From Continuing Operations $2,877 $4,408
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Results of Continuing Operations (For the nine months ended September 30)
Geographic and Product Information (Continuing Operations)
Produced Gas
-------------------------------------------------------------------------
Canada United States Total
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net
of Royalties $4,161 $4,039 $2,754 $2,148 $6,915 $6,187
Expenses
Production and
mineral taxes 62 69 127 159 189 228
Transportation
and selling 213 212 220 182 433 394
Operating 530 463 228 207 758 670
-------------------------------------------------------------------------
Operating Cash Flow $3,356 $3,295 $2,179 $1,600 $5,535 $4,895
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Oil & NGLs
-------------------------------------------------------------------------
Canada United States Total
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of
Royalties $1,191 $1,213 $ 210 $ 208 $1,401 $1,421
Expenses
Production and
mineral taxes 24 27 15 14 39 41
Transportation
and selling 31 11 - - 31 11
Operating 188 176 - - 188 176
-------------------------------------------------------------------------
Operating Cash Flow $ 948 $ 999 $ 195 $ 194 $1,143 $1,193
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Integrated Oilsands
-------------------------------------------------------------------------
Downstream
Oil Refining Other
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of
Royalties $ 552 $ 693 $5,109 $ - $ (47) $ 20
Expenses
Transportation
and selling 258 373 - - - -
Operating 123 138 317 - 7 19
Purchased product - - 3,898 - (61) -
-------------------------------------------------------------------------
Operating Cash Flow $ 171 $ 182 $ 894 $ - $ 7 $ 1
-------------------------------------------------------------------------

Integrated
Oilsands
-------------------------------------------------------------------------
Total
-------------------------------------------------------------------------
2007 2006
-------------------------------------------------------------------------
Revenues, Net of Royalties $5,614 $ 713
Expenses
Transportation and selling 258 373
Operating 447 157
Purchased product 3,837 -
-------------------------------------------------------------------------
Operating Cash Flow $1,072 $ 183
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Capital Expenditures (Continuing Operations)

Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Capital
Canada $ 962 $ 777 $ 2,424 $ 2,684
United States 452 576 1,313 1,746
Other 3 12 40 51
Integrated Oilsands 147 87 372 482
Market Optimization 2 2 5 40
Corporate 9 20 76 49
-------------------------------------------------------------------------
1,575 1,474 4,230 5,052
-------------------------------------------------------------------------
Acquisition Capital
Canada 60 1 67 9
United States 15 11 18 268
Integrated Oilsands - - 14 21
-------------------------------------------------------------------------
75 12 99 298
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total $ 1,650 $ 1,486 $ 4,329 $ 5,350
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Property, Plant and Equipment and Total Assets
Property, Plant and Equipment Total Assets
--------------------------------------------------
As at As at
--------------------------------------------------
September December September December
30, 31, 30, 31,
2007 2006 2007 2006
-------------------------------------------------------------------------
Canada $ 17,943 $ 17,702 $ 19,120 $ 19,060
United States 8,960 8,494 9,387 9,036
Other 144 263 168 300
Integrated Oilsands 4,566 1,322 9,481 1,379
Market Optimization 174 154 597 468
Corporate 369 278 4,709 4,863
-------------------------------------------------------------------------
Total $ 32,156 $ 28,213 $ 43,462 $ 35,106
-------------------------------------------------------------------------
-------------------------------------------------------------------------
On February 9, 2007, EnCana announced that it had completed the next
phase in the development of The Bow office project with the sale of
project assets and has entered into a 25 year lease agreement with a
third party developer. Corporate Property, Plant and Equipment and Total
Assets includes EnCana's accrual to date of $101 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.
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 September 30,
--------------------------------------------------------
Ecuador United Kingdom Midstream Total
--------------------------------------------------------
2007 2006 2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net
of Royalties $ - $ - $ - $ - $ - $ 14 $ - $ 14
-------------------------------------------------------------------------
Expenses
Production
and mineral
taxes - - - - - - - -
Transportation
and selling - - - - - - - -
Operating - - - - - - - -
Purchased product - - - - - - - -
Depreciation,
depletion and
amortization - - - - - - - -
Interest, net - - - - - - - -
Foreign exchange
(gain) loss, net - - - - - (4) - (4)
(Gain) loss on
discontinuance - - - - - 2 - 2
-------------------------------------------------------------------------
- - - - - (2) - (2)
-------------------------------------------------------------------------
Net Earnings (Loss)
Before Income Tax - - - - - 16 - 16
Income tax expense - - - (7) - 8 - 1
-------------------------------------------------------------------------
Net Earnings (Loss)
From Discontinued
Operations $ - $ - $ - $ 7 $ - $ 8 $ - $ 15
-------------------------------------------------------------------------
-------------------------------------------------------------------------

For the nine months ended September 30,
--------------------------------------------------------
Ecuador United Kingdom Midstream Total
--------------------------------------------------------
2007 2006 2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net
of Royalties(*) $ - $ 200 $ - $ - $ - $ 477 $ - $ 677
-------------------------------------------------------------------------
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 - - - 5 - 6
(Gain) loss
on discontinuance - 279 - - - (766) - (487)
-------------------------------------------------------------------------
- 420 - - - (378) - 42
-------------------------------------------------------------------------
Net Earnings (Loss)
Before Income Tax - (220) - - - 855 - 635
Income tax
expense - 59 - (5) - - - 54
-------------------------------------------------------------------------
Net Earnings
(Loss) From
Discontinued
Operations $ - $(279) $ - $ 5 $ - $ 855 $ - $ 581
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) Revenues, net of royalties in Ecuador for 2006 include realized
losses of $1 million related to derivative financial instruments.

Contingencies
EnCana agreed to indemnify the purchaser of its Ecuador interests against
losses that may arise in certain circumstances which are defined in the
share sale agreements. The obligation to indemnify will arise should
losses exceed amounts specified in the sale agreements and is limited to
maximum amounts which are set forth in the share sale agreements.
During the second quarter of 2006, the Government of Ecuador seized the
Block 15 assets, in relation to which EnCana previously held a 40 percent
economic interest, from the operator which is an event requiring
indemnification under the terms of EnCana's sale agreement with the
purchaser. The purchaser requested payment and EnCana paid the maximum
amount in the third quarter of 2006, calculated in accordance with the
terms of the agreements, of approximately $265 million. EnCana does not
expect that any further significant indemnification payments relating to
any other business matters addressed in the share sale agreements will be
required to be made to the purchaser.
8. DIVESTITURES
Total year-to-date proceeds received on sale of assets and investments
were $505 million (2006 - $634 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 $66 million (2006 -
$23 million).
Other
In August 2007, the Company closed the sale of its Australia assets for
proceeds of $31 million resulting in a gain on sale of $30 million. After
recording income tax of $5 million, EnCana recorded an after-tax gain of
$25 million.
In 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 $208 million which resulted in a gain on sale of $59 million.
In August 2006, the Company completed the sale of its 50 percent interest
in the Chinook heavy oil discovery offshore Brazil for approximately
$367 million which resulted in a gain on sale of $304 million. After
recording income tax of $49 million, EnCana recorded an after-tax gain of
$255 million.
Market Optimization
In February 2006, the Company sold its investment in Entrega Gas Pipeline
LLC for approximately $244 million which resulted in a gain on sale of
$17 million.
Corporate
In February 2007, the Company sold The Bow office project assets for
proceeds of approximately $57 million, representing its investment at the
date of sale. Refer to Note 6 for further discussion of The Bow office
project assets.
9. INTEREST, NET
Three Months Ended Nine Months Ended
September 30, September 30,
-----------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Interest Expense
- Long-Term Debt $ 113 $ 88 $ 331 $ 269
Interest Expense
- Other(*) 72 9 178 19
Interest Income(*) (83) (14) (212) (34)
-------------------------------------------------------------------------
$ 102 $ 83 $ 297 $ 254
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) 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 Nine Months Ended
September 30, September 30,
-----------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Unrealized Foreign
Exchange (Gain)
Loss on:
Translation of U.S.
dollar debt
issued from Canada $ (278) $ 4 $ (608) $ (155)
Translation of U.S.
dollar partnership
contribution receivable
issued from Canada 252 - 595 -
Other Foreign Exchange
(Gain) Loss 100 (4) 82 (3)
-------------------------------------------------------------------------
$ 74 $ - $ 69 $ (158)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
11. INCOME TAXES
The provision for income taxes is as follows:
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Current
Canada $ 142 $ 105 $ 485 $ 694
United States 172 51 484 87
Other Countries - 45 5 48
-------------------------------------------------------------------------
Total Current Tax 314 201 974 829
-------------------------------------------------------------------------
Future 102 401 (9) 690
-------------------------------------------------------------------------
$ 416 $ 602 $ 965 $ 1,519
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The following table reconciles income taxes calculated at the Canadian
statutory rate with the actual income taxes:
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Net Earnings Before
Income Tax $ 1,350 $ 1,945 $ 3,842 $ 5,927
Canadian Statutory Rate 32.3% 34.7% 32.3% 34.7%
-------------------------------------------------------------------------
Expected Income Tax 436 674 1,241 2,055
Effect on Taxes Resulting from:
Non-deductible Canadian Crown
payments - 23 - 75
Canadian resource allowance - - - (18)
Statutory and other rate
differences 12 (63) 36 (80)
Effect of tax rate changes - - (37) (457)
Effect of legislative changes - - (231) -
Non-taxable downstream
partnership income (21) - (40) -
Non-taxable capital (gains)
losses (32) 3 (44) (30)
Other 21 (35) 40 (26)
-------------------------------------------------------------------------
$ 416 $ 602 $ 965 $ 1,519
-------------------------------------------------------------------------
Effective Tax Rate 30.8% 31.0% 25.1% 25.6%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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, net of payments to date.
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, net of payments to date.
13. INVENTORIES
As at As at
September 30, December 31,
2007 2006
-------------------------------------------------------------------------
Product
Canada $ 1 $ 42
United States 1 -
Integrated Oilsands 633 8
Market Optimization 140 126
-------------------------------------------------------------------------
$ 775 $ 176
-------------------------------------------------------------------------
-------------------------------------------------------------------------
14. LONG-TERM DEBT
As at As at
September 30, December 31,
2007 2006
-------------------------------------------------------------------------
Canadian Dollar Denominated Debt
Revolving credit and term loan borrowings $ 897 $ 1,456
Unsecured notes 1,431 793
-------------------------------------------------------------------------
2,328 2,249
-------------------------------------------------------------------------
U.S. Dollar Denominated Debt
Revolving credit and term loan borrowings - 104
Unsecured notes 4,921 4,421
-------------------------------------------------------------------------
4,921 4,525
-------------------------------------------------------------------------
Increase in Value of Debt Acquired(*) 66 60
Debt Discounts and Financing Costs (69) -
Current Portion of Long-Term Debt (1,000) (257)
-------------------------------------------------------------------------
$ 6,246 $ 6,577
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) Certain of the notes and debentures of EnCana were acquired in
business combinations and were accounted for at their fair value at
the dates of acquisition. The difference between the fair value and
the principal amount of the debt is being amortized over the
remaining life of the outstanding debt acquired, approximately 21
years.

On March 12, 2007, EnCana completed a public offering in Canada of senior
unsecured medium term notes in the aggregate principal amount of
C$500 million. The notes have a coupon rate of 4.3 percent and mature on
March 12, 2012.
On August 13, 2007, EnCana completed a public offering in the United
States of senior unsecured notes in the aggregate principal amount of US
$500 million. The notes have a coupon rate of 6.625 percent and mature on
August 15, 2037.
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
September 30, December 31,
2007 2006
-------------------------------------------------------------------------
Asset Retirement Obligation, Beginning
of Year $ 1,051 $ 816
Liabilities Incurred 61 68
Liabilities Settled (48) (51)
Change in Estimated Future Cash Flows 4 172
Accretion Expense 46 50
Other 158 (4)
-------------------------------------------------------------------------
Asset Retirement Obligation, End of Period $ 1,272 $ 1,051
-------------------------------------------------------------------------
-------------------------------------------------------------------------
16. SHARE CAPITAL
September 30, December 31,
2007 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 7.6 158 8.6 179
Stock-based Compensation - 13 - 11
Common Shares Purchased (36.0) (301) (85.6) (734)
-------------------------------------------------------------------------
Common Shares Outstanding,
End of Period 749.5 $ 4,457 777.9 $ 4,587
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Normal Course Issuer Bid
To September 30, 2007, the Company purchased 38.9 million Common Shares
for total consideration of approximately $2,025 million. Of the amount
paid, $325 million was charged to Share capital and $1,700 million was
charged to Retained earnings. Included in the Common Shares Purchased in
2007 are 2.9 million Common Shares distributed, valued at $24 million,
from the EnCana Employee Benefit Plan Trust that vested under EnCana's
Performance Share Unit Plan (see Note 17). For these Common Shares
distributed, there was an $82 million adjustment to Retained earnings
with a reduction to Paid in surplus of $106 million.
EnCana has received regulatory approval each year under Canadian
securities laws to purchase Common Shares under five consecutive Normal
Course Issuer Bids ("Bids"). EnCana is entitled to purchase, for
cancellation, up to approximately 80.2 million Common Shares under the
renewed Bid which commenced on November 6, 2006 and terminates on
November 5, 2007.
Stock Options
EnCana has stock-based compensation plans that allow employees and
directors to purchase Common Shares of the Company. Option exercise
prices approximate the market price for the Common Shares on the date the
options were issued. Options granted under the plans are generally fully
exercisable after three years and expire five years after the date
granted. Options granted under predecessor and/or related company
replacement plans expire up to 10 years from the date the options were
granted.
The following tables summarize the information about options to purchase
Common Shares that do not have Tandem Share Appreciation Rights ("TSARs")
attached to them at September 30, 2007. Information related to TSARs is
included in Note 17.
Weighted
Stock Average
Options Exercise
(millions) Price (C$)
-------------------------------------------------------------------------
Outstanding, Beginning of Year 11.8 23.17
Exercised (7.6) 23.75
Forfeited (0.1) 22.90
-------------------------------------------------------------------------
Outstanding, End of Period 4.1 22.12
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Exercisable, End of Period 4.1 22.12
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Outstanding Options Exercisable Options
-------------------------------------------------------
Weighted
Average Weighted Weighted
Number of Remaining Average Number of Average
Range of Options Contractual Exercise Options Exercise
Exercise Price Outstanding Life Price Outstanding Price
(C$) (millions) (years) (C$) (millions) (C$)
-------------------------------------------------------------------------
11.00 to 16.99 0.6 2.1 11.58 0.6 11.58
17.00 to 23.49 0.1 1.0 22.86 0.1 22.86
23.50 to 23.99 3.1 0.6 23.89 3.1 23.89
24.00 to 24.99 0.2 0.8 24.51 0.2 24.51
25.00 to 25.99 0.1 1.0 25.61 0.1 25.61
-------------------------------------------------------------------------
4.1 0.8 22.12 4.1 22.12
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
At September 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 September 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 Nine Months Ended
September 30, September 30,
---------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Current Service Cost $ 3 $ 3 $ 11 $ 10
Interest Cost 5 5 14 13
Expected Return on Plan Assets (5) (4) (14) (12)
Expected Actuarial Loss on
Accrued Benefit Obligation 1 1 3 4
Expected Amortization of Past
Service Costs - - 1 1
Amortization of Transitional
Obligation - - (1) (1)
Expense for Defined Contribution
Plan 9 9 25 20
-------------------------------------------------------------------------
Net Benefit Plan Expense $ 13 $ 14 $ 39 $ 35
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
For the period ended September 30, 2007, contributions of $8 million have
been made to the defined benefit pension plans (2006 - $9 million).
B) Share Appreciation Rights ("SARs")
The following table summarizes the information about SARs at
September 30, 2007:
<<
Weighted
Average
Outstanding Exercise
SARs Price
-------------------------------------------------------------------------
U.S. Dollar Denominated (US$)
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 September 30, 2007, EnCana has not recorded any
compensation costs related to the outstanding SARs (2006 - reduction of
$1 million).
C) Tandem Share Appreciation Rights ("TSARs")
The following table summarizes the information about TSARs at
September 30, 2007:
<<
Weighted
Average
Outstanding Exercise
TSARs Price
-------------------------------------------------------------------------
Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 17,276,191 44.99
Granted 4,592,238 56.19
Exercised - SARs (1,704,867) 40.93
Exercised - Options (12,020) 35.15
Forfeited (1,060,528) 50.52
-------------------------------------------------------------------------
Outstanding, End of Period 19,091,014 50.28
-------------------------------------------------------------------------
Exercisable, End of Period 5,401,965 42.90
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
For the period ended September 30, 2007, EnCana recorded compensation
costs of $140 million related to the outstanding TSARs (2006 -
$28 million).
D) Performance-based Tandem Share Appreciation Rights
("Performance TSARs")
In 2007, under the terms of the existing Employee Stock Option Plan,
EnCana granted Performance TSARs under which the employee has the right
to receive a cash payment equal to the excess of the market price of
EnCana Common Shares at the time of exercise over the grant price.
Performance TSARs vest and expire under the same terms and service
conditions as the underlying option, and vesting is subject to the
Company attaining prescribed performance as measured by the annual
recycle ratio. Performance TSARs vest proportionately for a recycle ratio
of greater than one; the maximum number of Performance TSARs vest if the
recycle ratio is three or greater.
The following table summarizes the information about Performance TSARs at
September 30, 2007:
<<
Weighted
Average
Outstanding Exercise
TSARs Price
-------------------------------------------------------------------------
Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year - -
Granted 7,275,575 56.09
Forfeited (327,350) 56.09
-------------------------------------------------------------------------
Outstanding, End of Period 6,948,225 56.09
-------------------------------------------------------------------------
Exercisable, End of Period - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
For the period ended September 30, 2007, EnCana recorded compensation
costs of $9 million related to the outstanding Performance TSARs
(2006 - nil).
E) Deferred Share Units ("DSUs")
The following table summarizes the information about DSUs at
September 30, 2007:
<<
Outstanding Average
DSUs Share Price
-------------------------------------------------------------------------
Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 866,577 29.56
Granted, Directors 77,932 56.85
Exercised (334,615) 29.56
Units, in Lieu of Dividends 7,616 61.20
-------------------------------------------------------------------------
Outstanding, End of Period 617,510 33.39
-------------------------------------------------------------------------
Exercisable, End of Period 617,510 33.39
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
For the period ended September 30, 2007, EnCana recorded compensation
costs of $10 million related to the outstanding DSUs (2006 - $3 million).
F) Performance Share Units ("PSUs")
The following table summarizes the information about PSUs at
September 30, 2007:
<<
Outstanding Average
PSUs Share Price
-------------------------------------------------------------------------
Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 4,766,329 27.48
Granted 18,060 60.90
Distributed (2,937,491) 24.05
Forfeited (160,557) 33.93
-------------------------------------------------------------------------
Outstanding, End of Period 1,686,341 33.19
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
For the period ended September 30, 2007, EnCana recorded compensation
costs of $18 million related to the outstanding PSUs (2006 -
$14 million).
At September 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:
<<
Nine
Three Months Ended Months Ended
-------------------------------------------------------------------------
March June
31, 30, September 30, September 30,
(millions) 2007 2007 2007 2006 2007 2006
-------------------------------------------------------------------------
Weighted Average Common
Shares Outstanding -
Basic 768.4 758.5 750.4 809.7 759.1 829.1
Effect of Dilutive
Securities 11.2 6.7 5.5 14.6 8.4 16.5
-------------------------------------------------------------------------
Weighted Average Common
Shares Outstanding -
Diluted 779.6 765.2 755.9 824.3 767.5 845.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
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 Nine Months Ended
September 30, September 30,
--------------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of Royalties $ 496 $ 199 $ 1,193 $ 153
Operating Expenses and Other 3 1 4 4
-------------------------------------------------------------------------
Gain (Loss) on Risk Management -
Continuing Operations 499 200 1,197 157
Gain (Loss) on Risk Management -
Discontinued Operations - - - 4
-------------------------------------------------------------------------
$ 499 $ 200 $ 1,197 $ 161
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Unrealized Gain (Loss)
--------------------------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of Royalties $ (107) $ 428 $ (673) $ 1,921
Operating Expenses and Other - - 7 (2)
-------------------------------------------------------------------------
Gain (Loss) on Risk Management -
Continuing Operations (107) 428 (666) 1,919
Gain (Loss) on Risk Management -
Discontinued Operations - 5 - 27
-------------------------------------------------------------------------
$ (107) $ 433 $ (666) $ 1,946
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
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 September 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 520 520
Fair Value of Contracts in Place at Transition
that Expired During 2007 - 11
Foreign exchange gains on Canadian dollar
Contracts 2 -
Fair Value of Contracts Realized During 2007 (1,197) (1,197)
-------------------------------------------------------------------------
Fair Value of Contracts Outstanding $ 741 $ (666)
Paid Premiums on Unexpired Options 26
-------------------------------------------------------------------------
Fair Value of Contracts and Premiums Paid,
End of Period $ 767
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
At September 30, 2007, the risk management amounts are recorded in the
Consolidated Balance Sheet as follows:
<<
As at
September 30, 2007
-------------------------------------------------------------------------
Risk Management
Current asset $ 820
Long-term asset 57
Current liability 98
Long-term liability 12
-------------------------------------------------------------------------
Net Risk Management Asset $ 767
-------------------------------------------------------------------------
-------------------------------------------------------------------------
A summary of all unrealized estimated fair value financial positions is
as follows:
As at
September 30, 2007
-------------------------------------------------------------------------
Commodity Price Risk
Natural gas $ 846
Crude oil (103)
Power 22
Credit Derivatives (1)
Interest Rate Risk 3
-------------------------------------------------------------------------
Total Fair Value Positions $ 767
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
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 September 30, 2007, the Company's gas risk management activities from
financial contracts had an unrealized gain of $841 million and a fair
market value position of $846 million. The contracts were as follows:
<<
Notional
Volumes Average Fair Market
(MMcf/d) Term Price Value
-------------------------------------------------------------------------
Sales Contracts
Fixed Price Contracts
NYMEX Fixed Price 1,608 2007 8.80 US$/Mcf $ 262
NYMEX Fixed Price 765 2008 8.49 US$/Mcf 177
Options
Purchased NYMEX Put
Options 240 2007 6.00 US$/Mcf (4)
Basis Contracts
Canada 727 2007 (0.71) US$/Mcf 21
United States 879 2007 (0.71) US$/Mcf 256
Canada 191 2008 (0.78) US$/Mcf 15
United States 849 2008 (1.03) US$/Mcf 100
United States 20 2009 (0.71) US$/Mcf 5
Canada 41 2010-2011 (0.41) US$/Mcf 6
-------------------------------------------------------------------------
838
Other Financial
Positions (*) 3
-------------------------------------------------------------------------
Total Unrealized Gain
on Financial Contracts 841
Paid Premiums on
Unexpired Options 5
-------------------------------------------------------------------------
Total Fair Value
Positions $ 846
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) Other financial positions are part of the ongoing operations of the
Company's proprietary production management.
>>
Crude Oil
At September 30, 2007, the Company's oil risk management activities from
financial contracts had an unrealized loss of $124 million and a fair
market value position of $(103) million. The contracts were as follows:
<<
Notional
Volumes Average Fair Market
(bbls/d) Term Price Value
-------------------------------------------------------------------------
Sales Contracts
Fixed Price Contracts
WTI NYMEX Fixed Price 34,500 2007 64.40 US$/bbl $ (50)
WTI NYMEX Fixed Price 23,000 2008 70.13 US$/bbl (51)
Options
Purchased WTI NYMEX
Put Options 91,500 2007 55.34 US$/bbl (20)
-------------------------------------------------------------------------
(121)
Other Financial
Positions (*) (3)
-------------------------------------------------------------------------
Total Unrealized Loss
on Financial Contracts (124)
Paid Premiums on
Unexpired Options 21
-------------------------------------------------------------------------
Total Fair Value
Positions $ (103)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) 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 September 30, 2007, these contracts had an
unrealized gain of $22 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.
The Bow Office Project
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. Cost of design changes to the building requested
by EnCana and leasehold improvements will be the responsibility of the
Company. The development of The Bow office project remains conditional
upon receipt of certain approvals and conditions being met, failing which
the transaction could be unwound and EnCana would be required to
reimburse the third party developer for the majority of the costs
incurred and to assume the outstanding commitments of the project.
Discontinued Merchant Energy Operations
During the period between 2003 and 2005, EnCana and its indirect wholly
owned U.S. marketing subsidiary, WD Energy Services Inc. ("WD"), along
with other energy companies, were named as defendants in several
lawsuits, some of which were class action lawsuits, relating to sales of
natural gas from 1999 to 2002. The lawsuits allege that the defendants
engaged in a conspiracy with unnamed competitors in the natural gas
markets in California in violation of U.S. and California anti-trust and
unfair competition laws.
Without admitting any liability in the lawsuits, WD agreed to settle all
of the class action lawsuits in both state and federal court, for
payment, of $20.5 million and $2.4 million, respectively. Also, as
previously disclosed, without admitting any liability whatsoever, WD
concluded settlements with the U.S. Commodity Futures Trading Commission
("CFTC") for $20 million and of a previously disclosed consolidated class
action lawsuit in the United States District Court in New York for
$8.2 million.
The remaining lawsuits were commenced by individual plaintiffs, one of
which is E. & J. Gallo Winery ("Gallo"). The Gallo lawsuit claims damages
in excess of $30 million. The other remaining lawsuits do not specify the
precise amount of damages claimed. California law allows for the
possibility that the amount of damages assessed could be tripled.
The Company and WD intend to vigorously defend against the outstanding
claims; however, the Company cannot predict the outcome of these
proceedings or any future proceedings against the Company, whether these
proceedings would lead to monetary damages which could have a material
adverse effect on the Company's financial position, or whether there will
be other proceedings arising out of these allegations.
21. 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 $15.12 Can 0.200

NYSE $11.85 USD 0.160

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