EnCana generates second quarter cash flow of US$2.9 billion, or $3.85 per share – up 16 percent

Second quarter natural gas production up 10 percent to 3.8 billion cubic feet per day

Strong outlook for gas production growth and prices triggers increase to EnCana’s 2008 forecast for cash flow and gas production

CALGARY, July 24 /CNW/ - EnCana Corporation (TSX & NYSE: ECA) achieved
strong increases in cash flow and operating earnings in the second quarter of
2008 as a result of solid performance from the company's North American
portfolio of resource plays and substantial increases in commodity prices.
"Once again our strong operating results demonstrate the substantial
value-creation capacity of our resource play strategy. Second quarter cash
flow per share and operating earnings per share increased 16 and 9 percent
respectively over last year while natural gas production is ahead of
expectations. Led by the East Texas, Jonah, Bighorn and Alberta coalbed
methane (CBM) resource plays, our low-risk portfolio of unconventional
resources continues to deliver sustainable growth across North America. In the
second quarter, the upstream business of our Integrated Oil division, in
particular, benefited from significantly higher field prices," said Randy
Eresman, EnCana's President & Chief Executive Officer.
EnCana expanding investments in North American resource portfolio
"With natural gas production growing faster than forecast and stronger
than expected prices, we are raising our 2008 cash flow forecast to a range of
$10 billion to $11 billion from a current level of $9.6 billion to $10
billion. Our full-year gas production forecast is also increasing to an
expected average of 3.85 Bcf/d. We are directing the higher than originally
forecast cash flows into growing our already strong position in the
Haynesville Shale in Louisiana, where recent test wells are demonstrating very
strong potential. At the same time, we are stepping up our divestiture program
for the remainder of the year to offset the additional costs of expanding
shale gas lands and resources," Eresman said.
Shale plays continue to show promise
"In the second quarter we announced an expansion of our sizeable position
in British Columbia's Horn River and Louisiana's Haynesville natural gas shale
plays. At Horn River, two of our recently completed wells are producing at a
very strong first-month average rate in excess of 5 million cubic feet per day
(MMcf/d). At Haynesville, during a two-day test, the initial flow rate of a
second horizontal well was 15 MMcf/d. These well results are exceptional and
are a strong indication that the addition of these plays has the potential to
accelerate the pace of our natural gas growth," Eresman said.
Integrated Oil production growth set to ramp up
"At Foster Creek, first production from our newest expansion phase, which
will add 30,000 bbls/d of gross production capacity, is expected to start
ramping up in the fourth quarter 2008. The next 30,000 bbls/d phase is
expected to be completed in the first quarter of 2009. Combined, these two
phases are scheduled to double our gross production capacity at Foster Creek
to 120,000 bbls/d. Production is forecast to begin ramping up later this year
and continue through 2009. At Christina Lake, we are steaming wells in our
recently completed expansion, which is expected to increase our gross
production capacity to 18,000 bbls/d by the end of the year, with production
ramping up through 2009," Eresman said.
"Plans for splitting EnCana into two strong independent companies focused
on distinct businesses - unconventional natural gas (GasCo) and integrated oil
(IOCo) - are proceeding well and we are working towards completing the
transaction early in 2009," Eresman said.
Second Quarter 2008 Highlights
------------------------------
(all year-over-year comparisons are to the second quarter of 2007)
Financial
<<
- Cash flow increased 16 percent per share to $3.85, or $2.9 billion
- Operating earnings were up 9 percent per share to $1.96, or
$1.5 billion
- Net earnings were down 14 percent per share to $1.63, or
$1.2 billion, primarily due to unrealized mark-to-market losses on
risk management activities of $235 million after-tax compared to
gains of $47 million after-tax in 2007
- Operating cash flow generated from the Integrated Oil division
totalled $527 million, comprised of $185 million from the upstream
operations, a 59 percent increase due to strong field prices, and
$342 million from the downstream business, a decrease of 22 percent
due to weaker refining margins
- Capital investment was in line with guidance at $1.7 billion, up
about 47 percent in large part due to continued development of East
Texas and other key resource plays, as well as the expansion of the
company's upstream and downstream integrated oil capacity
- Free cash flow decreased $206 million to $1.2 billion (free cash flow
is defined in Note 1 on page 8)
- Realized natural gas prices were up 12 percent to $8.54 per thousand
cubic feet (Mcf) and realized liquids prices increased 99 percent to
$90.47 per barrel (bbl). These prices include the impact of financial
hedges
- EnCana purchased approximately 200,000 common shares at an average
share price of $74.81 under the Normal Course Issuer Bid, for a total
cost of $15 million.
Operating - Upstream
- Key resource play production was up 14 percent, with a 17 percent
increase in natural gas production and oil production down 9 percent
- Total natural gas production increased 10 percent to 3.8 billion
cubic feet per day (Bcf/d), up 11 percent per share
- Total oil and natural gas liquids (NGLs) production decreased 4
percent to approximately 128,000 barrels per day (bbls/d), down 3
percent per share
- Oil production at Foster Creek and Christina Lake was down 12 percent
to approximately 24,700 bbls/d (net to EnCana) due to an extended
turnaround in the second quarter at Foster Creek. Current net
production is about 30,000 bbls/d
- Operating and administrative costs of $1.71 per thousand cubic feet
equivalent (Mcfe) increased 46 percent from $1.17 per Mcfe one year
earlier. More than half of the increase was due to long-term
incentive costs and an appreciation of the Canadian dollar compared
to the U.S. dollar. When those items are factored out, operating and
administrative costs were in line with guidance of $1.40 per Mcfe.
The rest of the increase was due to reorganization costs, increased
activity levels and other administrative costs.
Operating - Downstream
- Refined products averaged 464,000 bbls/d (232,000 bbls/d net to
EnCana), up 10 percent
- Refinery crude utilization of 97 percent or 437,000 bbls/d crude
throughput (218,500 bbls/d net to EnCana), up 10 percent, from the
second quarter of 2007, due to a major turnaround and new coker
startup at the Borger refinery in June, 2007.
>>
Guidance for total cash flow increases to a range of $10 billion to
$11 billion
Based on the company's strong cash flow performance to date and natural
gas production and commodity price expectations for the remainder of the year,
EnCana is increasing its 2008 guidance for total cash flow to a range of $10
billion to $11 billion, or between $13.30 and $14.65 per share. EnCana is also
increasing its natural gas production forecast by 70 MMcf/d to 3.85 Bcf/d, or
8 percent higher than 2007 gas production. Key gas resource play production in
2008 is now expected to average 3.14 Bcf/d, up 60 MMcf/d. Production from the
company's Foster Creek and Christina Lake projects is now expected to average
about 31,000 bbls/d, down about 3,000 bbls/d due to an unexpected power outage
and an extended plant turnaround in the second quarter at Foster Creek. As
well, the company is planning a more ambitious divestiture program. Proceeds
from planned asset sales are expected to offset additional land purchases in
2008, resulting in net proceeds from acquisitions and divestitures of $500
million, which is in line with guidance. Updated guidance is posted on the
company's website www.encana.com.

Managing costs through long-term drilling contracts
"As a result of higher commodity prices and increased activity, we are
seeing signs of cost inflation in services and materials - particularly for
steel and fuels, and we believe inflationary pressure may continue to climb
the rest of the year. EnCana has largely managed to offset inflationary
pressures to date through a series of long-term contracts. For example, we
have been working to lock in longer-term contracts for our well fracturing
services. The majority of these contracts are priced at current levels.
Significant portions of our steel requirements were contracted early so that
we have the benefit of those more favourable cost levels. Going forward, we
will continue to pursue cost management opportunities when possible," Eresman
said.
Key resource play natural gas production up 17 percent in second quarter
Total natural gas production increased 10 percent in the second quarter
to 3.8 Bcf/d, driven by a 17 percent increase in EnCana's natural gas key
resource plays to 3.15 Bcf/d. In the U.S. increases were led by East Texas at
127 percent as a result of drilling success as well as incremental volumes
from the Deep Bossier acquisition. In the Canadian Foothills natural gas
production was up 5 percent, with drilling success and new facilities in the
key resource plays of Bighorn in west central Alberta, CBM in central Alberta
and Cutbank Ridge straddling the British Columbia-Alberta boundary.
Integrated Oil benefits from higher oil prices
Integrated Oil generated $527 million in operating cash flow, down
slightly from $557 million in the same quarter of 2007. The upstream business
benefited from a 138 percent increase in the average heavy oil price to $93.64
per bbl at Foster Creek and Christina Lake. Operating cash flow from the
downstream business was impacted by significantly weaker refining margins.
Operating cash flow for the second quarter includes $172 million related to
lower purchased product costs as a result of accounting for inventory based on
a first-in first-out valuation which is required under Canadian generally
accepted accounting principles. This inventory valuation methodology results
in lower product charges to operations in a rising input cost environment. The
Chicago 3-2-1 crack spread averaged $13.60 per bbl in the quarter, down 55
percent from $30.12 per bbl from the same period last year when crack spreads
reached record levels as gasoline inventories were drawn down to five-year
lows. The weaker refining margins were offset by the higher upstream pricing,
which demonstrates the benefit of the company's integration strategy. Second
quarter oil production at Foster Creek and Christina Lake was down 12 percent
to about 24,700 bbls/d (net to EnCana), primarily due to an extended scheduled
turnaround at Foster Creek. Current net production is approximately 30,000
bbls/d.
IMPORTANT NOTE: Effective January 2, 2007, EnCana established an
integrated oil business with ConocoPhillips, which resulted in EnCana
contributing its interests in Foster Creek and Christina Lake into an
upstream partnership owned 50-50 by the two companies. Production and
wells drilled from 2006 have been adjusted on a pro forma basis to
reflect the integrated oil transaction. Per share amounts for cash flow
and earnings are on a diluted basis. EnCana reports in U.S. dollars
unless otherwise noted and follows U.S. protocols, which report
production, sales and reserves on an after-royalties basis. The company's
financial statements are prepared in accordance with Canadian generally
accepted accounting principles (GAAP).
<<
-------------------------------------------------------------------------
Financial Summary - Total Consolidated
-------------------------------------------------------------------------
(for the six months
ended June 30) 6 6
($ millions, except Q2 Q2 % months months %
per share amounts) 2008 2007 change 2008 2007 change
-------------------------------------------------------------------------
Cash flow(1) 2,889 2,549 +13 5,278 4,301 +23
Per share diluted 3.85 3.33 +16 7.02 5.56 +26
-------------------------------------------------------------------------
Operating earnings(1) 1,469 1,369 +7 2,514 2,219 +13
Per share diluted 1.96 1.79 +9 3.34 2.87 +16
-------------------------------------------------------------------------
Net earnings 1,221 1,446 -16 1,314 1,943 -32
Per share diluted 1.63 1.89 -14 1.75 2.51 -30
-------------------------------------------------------------------------
Earnings Reconciliation Summary - Total Consolidated
-------------------------------------------------------------------------
Net earnings (loss) 1,221 1,446 1,314 1,943
(Add back losses &
deduct gains) (235) 47 (972) (376)
Unrealized mark-to-market
hedging gain (loss),
after-tax (13) (7) (228) 4
Non-operating foreign
exchange gain (loss),
after-tax Gain (loss) on
discontinuance, after-tax - - - 59
Future tax recovery due
to tax rate reductions - 37 - 37
-------------------------------------------------------------------------
Operating earnings(1) 1,469 1,369 +7 2,514 2,219 +13
Per share diluted 1.96 1.79 +9 3.34 2.87 +16
-------------------------------------------------------------------------
(1) Cash flow and operating earnings are non-GAAP measures as defined in
Note 1 on Page 8.
-------------------------------------------------------------------------
Production & Drilling Summary
-------------------------------------------------------------------------
Total Consolidated
-------------------------------------------------------------------------
(for the six months 6 6
ended June 30) Q2 Q2 % months months %
(After royalties) 2008 2007 change 2008 2007 change
-------------------------------------------------------------------------
Natural Gas (MMcf/d) 3,841 3,506 +10 3,787 3,454 +10
-------------------------------------------------------------------------
Natural gas production
per 1,000 shares (Mcf) 466 421 +11 919 819 +12
-------------------------------------------------------------------------
Oil and NGLs (Mbbls/d) 128 133 -4 132 132 -
-------------------------------------------------------------------------
Oil and NGLs production
per 1,000 shares (Mcfe) 93 96 -3 193 188 +3
-------------------------------------------------------------------------
Total Production (MMcfe/d) 4,607 4,306 +7 4,582 4,246 +8
-------------------------------------------------------------------------
Total per 1,000 shares
(Mcfe) 559 517 +8 1,112 1,007 +10
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net wells drilled 409 569 -28 1,552 1,833 -15
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Growth from key North American resource plays
-------------------------------------------------------------------------
Resource Play Daily Production
------------------------------------------------------------
2008 2007 2006
------------------------------------------------------------
(After Full Full
royalties) YTD Q2 Q1 Year Q4 Q3 Q2 Q1 Year
-------------------------------------------------------------------------
Natural Gas (MMcf/d)
Jonah 613 630 595 557 612 588 523 504 464
Piceance 377 383 372 348 351 354 349 334 326
East
Texas 294 316 273 143 187 144 139 103 99
Fort
Worth 138 137 140 124 138 128 124 106 101
Greater
Sierra 211 219 205 211 221 220 219 186 213
Cutbank
Ridge(1) 275 280 271 258 283 269 248 232 189
Bighorn(1) 158 170 146 126 136 136 122 109 97
CBM 300 303 298 259 283 256 245 251 194
Shallow
Gas 713 712 715 726 727 713 729 735 739
-------------------------------------------------------------------------
Total natural
gas(1)
(MMcf/d) 3,079 3,150 3,015 2,752 2,938 2,808 2,698 2,560 2,422
-------------------------------------------------------------------------
Oil (Mbbls/d)
Foster
Creek 24 21 27 24 25 26 25 20 18
Christina
Lake 3 4 2 3 2 3 3 3 3
Pelican
Lake 23 21 24 23 24 24 23 23 24
Weyburn(2) 14 13 14 15 14 15 14 15 15
-------------------------------------------------------------------------
Total oil
(Mbbls/d)(2) 64 59 67 65 65 68 65 61 60
-------------------------------------------------------------------------
Total
(MMcfe/d)
(1),(2) 3,464 3,506 3,417 3,142 3,328 3,210 3,088 2,926 2,782
-------------------------------------------------------------------------
% change
from prior
period +2.6 +2.7 +12.9 +3.7 +4.0 +5.5 +9.2
-------------------------------------------------------------------------
(1) Key resource play production volumes in 2007 and 2006 for Cutbank
Ridge and Bighorn were restated to include the addition of new areas
and zones that now qualify for key resource play inclusion based on
EnCana's internal criteria.
(2) Total key resource play production volumes in 2007 and 2006 were
restated in the first quarter of 2008 to include the designation of
Weyburn as an oil key resource play.

Drilling activity in key North American resource plays
-------------------------------------------------------------------------
Resource Play Net Wells Drilled
------------------------------------------------------------
2008 2007 2006
------------------------------------------------------------
Full Full
YTD Q2 Q1 Year Q4 Q3 Q2 Q1 Year
-------------------------------------------------------------------------
Natural Gas
Jonah 92 49 43 135 23 31 42 39 163
Piceance 164 81 83 286 77 72 72 65 220
East Texas 33 22 11 35 8 9 11 7 59
Fort Worth 41 20 21 75 15 17 29 14 97
Greater
Sierra 63 27 36 109 27 27 32 23 115
Cutbank
Ridge(1) 48 24 24 93 11 23 26 33 134
Bighorn(1) 48 18 30 62 6 18 10 28 58
CBM 261 10 251 1,079 330 323 18 408 729
Shallow
Gas 579 83 496 1,914 649 608 241 416 1,310
-------------------------------------------------------------------------
Total gas
wells(1) 1,329 334 995 3,788 1,146 1,128 481 1,033 2,885
-------------------------------------------------------------------------
Oil
Foster
Creek 13 1 12 23 6 8 1 8 3
Christina
Lake - - - 3 - 1 2 - 1
Pelican
Lake - - - - - - - - -
Weyburn(2) 14 5 9 37 10 9 9 9 35
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total oil
wells(2) 27 6 21 63 16 18 12 17 39
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total
(1),(2) 1,356 340 1,016 3,851 1,162 1,146 493 1,050 2,924
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Key resource play net wells drilled in 2007 and 2006 for Cutbank
Ridge and Bighorn were restated to include the addition of new areas
and zones that now qualify for key resource play inclusion based on
EnCana's internal criteria.
(2) Total key resource play net wells drilled in 2007 and 2006 were
restated in the first quarter of 2008 to include the designation of
Weyburn as an oil key resource play.
>>
Natural gas shale resource play update
EnCana announced on June 16, 2008 that it has established a leading land
and resource position in the Horn River Shale in northeast British Columbia
and the Haynesville Shale in Louisiana and Texas. EnCana has drilled several
exploration wells that have shown strong potential to deliver commercial
volumes of natural gas. At Horn River, two of EnCana's recently completed
wells are producing at a very strong first-month average rate in excess of 5
MMcf/d. In the Haynesville Shale play, EnCana has early results from its
second horizontal well, which flowed at an initial two-day rate of 15 MMcf/d.
In the second quarter EnCana increased its leased acreage in the Haynesville
Shale play to 370,000 net acres through a series of transactions. The company
also reached an agreement in July, 2008 to acquire an additional 89,000 acres
of mineral rights from Indigo Minerals LLC for $457 million.
<<
Second quarter 2008 natural gas and oil prices
-------------------------------------------------------------------------
6 6
Q2 Q2 % months months %
2008 2007 change 2008 2007 change
-------------------------------------------------------------------------
Natural gas ($/Mcf)
NYMEX 10.93 7.55 +45 9.48 7.16 +32
EnCana realized gas
price(1) 8.54 7.62 +12 8.29 7.43 +12
-------------------------------------------------------------------------
Oil and NGLs ($/bbl)
WTI 123.80 65.02 +90 111.12 61.68 +80
Western Canadian Select
(WCS) 102.18 45.84 +123 89.58 43.85 +104
Differential WTI/WCS 21.62 19.18 +13 21.54 17.83 +21
EnCana realized liquids
price(1) 90.47 45.47 +99 79.77 44.02 +81
-------------------------------------------------------------------------
Chicago 3-2-1 crack
spread ($bbl) 13.60 30.12 -55 10.65 21.51 -50
-------------------------------------------------------------------------
(1) Realized prices include the impact of financial hedging.
>>
Price risk management
Risk management positions at June 30, 2008 are presented in Note 17 to
the unaudited Interim Consolidated Financial Statements. In the second quarter
of 2008, EnCana's commodity price risk management measures resulted in
realized losses of approximately $400 million after-tax, composed of a $308
million after-tax loss on gas hedges, and a $92 million after-tax loss on oil
and other hedges. The realized losses in the second quarter reflect the
dramatic increase in oil prices in the past year and natural gas prices over
the past few months compared to the portion of EnCana's sales that are hedged
at fixed prices - a risk management strategy that is aimed at providing more
certainty of cash flow to fund the company's annual capital investment
program. EnCana has hedged about 1.5 Bcf/d of expected 2008 gas production for
the balance of the year at an average NYMEX equivalent price of $8.20 per Mcf.
EnCana has about 23,000 bbls/d of expected 2008 oil production hedged for the
balance of the year under fixed price contracts at an average West Texas
Intermediate (WTI) price of $70.13 per bbl. For 2009, EnCana has 391 MMcf/d of
its expected natural gas production under fixed price contracts at an average
NYMEX equivalent price of $9.85 per Mcf and 341 MMcf/d under NYMEX put options
at an average strike of $8.85 per Mcf.
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. These price discounts are called basis
differentials. EnCana has hedged 100 percent of its expected U.S. Rockies
basis exposure in 2008 using a combination of downstream transportation and
basis hedges, including some hedges that are based on a percentage of NYMEX
prices. At June 30, 2008, U.S. basis hedges, a combination of Rockies, Mid-
Continent and San Juan instruments, had an effective average differential to
NYMEX of $1.66 per Mcf for the rest of 2008. EnCana has also hedged about 8
percent of its expected 2008 Canadian gas production at an average AECO basis
differential of 76 cents per Mcf.
Corporate developments
----------------------
Quarterly dividend of 40 cents per share declared
EnCana's Board of Directors has declared a quarterly dividend of 40 cents
per share payable on September 30, 2008 to common shareholders of record as of
September 15, 2008. Based on the July 23, 2008 closing share price on the New
York Stock Exchange of $72.62, this represents an annualized yield of about
2.2 percent.
Corporate reorganization to create two energy companies focused on
unconventional resources
On May 11, 2008, EnCana announced plans to split into two highly focused
energy companies - one a North American natural gas company and the other a
fully integrated oil company with in-situ oil properties and refineries
supplemented by reliable production from natural gas and crude oil resource
plays. The proposed corporate reorganization, expected to close in early 2009,
would be implemented through a Plan of Arrangement and is subject to
shareholder and court approval. An information circular setting out the
details of the Plan of Arrangement is expected to be mailed to EnCana
shareholders in November, followed by a shareholders meeting planned for mid
December. The working names of the two companies are GasCo and IOCo. GasCo
will retain the name of EnCana Corporation while the permanent name of IOCo
will be determined prior to the close of the transaction. For further
information on the announcement see the company's website www.encana.com.
Normal Course Issuer Bid
In the second quarter of 2008, EnCana purchased for cancellation
approximately 200,000 common shares at an average price of $74.81 per share
under the company's Normal Course Issuer Bid for a total cost of $15 million.
As a result of the proposed corporate reorganization, the company has
suspended further purchases for 2008.
Financial strength
------------------
EnCana maintains a strong balance sheet, targeting a net debt-to-
capitalization ratio between 30 and 40 percent and a net debt-to-adjusted-
EBITDA multiple, on a trailing 12-month basis, of 1 to 2 times. At June 30,
2008, EnCana's net debt-to-capitalization ratio was 36 percent, including
mark- to-market losses on risk management instruments, which increased net
debt. Excluding this mark-to-market impact, the net debt-to-capitalization
ratio would have been 34 percent. EnCana's net debt-to-adjusted-EBITDA
multiple, on a trailing 12-month basis, was 1.3 times at the end of the second
quarter. The company expects to be in the lower end of its managed ranges by
year-end.
In the quarter, EnCana invested $1.7 billion in capital, excluding
acquisitions and divestitures, on continued development of its key resource
plays and expansion of the company's downstream heavy oil processing capacity
through its joint venture with ConocoPhillips.
<<
-------------------------------------------------------------------------
CONFERENCE CALL TODAY
11 a.m. Mountain Time (1 p.m. Eastern Time)
EnCana Corporation will host a conference call today, Thursday, July 24,
2008, starting at 11 a.m. MT (1 p.m. ET). To participate, please dial
(866) 321-6651 (toll-free in North America) or (416) 642-5212 and quote
confirmation code 7198404 approximately 10 minutes prior to the
conference call. An archived recording of the call will be available from
approximately 3 p.m. MT on July 24 until midnight July 31, 2008 by
dialling (888) 203-1112 or (647) 436-0148 and entering access
code 7198404.
A live audio webcast of the conference call will also be available via
EnCana's website, www.encana.com, under Investor Relations. The webcast
will be archived for approximately 90 days.
-------------------------------------------------------------------------

NOTE 1: Non-GAAP measures
This news release contains references to cash flow, operating earnings,
free cash flow, net debt, capitalization and adjusted earnings before
interest, tax, depreciation and amortization (EBITDA).
- 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.
- Operating earnings is a non-GAAP measure that shows net earnings
excluding non-operating items such as the after-tax impacts of a
gain/loss on discontinuance, the after-tax gain/loss of unrealized
mark-to-market accounting for derivative instruments, the after-tax
gain/loss on translation of U.S. dollar denominated debt issued from
Canada and the partnership contribution receivable, the after-tax
foreign exchange gain/loss on settlement of intercompany
transactions, future income tax on foreign exchange related to U.S.
dollar intercompany debt recognized for tax purposes only, and the
effect of changes in statutory income tax rates. Management believes
that these excluded items reduce the comparability of the company's
underlying financial performance between periods. The majority of
U.S. dollar debt issued from Canada has maturity dates in excess of
five years.
- Free cash flow is a non-GAAP measure that EnCana defines as cash flow
in excess of capital investment, excluding net acquisitions and
divestitures, and is used to determine the funds available for other
investing and/or financing activities.
- Net debt is a non-GAAP measure defined as long-term debt plus current
liabilities less current assets. Capitalization is a non-GAAP measure
defined as net debt plus shareholders' equity. Net debt to
capitalization and net debt to adjusted EBITDA are two ratios
management uses to steward the company's overall debt position as
measures of the company's overall financial strength.
- Adjusted EBITDA is a non-GAAP measure defined as net earnings from
continuing operations before gains or losses on divestitures, income
taxes, foreign exchange gains or losses, interest net, accretion of
asset retirement obligation, and depreciation, depletion and
amortization.
>>
These measures have been described and presented in this news release in
order to provide shareholders and potential investors with additional
information regarding EnCana's liquidity and its ability to generate funds to
finance its operations.
EnCana Corporation
With an enterprise value of approximately $70 billion, EnCana is a
leading North American unconventional natural gas and integrated oil company.
By partnering with employees, community organizations and other businesses,
EnCana contributes to the strength and sustainability of the communities where
it operates. EnCana common shares trade on the Toronto and New York stock
exchanges under the symbol ECA.
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: projections relating to future
economic and operating performance (including per share growth, net debt-to-
capitalization and net debt-to-adjusted-EBITDA ratios, cash flow, free cash
flow, and cash flow per share); the anticipated ability to meet the company's
guidance forecasts; anticipated growth and success of various resource plays
and the expected characteristics of such resource plays; the future drilling
and production potential for various regions, including East Texas and the
Horn River and Haynesville natural gas shale plays; projections relating to
the proposed corporate reorganization transaction, including the expected
timing for mailing an information circular to shareholders, holding a
shareholders meeting and the potential closing date; projections of crude oil
and natural gas prices, including basis differentials for various regions;
anticipated expansion and production at Foster Creek and Christina Lake;
projections for future crack spreads and refining margins; anticipated effects
of EnCana's market risk mitigation strategy; projections for 2008 capital
expenditures and investment; projections for oil, natural gas and NGLs
production in 2008 and beyond; anticipated costs and inflationary pressures;
and potential divestitures, proceeds which may be generated there from and the
potential use of such proceeds. Readers are cautioned not to place undue
reliance on forward-looking statements, as there can be no assurance that the
plans, intentions or expectations upon which they are based will occur. By
their nature, forward- looking statements involve numerous assumptions, known
and unknown risks and uncertainties, both general and specific, that
contribute to the possibility that the predictions, forecasts, projections and
other forward-looking statements will not occur, which may cause the company's
actual performance and financial results in future periods to differ
materially from any estimates or projections of future performance or results
expressed or implied by such forward-looking statements. These risks and
uncertainties include, among other things: volatility of and assumptions
regarding oil and gas prices; assumptions based upon the company's current
guidance; fluctuations in currency and interest rates; product supply and
demand; market competition; risks inherent in the company's marketing
operations, including credit risks; imprecision of reserves estimates and
estimates of recoverable quantities of oil, natural gas and liquids from
resource plays and other sources not currently classified as proved reserves;
the ability of the company and ConocoPhillips to successfully manage and
operate the integrated North American oil business and the ability of the
parties to obtain necessary regulatory approvals; refining and marketing
margins; potential disruption or unexpected technical difficulties in
developing new products and manufacturing processes; potential failure of new
products to achieve acceptance in the market; unexpected cost increases or
technical difficulties in constructing or modifying manufacturing or refining
facilities; unexpected difficulties in manufacturing, transporting or refining
synthetic crude oil; risks associated with technology; the company's ability
to replace and expand oil and gas reserves; its ability to generate sufficient
cash flow from operations to meet its current and future obligations; its
ability to access external sources of debt and equity capital; the timing and
the costs of well and pipeline construction; the company's ability to secure
adequate product transportation; changes in royalty, tax, environmental and
other laws or regulations or the interpretations of such laws or regulations;
political and economic conditions in the countries in which the company
operates; the risk of war, hostilities, civil insurrection and instability
affecting countries in which the company operates and terrorist threats; risks
associated with existing and potential future lawsuits and regulatory actions
made against the company; and other risks and uncertainties described from
time to time in the reports and filings made with securities regulatory
authorities by EnCana. Although EnCana believes that the expectations
represented by such forward-looking statements are reasonable, there can be no
assurance that such expectations will prove to be correct. Readers are
cautioned that the foregoing list of important factors is not exhaustive.
Forward-looking information respecting anticipated 2008 cash flow,
operating cash flow and pre-tax cash flow for EnCana, and for GasCo and IOCo
pro-forma the proposed reorganization transaction, is based upon achieving
average production of oil and gas for 2008 as set out above, average commodity
prices for 2008 based on actual results for the second quarter of 2008, and
for the balance of 2008, a WTI price of $130/bbl for oil, a NYMEX price of
$11.00/Mcf for natural gas, an average U.S./Canadian dollar foreign exchange
rate of $0.98, an average Chicago crack spread for 2008 of $10.00/bbl for
refining margins, and an average number of outstanding shares for EnCana of
approximately 750 million. Assumptions relating to forward-looking statements
generally include EnCana's current expectations and projections made by the
company in light of, and generally consistent with, its historical experience
and its perception of historical trends, as well as expectations regarding
rates of advancement and innovation, generally consistent with and informed by
its past experience, all of which are subject to the risk factors identified
elsewhere in this document.
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.
Further information on EnCana Corporation is available on the company's
website, www.encana.com. For EnCana video, visit www.thenewsmarket.com/EnCana.
Free delivery options include digital FTP transfer, Beta SP tape, Data-DVD and
streaming download (Flash, QuickTime and Windows Media).

<<
EnCana Corporation
Interim Consolidated Financial Statements
(unaudited)
For the period ended June 30, 2008
(U.S. Dollars)

CONSOLIDATED STATEMENT OF EARNINGS (unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
($ millions, except per ----------------------------------------
share amounts) 2008 2007 2008 2007
-------------------------------------------------------------------------
REVENUES, NET OF
ROYALTIES (Note 5) $ 7,321 $ 5,613 $ 12,663 $ 10,049
EXPENSES (Note 5)
Production and mineral
taxes 154 57 268 149
Transportation and
selling 326 234 646 512
Operating 709 565 1,405 1,116
Purchased product 2,882 1,836 5,275 3,687
Depreciation, depletion
and amortization 1,097 899 2,132 1,742
Administrative 225 95 381 190
Interest, net (Note 7) 147 94 281 195
Accretion of asset
retirement obligation (Note 12) 20 15 41 29
Foreign exchange (gain)
loss, net (Note 8) (35) 7 60 (5)
(Gain) loss on
divestitures (Note 6) (17) 1 (17) (58)
-------------------------------------------------------------------------
5,508 3,803 10,472 7,557
-------------------------------------------------------------------------
NET EARNINGS BEFORE INCOME TAX 1,813 1,810 2,191 2,492
Income tax expense (Note 9) 592 364 877 549
-------------------------------------------------------------------------
NET EARNINGS $ 1,221 $ 1,446 $ 1,314 $ 1,943
-------------------------------------------------------------------------
-------------------------------------------------------------------------

NET EARNINGS PER
COMMON SHARE (Note 16)
Basic $ 1.63 $ 1.91 $ 1.75 $ 2.54
Diluted $ 1.63 $ 1.89 $ 1.75 $ 2.51
-------------------------------------------------------------------------
-------------------------------------------------------------------------

CONSOLIDATED STATEMENT OF RETAINED EARNINGS (unaudited)
Six Months Ended
June 30,
--------------------
($ millions) 2008 2007
-------------------------------------------------------------------------
RETAINED EARNINGS,
BEGINNING OF YEAR $ 13,082 $ 11,344
Net Earnings 1,314 1,943
Dividends on Common Shares (600) (304)
Charges for Normal Course
Issuer Bid (Note 13) (243) (1,421)
-------------------------------------------------------------------------
RETAINED EARNINGS, END OF PERIOD $ 13,553 $ 11,562
-------------------------------------------------------------------------
-------------------------------------------------------------------------

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
----------------------------------------
($ millions) 2008 2007 2008 2007
-------------------------------------------------------------------------
NET EARNINGS $ 1,221 $ 1,446 $ 1,314 $ 1,943
OTHER COMPREHENSIVE INCOME,
NET OF TAX
Foreign Currency
Translation Adjustment 48 828 (352) 939
-------------------------------------------------------------------------
COMPREHENSIVE INCOME $ 1,269 $ 2,274 $ 962 $ 2,882
-------------------------------------------------------------------------
-------------------------------------------------------------------------

CONSOLIDATED STATEMENT OF ACCUMULATED OTHER COMPREHENSIVE INCOME
(unaudited)
Six Months Ended
June 30,
--------------------
($ millions) 2008 2007
-------------------------------------------------------------------------
ACCUMULATED OTHER COMPREHENSIVE INCOME,
BEGINNING OF YEAR $ 3,063 $ 1,375
Foreign Currency Translation Adjustment (352) 939
-------------------------------------------------------------------------
ACCUMULATED OTHER COMPREHENSIVE INCOME,
END OF PERIOD $ 2,711 $ 2,314
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.

CONSOLIDATED BALANCE SHEET (unaudited)
As at As at
June 30, December 31,
($ millions) 2008 2007
-------------------------------------------------------------------------
ASSETS
Current Assets
Cash and cash equivalents $ 778 $ 553
Accounts receivable and
accrued revenues 3,346 2,381
Current portion of
partnership contribution
receivable 305 297
Risk management (Note 17) 265 385
Inventories (Note 10) 1,422 828
-------------------------------------------------------------------------
6,116 4,444
Property, Plant and
Equipment, net (Note 5) 37,070 35,865
Investments and Other Assets 654 607
Partnership Contribution Receivable 2,992 3,147
Risk Management (Note 17) 341 18
Goodwill 2,821 2,893
-------------------------------------------------------------------------
(Note 5) $ 49,994 $ 46,974
-------------------------------------------------------------------------
-------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable and
accrued liabilities $ 4,888 $ 3,982
Income tax payable 909 1,150
Current portion of
partnership contribution
payable 297 288
Risk management (Note 17) 1,617 207
Current portion of
long-term debt (Note 11) 491 703
-------------------------------------------------------------------------
8,202 6,330
Long-Term Debt (Note 11) 9,878 8,840
Other Liabilities 450 242
Partnership Contribution
Payable 3,012 3,163
Risk Management (Note 17) 73 29
Asset Retirement
Obligation (Note 12) 1,402 1,458
Future Income Taxes 6,160 6,208
-------------------------------------------------------------------------
29,177 26,270
-------------------------------------------------------------------------
Shareholders' Equity
Share capital (Note 13) 4,553 4,479
Paid in surplus - 80
Retained earnings 13,553 13,082
Accumulated other comprehensive income 2,711 3,063
-------------------------------------------------------------------------
Total Shareholders' Equity 20,817 20,704
-------------------------------------------------------------------------
$ 49,994 $ 46,974
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.

CONSOLIDATED STATEMENT OF CASH FLOWS (unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
----------------------------------------
($ millions) 2008 2007 2008 2007
-------------------------------------------------------------------------
OPERATING ACTIVITIES
Net earnings $ 1,221 $ 1,446 $ 1,314 $ 1,943
Depreciation, depletion
and amortization 1,097 899 2,132 1,742
Future income taxes (Note 9) 152 79 73 (111)
Unrealized (gain) loss
on risk management (Note 17) 318 (55) 1,411 559
Unrealized foreign
exchange (gain) loss (11) 79 65 76
Accretion of asset
retirement obligation (Note 12) 20 15 41 29
(Gain) loss on
divestitures (Note 6) (17) 1 (17) (58)
Other 109 85 259 121
Net change in other
assets and liabilities (171) (16) (264) 4
Net change in non-cash
working capital (722) (385) (1,260) (249)
-------------------------------------------------------------------------
Cash From Operating Activities 1,996 2,148 3,754 4,056
-------------------------------------------------------------------------
INVESTING ACTIVITIES
Capital expenditures (Note 5) (1,996) (1,189) (3,903) (2,679)
Proceeds from
divestitures (Note 6) 79 165 151 446
Net change in investments
and other (18) (25) (9) (6)
Net change in non-cash
working capital (101) (45) 191 (103)
-------------------------------------------------------------------------
Cash (Used in) Investing
Activities (2,036) (1,094) (3,570) (2,342)
-------------------------------------------------------------------------
FINANCING ACTIVITIES
Net issuance (repayment)
of revolving long-term debt 426 (40) 367 (40)
Issuance of long-term
debt (Note 11) - - 723 434
Repayment of long-term debt (196) - (196) -
Issuance of common
shares (Note 13) 13 77 76 153
Purchase of common
shares (Note 13) (15) (713) (326) (1,807)
Dividends on common
shares (300) (151) (600) (304)
Other - (14) - (3)
-------------------------------------------------------------------------
Cash From (Used in)
Financing Activities (72) (841) 44 (1,567)
-------------------------------------------------------------------------
FOREIGN EXCHANGE GAIN (LOSS) ON CASH AND CASH
EQUIVALENTS HELD IN
FOREIGN CURRENCY 1 5 (3) 6
-------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS (111) 218 225 153
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD 889 337 553 402
-------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS,
END OF PERIOD $ 778 $ 555 $ 778 $ 555
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.

Notes to Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise specified)
1. BASIS OF PRESENTATION
The interim Consolidated Financial Statements include the accounts of
EnCana Corporation and its subsidiaries ("EnCana" or the "Company"), and
are presented in accordance with Canadian generally accepted accounting
principles. EnCana's operations are in the business of exploration for,
and development, production and marketing of natural gas, crude oil and
natural gas liquids ("NGLs"), refining operations and power generation
operations.
The interim Consolidated Financial Statements have been prepared
following the same accounting policies and methods of computation as the
annual audited Consolidated Financial Statements for the year ended
December 31, 2007, except as noted below. The disclosures provided below
are incremental to those included with the annual audited Consolidated
Financial Statements. The interim Consolidated Financial Statements
should be read in conjunction with the annual audited Consolidated
Financial Statements and the notes thereto for the year ended
December 31, 2007.
2. CHANGES IN ACCOUNTING POLICIES AND PRACTICES
As disclosed in the December 31, 2007 annual audited Consolidated
Financial Statements, on January 1, 2008, the Company adopted the
following Canadian Institute of Chartered Accountants ("CICA") Handbook
Sections:
- "Inventories", Section 3031. The new standard replaces the previous
inventories standard and requires inventory to be valued on a
first-in, first-out or weighted average basis, which is consistent
with EnCana's former accounting policy. The new standard allows the
reversal of previous write-downs to net realizable value when there is
a subsequent increase in the value of inventories. The adoption of
this standard has had no material impact on EnCana's Consolidated
Financial Statements.
- "Financial Instruments - Presentation", Section 3863 and "Financial
Instruments - Disclosures", Section 3862. The new disclosure standard
increases EnCana's disclosure regarding the nature and extent of the
risks associated with financial instruments and how those risks are
managed (See Note 17). The new presentation standard carries forward
the former presentation requirements.
- "Capital Disclosures", Section 1535. The new standard requires EnCana
to disclose its objectives, policies and processes for managing its
capital structure (See Note 14).
3. RECENT ACCOUNTING PRONOUNCEMENTS
As of January 1, 2009, EnCana will be required to adopt the CICA Handbook
Section 3064, "Goodwill and Intangible Assets", which will replace the
existing Goodwill and Intangible Assets standard. The new standard
revises the requirement for recognition, measurement, presentation and
disclosure of intangible assets. The adoption of this standard should not
have a material impact on EnCana's Consolidated Financial Statements.
In January 2006, the CICA Accounting Standards Board ("AcSB") adopted a
strategic plan for the direction of accounting standards in Canada. As
part of that plan, the AcSB confirmed in February 2008 that International
Financial Reporting Standards ("IFRS") will replace Canadian GAAP in 2011
for profit-oriented Canadian publicly accountable enterprises. As EnCana
will be required to report its results in accordance with IFRS starting
in 2011, the Company is assessing the potential impacts of this
changeover and developing its plan accordingly.
4. PROPOSED CORPORATE REORGANIZATION
On May 11, 2008, EnCana announced its plans to split into two highly
focused energy companies - one a North American natural gas company and
the other a fully integrated oil company with in-situ oilsands properties
and refineries supplemented by reliable production from various gas and
oil resource plays. The proposed corporate reorganization, expected to
close in early January 2009, would be implemented through a court
approved Plan of Arrangement and is subject to shareholder approval. The
reorganization would result in two publicly traded entities with every
EnCana shareholder receiving one share of each entity in exchange for
each EnCana common share held. The working names of the two companies are
GasCo and IntegratedOilCo ("IOCo") respectively. GasCo will retain the
name of EnCana Corporation while the permanent name of IOCo will be
determined prior to the close of the transaction.
5. SEGMENTED INFORMATION
As a result of the proposed corporate reorganization, EnCana has changed
its reportable segments to reflect the realigned reporting hierarchies.
The most significant change results in EnCana now presenting Canadian
Plains and Canadian Foothills as separate operating segments. These were
previously aggregated and presented in the Canada segment. Prior periods
have been restated to reflect the new presentation.
GasCo's operating segments will include EnCana's Canadian Foothills,
United States and Offshore and International segments. IOCo's operating
segments will include EnCana's Canadian Plains and Integrated Oil
segments.
The Company has defined its continuing operations into the following
segments:
- Canadian Plains, Canadian Foothills, United States and Offshore and
International segments include the Company's exploration for, and
development and production of natural gas, crude oil and NGLs and
other related activities. The majority of the Company's operations are
located in Canada and the United States. Offshore and International
exploration is mainly focused on opportunities in Atlantic Canada, the
Middle East and Europe.
- Integrated Oil is focused on two lines of business: the exploration
for, and development and production of bitumen in Canada using in-situ
recovery methods; and the refining of crude oil into petroleum and
chemical products located in the United States. This segment includes
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
Canadian Plains, Canadian Foothills, United States and Integrated Oil
segments. Correspondingly, the Marketing groups also undertake market
optimization activities which comprise third-party purchases and sales
of product that provide operational flexibility for transportation
commitments, product type, delivery points and customer
diversification. These activities are reflected in the Market
Optimization segment.
- Corporate includes unrealized gains or losses recorded on derivative
financial instruments. Once amounts are settled, the realized gains
and losses are recorded in the operating segment to which the
derivative instrument relates.
Market Optimization markets substantially all of the Company's upstream
production to third-party customers. Transactions between business
segments are based on market values and eliminated on consolidation. The
tables in this note present financial information on an after
eliminations basis.
Results of Operations (For the three months ended June 30)
Canadian
Canadian Plains Foothills United States
-------------------------------------------------------------------------
2008 2007 2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of
Royalties $ 1,185 $ 853 $ 1,189 $ 917 $ 1,525 $ 1,128
Expenses
Production and
mineral taxes 24 18 12 13 118 26
Transportation
and selling 25 28 54 51 120 77
Operating 147 108 180 125 186 154
Purchased product - - - - - -
Depreciation,
depletion and
amortization 238 242 285 257 421 281
-------------------------------------------------------------------------
Segment Income
(Loss) $ 751 $ 457 $ 658 $ 471 $ 680 $ 590
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Offshore & Market
Integrated Oil International Optimization
-------------------------------------------------------------------------
2008 2007 2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of
Royalties $ 3,104 $ 1,943 $ (1) $ 1 $ 647 $ 722
Expenses
Production and
mineral taxes - - - - - -
Transportation
and selling 127 76 - - - 2
Operating 196 176 (1) (1) 8 10
Purchased product 2,254 1,134 - - 628 702
Depreciation,
depletion and
amortization 91 94 35 - 4 4
-------------------------------------------------------------------------
Segment Income
(Loss) $ 436 $ 463 $ (35) $ 2 $ 7 $ 4
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Corporate Consolidated
-------------------------------------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of Royalties $ (328) $ 49 $ 7,321 $ 5,613
Expenses
Production and mineral taxes - - 154 57
Transportation and selling - - 326 234
Operating (7) (7) 709 565
Purchased product - - 2,882 1,836
Depreciation, depletion and
amortization 23 21 1,097 899
-------------------------------------------------------------------------
Segment Income (Loss) $ (344) $ 35 2,153 2,022
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Administrative 225 95
Interest, net 147 94
Accretion of asset retirement obligation 20 15
Foreign exchange (gain) loss, net (35) 7
(Gain) loss on divestitures (17) 1
-------------------------------------------------------------------------
340 212
-------------------------------------------------------------------------
Net Earnings Before Income Tax 1,813 1,810
Income tax expense 592 364
-------------------------------------------------------------------------
Net Earnings $ 1,221 $ 1,446
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Results of Operations (For the three months ended June 30)
Geographic and Product Information
Canadian Plains
-------------------------------------------------------------------------
Gas Oil & NGLs
-------------------------------------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of Royalties $ 629 $ 563 $ 554 $ 286
Expenses
Production and mineral taxes 13 10 11 8
Transportation and selling 18 21 7 7
Operating 74 55 72 52
-------------------------------------------------------------------------
Operating Cash Flow $ 524 $ 477 $ 464 $ 219
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Canadian Plains
-------------------------------------------------------------------------
Other Total
-------------------------------------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of Royalties $ 2 $ 4 $ 1,185 $ 853
Expenses
Production and mineral taxes - - 24 18
Transportation and selling - - 25 28
Operating 1 1 147 108
-------------------------------------------------------------------------
Operating Cash Flow $ 1 $ 3 $ 989 $ 699
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Canadian Foothills
-------------------------------------------------------------------------
Gas Oil & NGLs
-------------------------------------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of Royalties $ 1,000 $ 816 $ 174 $ 88
Expenses
Production and mineral taxes 11 12 1 1
Transportation and selling 51 49 3 2
Operating 163 114 12 7
-------------------------------------------------------------------------
Operating Cash Flow $ 775 $ 641 $ 158 $ 78
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Canadian Foothills
-------------------------------------------------------------------------
Other Total
-------------------------------------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of Royalties $ 15 $ 13 $ 1,189 $ 917
Expenses
Production and mineral taxes - - 12 13
Transportation and selling - - 54 51
Operating 5 4 180 125
-------------------------------------------------------------------------
Operating Cash Flow $ 10 $ 9 $ 943 $ 728
-------------------------------------------------------------------------
-------------------------------------------------------------------------

United States
-------------------------------------------------------------------------
Gas Oil & NGLs
-------------------------------------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of Royalties $ 1,308 $ 989 $ 130 $ 70
Expenses
Production and mineral taxes 107 20 11 6
Transportation and selling 120 77 - -
Operating 106 85 - -
-------------------------------------------------------------------------
Operating Cash Flow $ 975 $ 807 $ 119 $ 64
-------------------------------------------------------------------------
-------------------------------------------------------------------------

United States
-------------------------------------------------------------------------
Other Total
-------------------------------------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of Royalties $ 87 $ 69 $ 1,525 $ 1,128
Expenses
Production and mineral taxes - - 118 26
Transportation and selling - - 120 77
Operating 80 69 186 154
-------------------------------------------------------------------------
Operating Cash Flow $ 7 $ - $ 1,101 $ 871
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Integrated Oil
-------------------------------------------------------------------------
Downstream
Oil Refining
-------------------------------------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of Royalties $ 298 $ 172 $ 2,769 $ 1,717
Expenses
Production and mineral taxes - - - -
Transportation and selling 123 72 - -
Operating 50 39 127 119
Purchased product - - 2,300 1,157
-------------------------------------------------------------------------
Operating Cash Flow $ 125 $ 61 $ 342 $ 441
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Integrated Oil
-------------------------------------------------------------------------
Other(x) Total
-------------------------------------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of Royalties $ 37 $ 54 $ 3,104 $ 1,943
Expenses
Production and mineral taxes - - - -
Transportation and selling 4 4 127 76
Operating 19 18 196 176
Purchased product (46) (23) 2,254 1,134
-------------------------------------------------------------------------
Operating Cash Flow $ 60 $ 55 $ 527 $ 557
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x) Includes exploration and production of natural gas and bitumen for
the Athabasca and Senlac properties.

Results of Operations (For the three months ended June 30)
Company Operating Information(x)
GasCo
-------------------------------------------------------------------------
Canadian
Foothills United States
-------------------------------------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of Royalties $ 1,189 $ 917 $ 1,525 $ 1,128
Expenses
Production and mineral taxes 12 13 118 26
Transportation and selling 54 51 120 77
Operating 180 125 186 154
-------------------------------------------------------------------------
Operating Cash Flow $ 943 $ 728 $ 1,101 $ 871
-------------------------------------------------------------------------
-------------------------------------------------------------------------

GasCo
-------------------------------------------------------------------------
Offshore &
International Total
-------------------------------------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of Royalties $ (1) $ 1 $ 2,713 $ 2,046
Expenses
Production and mineral taxes - - 130 39
Transportation and selling - - 174 128
Operating (1) (1) 365 278
-------------------------------------------------------------------------
Operating Cash Flow $ - $ 2 $ 2,044 $ 1,601
-------------------------------------------------------------------------
-------------------------------------------------------------------------

IOCo
-------------------------------------------------------------------------
Canadian Plains Integrated Oil Total
-------------------------------------------------------------------------
2008 2007 2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of
Royalties $ 1,185 $ 853 $ 3,104 $ 1,943 $ 4,289 $ 2,796
Expenses
Production and
mineral taxes 24 18 - - 24 18
Transportation
and selling 25 28 127 76 152 104
Operating 147 108 196 176 343 284
Purchased product - - 2,254 1,134 2,254 1,134
-------------------------------------------------------------------------
Operating Cash Flow $ 989 $ 699 $ 527 $ 557 $ 1,516 $ 1,256
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x) GasCo and IOCo company operating information excluding their
respective share of the Market Optimization and Corporate segments.

Results of Operations (For the six months ended June 30)
Canadian
Canadian Plains Foothills United States
-------------------------------------------------------------------------
2008 2007 2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of
Royalties $ 2,244 $ 1,700 $ 2,264 $ 1,781 $ 2,879 $ 2,091
Expenses
Production and
mineral taxes 37 35 16 24 214 90
Transportation
and selling 52 58 110 98 235 143
Operating 289 209 358 254 355 301
Purchased product - - - - - -
Depreciation,
depletion and
amortization 483 472 560 493 818 546
-------------------------------------------------------------------------
Segment Income
(Loss) $ 1,383 $ 926 $ 1,220 $ 912 $ 1,257 $ 1,011
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Offshore & Market
Integrated Oil International Optimization
-------------------------------------------------------------------------
2008 2007 2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of
Royalties $ 5,427 $ 3,566 $ 1 $ (1) $ 1,272 $ 1,478
Expenses
Production and
mineral taxes 1 - - - - -
Transportation
and selling 249 203 - - - 10
Operating 392 341 1 2 19 17
Purchased product 4,040 2,253 - - 1,235 1,434
Depreciation,
depletion and
amortization 184 184 35 1 8 7
-------------------------------------------------------------------------
Segment Income
(Loss) $ 561 $ 585 $ (35) $ (4) $ 10 $ 10
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Corporate Consolidated
-------------------------------------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of Royalties $(1,424) $ (566) $12,663 $10,049
Expenses
Production and mineral taxes - - 268 149
Transportation and selling - - 646 512
Operating (9) (8) 1,405 1,116
Purchased product - - 5,275 3,687
Depreciation, depletion and
amortization 44 39 2,132 1,742
-------------------------------------------------------------------------
Segment Income (Loss) $(1,459) $ (597) 2,937 2,843
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Administrative 381 190
Interest, net 281 195
Accretion of asset retirement
obligation 41 29
Foreign exchange (gain) loss, net 60 (5)
(Gain) loss on divestitures (17) (58)
-------------------------------------------------------------------------
746 351
-------------------------------------------------------------------------
Net Earnings Before Income Tax 2,191 2,492
Income tax expense 877 549
-------------------------------------------------------------------------
Net Earnings $ 1,314 $ 1,943
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Results of Operations (For the six months ended June 30)
Geographic and Product Information
Canadian Plains
-------------------------------------------------------------------------
Gas Oil & NGLs
-------------------------------------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of Royalties $ 1,219 $ 1,121 $ 1,021 $ 573
Expenses
Production and mineral taxes 18 20 19 15
Transportation and selling 37 43 15 15
Operating 147 107 140 100
-------------------------------------------------------------------------
Operating Cash Flow $ 1,017 $ 951 $ 847 $ 443
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Canadian Plains
-------------------------------------------------------------------------
Other Total
-------------------------------------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of Royalties $ 4 $ 6 $ 2,244 $ 1,700
Expenses
Production and mineral taxes - - 37 35
Transportation and selling - - 52 58
Operating 2 2 289 209
-------------------------------------------------------------------------
Operating Cash Flow $ 2 $ 4 $ 1,866 $ 1,398
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Canadian Foothills
-------------------------------------------------------------------------
Gas Oil & NGLs
-------------------------------------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of Royalties $ 1,909 $ 1,587 $ 322 $ 168
Expenses
Production and mineral taxes 14 23 2 1
Transportation and selling 104 94 6 4
Operating 324 231 23 14
-------------------------------------------------------------------------
Operating Cash Flow $ 1,467 $ 1,239 $ 291 $ 149
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Canadian Foothills
-------------------------------------------------------------------------
Other Total
-------------------------------------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of Royalties $ 33 $ 26 $ 2,264 $ 1,781
Expenses
Production and mineral taxes - - 16 24
Transportation and selling - - 110 98
Operating 11 9 358 254
-------------------------------------------------------------------------
Operating Cash Flow $ 22 $ 17 $ 1,780 $ 1,405
-------------------------------------------------------------------------
-------------------------------------------------------------------------

United States
-------------------------------------------------------------------------
Gas Oil & NGLs
-------------------------------------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of Royalties $ 2,491 $ 1,820 $ 229 $ 124
Expenses
Production and mineral taxes 194 78 20 12
Transportation and selling 235 143 - -
Operating 207 160 - -
-------------------------------------------------------------------------
Operating Cash Flow $ 1,855 $ 1,439 $ 209 $ 112
-------------------------------------------------------------------------
-------------------------------------------------------------------------

United States
-------------------------------------------------------------------------
Other Total
-------------------------------------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of Royalties $ 159 $ 147 $ 2,879 $ 2,091
Expenses
Production and mineral taxes - - 214 90
Transportation and selling - - 235 143
Operating 148 141 355 301
-------------------------------------------------------------------------
Operating Cash Flow $ 11 $ 6 $ 2,075 $ 1,557
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Integrated Oil
-------------------------------------------------------------------------
Downstream
Oil Refining
-------------------------------------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of Royalties $ 536 $ 392 $ 4,815 $ 3,060
Expenses
Production and mineral taxes - - - -
Transportation and selling 243 196 - -
Operating 91 88 259 219
Purchased product - - 4,121 2,291
-------------------------------------------------------------------------
Operating Cash Flow $ 202 $ 108 $ 435 $ 550
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Other(x) Total
-------------------------------------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of Royalties $ 76 $ 114 $ 5,427 $ 3,566
Expenses
Production and mineral taxes 1 - 1 -
Transportation and selling 6 7 249 203
Operating 42 34 392 341
Purchased product (81) (38) 4,040 2,253
-------------------------------------------------------------------------
Operating Cash Flow $ 108 $ 111 $ 745 $ 769
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x) Includes exploration and production of natural gas and bitumen for
the Athabasca and Senlac properties.

Results of Operations (For the three months ended June 30)
Company Operating Information(x)
GasCo
-------------------------------------------------------------------------
Canadian Foothills United States
-------------------------------------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of Royalties $ 2,264 $ 1,781 $ 2,879 $ 2,091
Expenses
Production and mineral taxes 16 24 214 90
Transportation and selling 110 98 235 143
Operating 358 254 355 301
-------------------------------------------------------------------------
Operating Cash Flow $ 1,780 $ 1,405 $ 2,075 $ 1,557
-------------------------------------------------------------------------
-------------------------------------------------------------------------

GasCo
-------------------------------------------------------------------------
Offshore &
International Total
-------------------------------------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of Royalties $ 1 $ (1) $ 5,144 $ 3,871
Expenses
Production and mineral taxes - - 230 114
Transportation and selling - - 345 241
Operating 1 2 714 557
-------------------------------------------------------------------------
Operating Cash Flow $ - $ (3) $ 3,855 $ 2,959
-------------------------------------------------------------------------
-------------------------------------------------------------------------

IOCo
-------------------------------------------------------------------------
Canadian Plains Integrated Oil Total
-------------------------------------------------------------------------
2008 2007 2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of
Royalties $ 2,244 $ 1,700 $ 5,427 $ 3,566 $ 7,671 $ 5,266
Expenses
Production and
mineral taxes 37 35 1 - 38 35
Transportation
and selling 52 58 249 203 301 261
Operating 289 209 392 341 681 550
Purchased product - - 4,040 2,253 4,040 2,253
-------------------------------------------------------------------------
Operating Cash Flow $ 1,866 $ 1,398 $ 745 $ 769 $ 2,611 $ 2,167
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x) GasCo and IOCo company operating information excluding their
respective share of the Market Optimization and Corporate segments.

Capital Expenditures
Three Months Ended Six Months Ended
June 30, June 30,
---------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Capital
Canadian Plains $ 158 $ 156 $ 420 $ 340
Canadian Foothills 570 404 1,337 1,052
United States 660 422 1,179 861
Integrated Oil 266 126 529 270
Offshore & International 28 44 53 62
Market Optimization 5 2 7 3
Corporate 31 18 42 67
-------------------------------------------------------------------------
1,718 1,172 3,567 2,655
-------------------------------------------------------------------------
Acquisition Capital
Canadian Foothills 20 - 92 7
United States 258 3 244 3
Integrated Oil - 14 - 14
-------------------------------------------------------------------------
278 17 336 24
-------------------------------------------------------------------------
Total $ 1,996 $ 1,189 $ 3,903 $ 2,679
-------------------------------------------------------------------------
-------------------------------------------------------------------------
On November 20, 2007, EnCana acquired certain natural gas and land
interests in Texas for approximately $2.55 billion before closing
adjustments. The purchase was facilitated by an unrelated party, Brown
Kilgore Properties LLC ("Brown Kilgore"), which held the majority of the
assets in trust for the Company in anticipation of a qualifying like kind
exchange for U.S. tax purposes. The relationship with Brown Kilgore
represented an interest in a Variable Interest Entity ("VIE") from
November 20, 2007 to May 18, 2008. During this period, EnCana was the
primary beneficiary of the VIE and consolidated Brown Kilgore. On May 18,
2008, when the arrangement with Brown Kilgore was completed, the assets
were transferred to EnCana.
Property, Plant and Equipment and Total Assets by Segment
Property, Plant
and Equipment Total Assets
---------------------------------------
As at As at
---------------------------------------
June 30, December June 30, December
2008 31, 2007 2008 31, 2007
-------------------------------------------------------------------------
Canadian Plains $ 6,675 $ 6,967 $ 8,413 $ 8,626
Canadian Foothills 10,611 10,127 12,757 12,184
United States 12,385 11,879 13,831 12,948
Integrated Oil 5,462 5,164 10,976 10,122
Offshore & International 1,229 1,104 1,331 1,135
Market Optimization 165 171 656 478
Corporate 543 453 2,030 1,481
-------------------------------------------------------------------------
Total $ 37,070 $ 35,865 $ 49,994 $ 46,974
-------------------------------------------------------------------------
-------------------------------------------------------------------------
On February 9, 2007, EnCana announced that it had completed the next
phase in the development of The Bow office project with the sale of
project assets and has entered into a 25 year lease agreement with a
third party developer. As at June 30, 2008, Corporate Property, Plant and
Equipment and Total Assets includes EnCana's accrual to date of
$232 million ($147 million at December 31, 2007) related to this office
project as an asset under construction.
On January 4, 2008, EnCana signed the contract for the design and
construction of the Production Field Centre ("PFC") for the Deep Panuke
project. As at June 30, 2008, Offshore and International Property, Plant,
and Equipment and Total Assets includes EnCana's accrual to date of
$91 million related to this offshore facility as an asset under
construction.
Corresponding liabilities for these projects are included in Other
Liabilities in the Consolidated Balance Sheet. There is no effect on the
Company's net earnings or cash flows related to the capitalization of The
Bow office project or the Deep Panuke PFC.
6. DIVESTITURES
Total year-to-date proceeds received on sale of assets and investments
were $151 million (2007 - $446 million) as described below:
Canadian Plains, Canadian Foothills and United States
In 2008, the Company completed the divestiture of mature conventional oil
and natural gas assets for proceeds of $31 million (2007 - nil) in
Canadian Plains, $70 million (2007 - $12 million) in Canadian Foothills,
and $95 million (2007 - $11 million) in the United States.
Offshore and International
In May 2007, the Company completed the sale of its assets in the
Mackenzie Delta and Beaufort Sea for proceeds of $159 million, which were
credited to property, plant and equipment.
In January 2007, the Company completed the sale of its interests in Chad,
properties that were in the pre-production stage, for proceeds of
$207 million which resulted in a gain on sale of $59 million.
Corporate
In February 2007, the Company sold The Bow office project assets for
proceeds of approximately $57 million, representing its investment at the
date of sale. Refer to Note 5 for further discussion of The Bow office
project assets.
7. INTEREST, NET
Three Months Ended Six Months Ended
June 30, June 30,
---------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Interest Expense - Long-Term Debt $ 144 $ 118 $ 284 $ 218
Interest Expense - Other(x) 56 43 110 106
Interest Income(x) (53) (67) (113) (129)
-------------------------------------------------------------------------
$ 147 $ 94 $ 281 $ 195
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x) Interest Expense - Other and Interest Income are primarily due to the
Partnership Contribution Payable and Receivable, respectively.
8. FOREIGN EXCHANGE (GAIN) LOSS, NET
Three Months Ended Six Months Ended
June 30, June 30,
---------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Unrealized Foreign Exchange
(Gain) Loss on:
Translation of U.S. dollar debt
issued from Canada $ (52) $ (289) $ 165 $ (330)
Translation of U.S. dollar
partnership contribution
receivable issued from Canada 44 305 (99) 343
Other Foreign Exchange (Gain) Loss (27) (9) (6) (18)
-------------------------------------------------------------------------
$ (35) $ 7 $ 60 $ (5)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
9. INCOME TAXES
The provision for income taxes is as follows:
Three Months Ended Six Months Ended
June 30, June 30,
---------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Current
Canada $ 172 $ 61 $ 406 $ 343
United States 256 220 385 312
Other Countries 12 4 13 5
-------------------------------------------------------------------------
Total Current Tax 440 285 804 660
-------------------------------------------------------------------------
Future 152 79 73 (111)
-------------------------------------------------------------------------
$ 592 $ 364 $ 877 $ 549
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The following table reconciles income taxes calculated at the Canadian
statutory rate with the actual income taxes:
Three Months Ended Six Months Ended
June 30, June 30,
---------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Net Earnings Before Income Tax $ 1,813 $ 1,810 $ 2,191 $ 2,492
Canadian Statutory Rate 29.7% 32.3% 29.7% 32.3%
-------------------------------------------------------------------------
Expected Income Tax 538 585 650 805
Effect on Taxes Resulting from:
Statutory and other rate
differences 75 19 78 24
Effect of tax rate changes(x) - (37) - (37)
Effect of legislative changes - (231) - (231)
Non-taxable downstream
partnership income (8) (13) (7) (19)
International financing (79) (14) (159) (29)
Foreign exchange gains not
included in net earnings 24 - 180 -
Non-taxable capital (gains)
losses (4) 8 11 (12)
Other 46 47 124 48
-------------------------------------------------------------------------
$ 592 $ 364 $ 877 $ 549
-------------------------------------------------------------------------
Effective Tax Rate 32.7% 20.1% 40.0% 22.0%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x) The Canadian federal government, during the second quarter of 2007,
enacted income tax rate changes.
10. INVENTORIES
As at As at
June 30, December
2008 31, 2007
-------------------------------------------------------------------------
Product
Canadian Plains $ 1 $ -
United States - 2
Integrated Oil 1,092 646
Market Optimization 327 180
Parts and Supplies 2 -
-------------------------------------------------------------------------
$ 1,422 $ 828
-------------------------------------------------------------------------
-------------------------------------------------------------------------

11. LONG-TERM DEBT As at As at
June 30, December 31,
2008 2007
-------------------------------------------------------------------------
Canadian Dollar Denominated Debt
Revolving credit and term loan borrowings $ 1,673 $ 1,506
Unsecured notes 1,718 1,138
-------------------------------------------------------------------------
3,391 2,644
-------------------------------------------------------------------------
U.S. Dollar Denominated Debt
Revolving credit and term loan borrowings 650 495
Unsecured notes 6,350 6,421
-------------------------------------------------------------------------
7,000 6,916
-------------------------------------------------------------------------
Increase in Value of Debt Acquired(x) 61 66
Debt Discounts and Financing Costs (83) (83)
Current Portion of Long-Term Debt (491) (703)
-------------------------------------------------------------------------
$ 9,878 $ 8,840
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x) Certain of the notes and debentures of EnCana were acquired in
business combinations and were accounted for at their fair value at the
dates of acquisition. The difference between the fair value and the
principal amount of the debt is being amortized over the remaining life
of the outstanding debt acquired, approximately 20 years.
On January 18, 2008, EnCana completed a public offering in Canada of
senior unsecured medium term notes in the aggregate principal amount of
C$750 million. The notes have a coupon rate of 5.80 percent and mature on
January 18, 2018.

12. ASSET RETIREMENT OBLIGATION
The following table presents the reconciliation of the beginning and
ending aggregate carrying amount of the obligation associated with the
retirement of oil and gas assets and refining facilities:
As at As at
June 30, December 31,
2008 2007
-------------------------------------------------------------------------
Asset Retirement Obligation, Beginning of Year $ 1,458 $ 1,051
Liabilities Incurred 26 89
Liabilities Settled (80) (100)
Liabilities Divested (3) -
Change in Estimated Future Cash Flows (5) 184
Accretion Expense 41 64
Other (35) 170
-------------------------------------------------------------------------
Asset Retirement Obligation, End of Period $ 1,402 $ 1,458
-------------------------------------------------------------------------
-------------------------------------------------------------------------

13. SHARE CAPITAL
June 30, 2008 December 31, 2007
-----------------------------------------
(millions) Number Amount Number Amount
-------------------------------------------------------------------------
Common Shares Outstanding,
Beginning of Year 750.2 $ 4,479 777.9 $ 4,587
Common Shares Issued under
Option Plans 2.8 76 8.3 176
Stock-Based Compensation - 11 - 17
Common Shares Purchased (2.8) (13) (36.0) (301)
-------------------------------------------------------------------------
Common Shares Outstanding,
End of Period 750.2 $ 4,553 750.2 $ 4,479
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Normal Course Issuer Bid
To June 30, 2008, the Company purchased 4.8 million Common Shares for
total consideration of approximately $326 million. Of the amount paid,
$29&#xA0;million was charged to Share capital and $297 million was charged to
Retained earnings. Included in the Common Shares Purchased in 2008 are
2.0 million Common Shares distributed (2007 - 2.9 million), valued at
$16 million (2007 - $24 million), from the EnCana Employee Benefit Plan
Trust that vested under EnCana's Performance Share Unit Plan (See Note
15). For these Common Shares distributed, there was a $54 million
adjustment to Retained earnings (2007 - $82 million) with a reduction to
Paid in surplus of $70 million (2007 - $106 million).
EnCana has received regulatory approval each year under Canadian
securities laws to purchase Common Shares under six consecutive Normal
Course Issuer Bids ("Bids"). EnCana is entitled to purchase, for
cancellation, up to approximately 75.1 million Common Shares under the
renewed Bid which commenced on November 13, 2007 and terminates on
November 12, 2008.
Stock Options
EnCana has stock-based compensation plans that allow employees to
purchase Common Shares of the Company. Option exercise prices approximate
the market price for the Common Shares on the date the options were
issued. Options granted under the plans are generally fully exercisable
after three years and expire five years after the date granted. Options
granted under predecessor and/or related company replacement plans expire
up to 10 years from the date the options were granted.
The following tables summarize the information about options to purchase
Common Shares that do not have Tandem Share Appreciation Rights ("TSARs")
attached to them at June 30, 2008. Information related to TSARs is
included in Note 15.
Weighted
Stock Average
Options Exercise
(millions) Price (C$)
-------------------------------------------------------------------------
Outstanding, Beginning of Year 3.4 21.82
Exercised (2.8) 23.66
-------------------------------------------------------------------------
Outstanding, End of Period 0.6 13.25
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Exercisable, End of Period 0.6 13.25
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Outstanding Options Exercisable Options
-------------------------------------------------------------------------
Weighted
Average Weighted Number of Weighted
Number of Remaining Average Options Average
Range of Options Contrac- Exercise Out- Exercise
Exercise Outstanding tual Life Price standing Price
Price (C$) (millions) (years) (C$) (millions) (C$)
-------------------------------------------------------------------------
11.00 to 21.99 0.5 1.4 11.62 0.5 11.62
22.00 to 25.99 0.1 0.3 24.62 0.1 24.62
-------------------------------------------------------------------------
0.6 1.3 13.25 0.6 13.25
-------------------------------------------------------------------------
-------------------------------------------------------------------------
At December 31, 2007, the balance in Paid in surplus related to
stock-based compensation programs.

14. CAPITAL STRUCTURE
The Company's capital structure is comprised of Shareholders' Equity plus
Long-Term Debt. The Company's objectives when managing its capital
structure are to:
i) maintain financial flexibility so as to preserve EnCana's access to
capital markets and its ability to meet its financial obligations;
and
ii) finance internally generated growth as well as potential
acquisitions.
The Company monitors its capital structure and short-term financing
requirements using non-GAAP financial metrics consisting of Net Debt to
Capitalization and Net Debt to Adjusted Earnings Before Interest, Taxes,
Depreciation and Amortization ("EBITDA"). The metrics are used to steward
the Company's overall debt position as measures of the Company's overall
financial strength.
EnCana targets a Net Debt to Capitalization ratio of between 30 and 40
percent that is calculated as follows:
-------------------------
As at
-------------------------
June 30, December 31,
2008 2007
-------------------------------------------------------------------------
Long-Term Debt, excluding current portion $ 9,878 $ 8,840
Less: Working capital (2,086) (1,886)
-------------------------------------------------------------------------
Net Debt 11,964 10,726
Total Shareholders' Equity 20,817 20,704
-------------------------------------------------------------------------
Total Capitalization $ 32,781 $ 31,430
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Debt to Capitalization ratio 36% 34%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
EnCana's Net Debt to Capitalization ratio increased to 36 percent from
34 percent at December 31, 2007 primarily due to unrealized mark-to-
market losses on risk management instruments which increased Net Debt.
Excluding this impact, the Net Debt to Capitalization ratio would have
been 34 percent at June 30, 2008 and would have remained unchanged at
34 percent at December 31, 2007.
EnCana targets a Net Debt to Adjusted EBITDA of 1.0 to 2.0 times. At
June 30, 2008, the Net Debt to Adjusted EBITDA was 1.3x (December 31,
2007 - 1.2x) calculated on a trailing twelve-month basis as follows:
-------------------------
As at
-------------------------
June 30, December 31,
2008 2007
-------------------------------------------------------------------------
Net Debt $ 11,964 $ 10,726
-------------------------------------------------------------------------
Net Earnings from Continuing Operations $ 3,255 $ 3,884
Add (deduct):
Interest, net 514 428
Income tax expense 1,265 937
Depreciation, depletion and amortization 4,206 3,816
Accretion of asset retirement obligation 76 64
Foreign exchange (gain) loss, net (99) (164)
(Gain) loss on divestitures (24) (65)
-------------------------------------------------------------------------
Adjusted EBITDA $ 9,193 $ 8,900
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Debt to Adjusted EBITDA 1.3x 1.2x
-------------------------------------------------------------------------
-------------------------------------------------------------------------
EnCana manages its capital structure and makes adjustments according to
market conditions to maintain flexibility while achieving the objectives
stated above. To manage the capital structure, the Company may adjust
capital spending, adjust dividends paid to shareholders, purchase shares
for cancellation pursuant to normal course issuer bids, issue new shares,
issue new debt or repay existing debt.
The Company's capital management objectives, evaluation measures,
definitions and targets have remained unchanged over the periods
presented. EnCana is subject to certain financial covenants in its credit
facility agreements and is in compliance with all financial covenants.
15. COMPENSATION PLANS
The tables below outline certain information related to EnCana's
compensation plans at June 30, 2008. Additional information is contained
in Note 17 of the Company's annual audited Consolidated Financial
Statements for the year ended December 31, 2007.
A) Pensions
The following table summarizes the net benefit plan expense:
Three Months Ended Six Months Ended
June 30, June 30,
-------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Current Service Cost $ 4 $ 4 $ 8 $ 8
Interest Cost 6 5 11 9
Expected Return on Plan
Assets (5) (5) (10) (9)
Expected Actuarial Loss on
Accrued Benefit Obligation 1 1 2 2
Expected Amortization of
Past Service Costs - 1 1 1
Amortization of Transitional
Obligation - (1) (1) (1)
Expense for Defined
Contribution Plan 10 9 20 16
-------------------------------------------------------------------------
Net Benefit Plan Expense $ 16 $ 14 $ 31 $ 26
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the period ended June 30, 2008, contributions of $7 million have been
made to the defined benefit pension plans (2007 - $4 million).
B) Tandem Share Appreciation Rights ("TSARs")
The following table summarizes the information about TSARs at June 30,
2008:
Weighted
Average
Outstanding Exercise
TSARs Price
-------------------------------------------------------------------------
Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 18,854,141 48.44
Granted 3,998,422 70.26
Exercised - SARs (2,845,548) 43.72
Exercised - Options (46,810) 42.41
Forfeited (288,175) 52.59
-------------------------------------------------------------------------
Outstanding, End of Period 19,672,030 53.51
-------------------------------------------------------------------------
Exercisable, End of Period 8,317,809 45.57
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the period ended June 30, 2008, EnCana recorded compensation costs of
$340 million related to the outstanding TSARs (2007 - $157 million).
C) Performance Tandem Share Appreciation Rights ("Performance TSARs")
The following table summarizes the information about Performance TSARs at
June 30, 2008:
Weighted
Average
Outstanding Exercise
TSARs Price
-------------------------------------------------------------------------
Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 6,930,925 56.09
Granted 7,058,538 69.40
Exercised - SARs (259,466) 56.09
Exercised - Options (3,669) 56.09
Forfeited (454,914) 57.94
-------------------------------------------------------------------------
Outstanding, End of Period 13,271,414 63.11
-------------------------------------------------------------------------
Exercisable, End of Period 1,497,135 56.09
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the period ended June 30, 2008, EnCana recorded compensation costs of
$126 million related to the outstanding Performance TSARs (2007 -
$9 million).
D) Share Appreciation Rights ("SARs")
In 2008, EnCana granted SARs to certain employees which entitles the
employee to receive a cash payment equal to the excess of the market
price of EnCana's Common Shares at the time of exercise over the grant
price. SARs are exercisable at 30 percent of the number granted after one
year, an additional 30 percent of the number granted after two years and
are fully exercisable after three years and expire five years after the
grant date.
The following table summarizes the information about SARs at June 30,
2008:
Weighted
Average
Outstanding Exercise
SARs Price
-------------------------------------------------------------------------
Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year - -
Granted 951,065 71.71
Forfeited (17,250) 69.40
-------------------------------------------------------------------------
Outstanding, End of Period 933,815 71.75
-------------------------------------------------------------------------
Exercisable, End of Period - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the period ended June 30, 2008, EnCana recorded compensation costs of
$5 million related to the outstanding SARs (2007 - nil).
E) Performance Share Appreciation Rights ("Performance SARs")
In 2008, EnCana granted Performance SARs to certain employees which
entitles the employee to receive a cash payment equal to the excess of
the market price of EnCana's Common Shares at the time of exercise over
the grant price. Performance SARs vest and expire under the same terms
and service conditions as SARs and are also subject to EnCana attaining
prescribed performance relative to pre-determined key measures.
Performance SARs that do not vest when eligible are forfeited.
The following table summarizes the information about Performance SARs at
June 30, 2008:
Weighted
Average
Outstanding Exercise
SARs Price
-------------------------------------------------------------------------
Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year - -
Granted 1,677,030 69.40
Forfeited (34,500) 69.40
-------------------------------------------------------------------------
Outstanding, End of Period 1,642,530 69.40
-------------------------------------------------------------------------
Exercisable, End of Period - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the period ended June 30, 2008, EnCana recorded compensation costs of
$4 million related to the outstanding Performance SARs (2007 - nil).
F) Deferred Share Units ("DSUs")
The following table summarizes the information about DSUs at June 30,
2008:
Average
Outstanding Share
DSUs Price
-------------------------------------------------------------------------
Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 589,174 33.78
Granted, Directors 82,218 67.92
Exercised (34,008) 91.00
Units, in Lieu of Dividends 6,208 85.17
-------------------------------------------------------------------------
Outstanding, End of Period 643,592 35.61
-------------------------------------------------------------------------
Exercisable, End of Period 643,592 35.61
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the period ended June 30, 2008, EnCana recorded compensation costs of
$23 million related to the outstanding DSUs (2007 - $11 million).
G) Performance Share Units ("PSUs")
The following table summarizes the information about PSUs at June 30,
2008:
Average
Outstanding Share
PSUs Price
-------------------------------------------------------------------------
Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 1,685,036 38.79
Granted 408,686 70.77
Distributed (2,042,541) 45.34
Forfeited (51,181) 38.32
-------------------------------------------------------------------------
Outstanding, End of Period - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the period ended June 30, 2008, EnCana recorded compensation costs of
$1 million related to the outstanding PSUs (2007 - $15 million).
16. PER SHARE AMOUNTS
The following table summarizes the Common Shares used in calculating Net
Earnings per Common Share:

Three Months Ended Six Months Ended
March 31, June 30, June 30,
-----------------------------------------------------
(millions) 2008 2008 2007 2008 2007
-------------------------------------------------------------------------
Weighted Average
Common Shares
Outstanding - Basic 749.5 750.2 758.5 749.8 763.5
Effect of Dilutive
Securities 3.5 1.1 6.7 2.5 9.7
-------------------------------------------------------------------------
Weighted Average
Common Shares
Outstanding -
Diluted 753.0 751.3 765.2 752.3 773.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
17. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
EnCana's financial assets and liabilities are comprised of cash and cash
equivalents, accounts receivable and accrued revenues, accounts payable
and accrued liabilities, the partnership contribution receivable and
payable, risk management assets and liabilities, and long-term debt. Risk
management assets and liabilities arise from the use of derivative
financial instruments. Fair values of financial assets and liabilities,
summarized information related to risk management positions, and
discussion of risks associated with financial assets and liabilities are
presented as follows.
A) Fair Value of Financial Assets and Liabilities
The fair values of cash and cash equivalents, accounts receivable and
accrued revenues, and accounts payable and accrued liabilities
approximate their carrying amount due to the short-term maturity of those
instruments.
Risk management assets and liabilities are recorded at their estimated
fair value based on the mark-to-market method of accounting, using quoted
market prices or, in their absence, third-party market indications and
forecasts. Long-term debt is carried at amortized cost using the
effective interest method of amortization. The estimated fair values of
long-term borrowings have been determined based on market information
where available, or by discounting future payments of interest and
principal at estimated interest rates expected to be available to the
Company at period end.
The fair values of the partnership contribution receivable and
partnership contribution payable approximate their carrying amount due to
the specific nature of these instruments in relation to the creation of
the integrated oil joint venture. Further information about these notes
is disclosed in Note 10 to the Company's annual audited Consolidated
Financial Statements.
The fair value of financial assets and liabilities were as follows:

As at As at
June 30, 2008 December 31, 2007
---------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------------------------------------------------------------------------
Financial Assets
Held-for-Trading:
Cash and cash equivalents $ 778 $ 778 $ 553 $ 553
Risk management assets(x) 606 606 403 403
Loans and Receivables:
Accounts receivable and
accrued revenues 3,346 3,346 2,381 2,381
Partnership contribution
receivable(x) 3,297 3,297 3,444 3,444
Financial Liabilities
Held-for-Trading:
Risk management liabilities(x) $ 1,690 $ 1,690 $ 236 $ 236
Other Financial Liabilities:
Accounts payable and accrued
liabilities 4,888 4,888 3,982 3,982
Long-term debt(x) 10,369 10,461 9,543 9,763
Partnership contribution
payable(x) 3,309 3,309 3,451 3,451
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x) Including current portion.

B) Risk Management Assets and Liabilities
Net Risk Management Position As at As at
June 30, December 31,
2008 2007
-------------------------------------------------------------------------
Risk Management
Current asset $ 265 $ 385
Long-term asset 341 18
-------------------------------------------------------------------------
606 403
-------------------------------------------------------------------------
Risk Management
Current liability 1,617 207
Long-term liability 73 29
-------------------------------------------------------------------------
1,690 236
-------------------------------------------------------------------------
Net Risk Management Asset (Liability) $ (1,084) $ 167
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Summary of Unrealized Risk Management Positions

As at June 30, 2008 As at December 31, 2007
------------------------------------------------------
Risk Management Risk Management
------------------------------------------------------
Asset Liability Net Asset Liability Net
-------------------------------------------------------------------------
Commodity Prices
Natural gas $ 566 $ 1,381 $ (815) $ 375 $ 29 $ 346
Crude oil 5 309 (304) 6 205 (199)
Power 35 - 35 19 - 19
Interest Rates - - - 2 - 2
Credit - - - 1 2 (1)
-------------------------------------------------------------------------
Total Fair Value $ 606 $ 1,690 $(1,084) $ 403 $ 236 $ 167
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Fair Value Methodologies Used to Calculate Unrealized Risk Management
Positions
As at As at
June 30, December 31,
2008 2007
-------------------------------------------------------------------------
Prices actively quoted $ (1,476) $ 148
Prices sourced from observable data or
market corroboration 392 19
-------------------------------------------------------------------------
Total Fair Value $ (1,084) $ 167
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Prices actively quoted refers to the fair value of contracts valued using
quoted prices in an active market. Prices sourced from observable data or
market corroboration refers to the fair value of contracts valued in part
using active quotes and in part using observable, market-corroborated
data.

Net Fair Value of Commodity Price Positions at June 30, 2008
Notional Fair Market
Volumes Term Average Price Value
-------------------------------------------------------------------------
Natural Gas
Sales Contracts
Fixed Price Contracts
NYMEX Fixed Price 1,494 MMcf/d 2008 8.20 US$/Mcf $ (1,419)
NYMEX Fixed Price 391 MMcf/d 2009 9.85 US$/Mcf (364)
Options
Purchased AECO
Call Options (6) MMcf/d 2008 10.85 C$/Mcf 1
Purchased NYMEX
Call Options (851) MMcf/d 2008 11.55 US$/Mcf 223
Purchased NYMEX
Put Options 136 MMcf/d 2008 8.85 US$/Mcf (9)
Purchased NYMEX
Put Options 341 MMcf/d 2009 8.85 US$/Mcf (18)
Basis Contracts
Canada 175 MMcf/d 2008 (0.76) US$/Mcf 27
United States 1,058 MMcf/d 2008 (1.66) US$/Mcf 240
Canada and
United States(x) 2009-2011 377
-------------------------------------------------------------------------
(942)
Other Financial
Positions(xx) (33)
-------------------------------------------------------------------------
Total Unrealized Loss
on Financial Contracts (975)
Paid Premiums on
Unexpired Options 160
-------------------------------------------------------------------------
Natural Gas Fair Value Position $ (815)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x) EnCana has entered into swaps to protect against widening natural gas
price differentials between production areas, including Canada, the U.S.
Rockies and Texas, and various sales points. These basis swaps are priced
using both fixed prices and basis prices determined as a percentage of
NYMEX.
(xx) Other financial positions are part of the ongoing operations of the
Company's proprietary production and transportation commitment
management.

Notional Fair Market
Volumes Term Average Price Value
-------------------------------------------------------------------------
Crude Oil Sales
Contracts
Fixed Price Contracts
WTI NYMEX Fixed
Price 23,000 bbls/d 2008 70.13 US$/bbl $ (297)
Other Financial
Positions(xx) (7)
-------------------------------------------------------------------------
Crude Oil Fair
Value Position $ (304)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Power Purchase Contracts
Power Fair Value Position $ 35
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(xx) Other financial positions are part of the ongoing operations of the
Company's proprietary production management.

Net Earnings Impact of Realized and Unrealized Gains (Losses) on Risk
Management Positions
Realized Gain (Loss)
---------------------------------------
Three Months Ended Six Months Ended
June 30, June 30,
---------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of Royalties $ (586) $ 382 $ (566) $ 697
Operating Expenses and Other (2) - - 1
-------------------------------------------------------------------------
Gain (Loss) on Risk Management $ (588) $ 382 $ (566) $ 698
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Unrealized Gain (Loss)
---------------------------------------
Three Months Ended Six Months Ended
June 30, June 30,
---------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues, Net of Royalties $ (328) $ 49 $(1,424) $ (566)
Operating Expenses and Other 10 6 13 7
-------------------------------------------------------------------------
Gain (Loss) on Risk Management $ (318) $ 55 $(1,411) $ (559)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Reconciliation of Unrealized Risk Management Positions from January 1 to
June 30, 2008
2008 2007
--------------------------------------
Total Total
Fair Market Unrealized Unrealized
Value Gain (Loss) Gain (Loss)
-------------------------------------------------------------------------
Fair Value of Contracts,
Beginning of Year $ 167
Change in Fair Value of Contracts
in Place at Beginning of Year
and Contracts Entered into
During the Period (1,977) $ (1,977) $ 132
Fair Value of Contracts in Place
at Transition that Expired During
the Period - - 7
Fair Value of Contracts Realized
During the Period 566 566 (698)
-------------------------------------------------------------------------
Fair Value of Contracts Outstanding $ (1,244) $ (1,411) $ (559)
Paid Premiums on Unexpired Options 160
-------------------------------------------------------------------------
Fair Value of Contracts and
Premiums Paid, End of Period $ (1,084)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Commodity Price Sensitivities
The following table summarizes the sensitivity of the fair value of the
Company's risk management positions to fluctuations in commodity prices,
with all other variables held constant. When assessing the potential
impact of these commodity price changes, the Company believes 10%
volatility is a reasonable measure. Fluctuations in commodity prices
could have resulted in unrealized gains (losses) impacting net earnings
as at June 30, 2008 as follows:
Favorable Unfavorable
10% Change 10% Change
-------------------------------------------------------------------------
Natural gas price $ 347 $ (303)
Crude oil price 60 (60)
Power price 4 (4)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
C) Risks Associated with Financial Assets and Liabilities
The Company is exposed to financial risks arising from its financial
assets and liabilities. The financial risks include market risk relating
to commodity prices, interest rates and foreign exchange rates, credit
risk and liquidity risk.
Market Risk
Market risk, the risk that the fair value or future cash flows of
financial assets or liabilities will fluctuate due to movements in market
prices, is comprised of the following:
- Commodity Price Risk
As a means of mitigating exposure to commodity price risk volatility,
the Company has entered into various derivative agreements. The use
of derivative instruments is governed under formal policies and is
subject to limits established by the Board of Directors. The
Company's policy is to not use derivative financial instruments for
speculative purposes.
Natural Gas - To partially mitigate the natural gas commodity price
risk, the Company enters into option contracts and swaps, which fix
the NYMEX prices. To help protect against widening natural gas price
differentials in various production areas, EnCana has entered into
swaps to manage the price differentials between these production
areas and various sales points.
Crude Oil - The Company has partially mitigated its exposure to the
WTI NYMEX price with fixed price swaps.
Power - The Company has in place two Canadian dollar denominated
derivative contracts, which commenced January 1, 2007 for a period of
11 years, to manage its electricity consumption costs.
- Interest Rate Risk
The Company partially mitigates its exposure to interest rate changes
by maintaining a mix of both fixed and floating rate debt.
At June 30, 2008, the increase or decrease in net earnings for each
one percent change in interest rates on floating rate debt amounts to
$16 million.
Foreign Exchange Risk
As EnCana operates primarily in North America, fluctuations in the
exchange rate between the U.S./Canadian dollar can have a significant
effect on the Company's reported results. EnCana's functional
currency is Canadian dollars, however, the Company reports its
results in U.S. dollars as most of its revenue is closely tied to the
U.S. dollar and to facilitate a more direct comparison to other North
American oil and gas companies. As the effects of foreign exchange
fluctuations are embedded in the Company's results, the total effect
of foreign exchange fluctuations are not separately identifiable.
To mitigate the exposure to the fluctuating U.S./Canadian exchange
rate, EnCana maintains a mix of both U.S. dollar and Canadian dollar
debt.
As disclosed in Note 8, EnCana's foreign exchange (gain) loss is
primarily comprised of unrealized foreign exchange gains and losses
on the translation of U.S. dollar debt issued from Canada and the
translation of U.S. dollar partnership contribution receivable issued
from Canada. At June 30, 2008, EnCana had $5,350 million in U.S.
dollar debt issued from Canada ($5,421 million at December 31, 2007)
and $3,297 million related to the U.S. dollar partnership
contribution receivable ($3,444 million at December 31, 2007). A
$0.01 change in the U.S. to Canadian dollar exchange rate would have
resulted in a $21 million change in foreign exchange (gain) loss at
June 30, 2008.
Credit Risk
Credit risk is the risk that the counterparty to a financial asset
will default resulting in the Company incurring a financial loss.
This credit exposure is mitigated through the use of Board-approved
credit policies governing the Company's credit portfolio and with
credit practices that limit transactions according to counterparties'
credit quality. All foreign currency agreements are with major
financial institutions in Canada and the United States or with
counterparties having investment grade credit ratings. A substantial
portion of the Company's accounts receivable are with customers in
the oil and gas industry and are subject to normal industry credit
risks.
At June 30, 2008, EnCana had three counterparties whose net
settlement position individually account for more than 10 percent of
the fair value of the outstanding in-the-money net financial
instrument contracts by counterparty. The maximum credit risk
exposure associated with accounts receivable and accrued revenues,
risk management assets and the partnership contribution receivable is
the total carrying value.
Liquidity Risk
Liquidity risk is the risk the Company will encounter difficulties in
meeting its financial liability obligations. The Company manages its
liquidity risk through cash and debt management. As disclosed in
Note 14, EnCana targets a Net Debt to Capitalization ratio between 30
and 40 percent and a Net Debt to Adjusted EBITDA of 1.0 to 2.0 times
to steward the Company's overall debt position.
In managing liquidity risk, the Company has access to a wide range of
funding at competitive rates through commercial paper, capital
markets and banks. As at June 30, 2008, EnCana had available unused
committed bank credit facilities in the amount of $2.7 billion and
unused capacity under shelf prospectuses, the availability of which
is dependent on market conditions, for up to $7.2 billion. Of this
unused shelf capacity, $2 billion expired on July 9, 2008. The
Company believes it has sufficient funding through the use of these
facilities to meet foreseeable borrowing requirements.
EnCana maintains investment grade credit ratings on its senior
unsecured debt. On May 12, 2008, following the proposed corporate
reorganization (See Note 4), Standard & Poor's Ratings Service
assigned a rating of A- and placed the Company on "CreditWatch with
Negative Implications", DBRS Limited assigned a rating of A(low) and
placed the Company "Under Review with Developing Implications", and
Moody's Investors Service has assigned a rating of Baa2 and changed
the outlook to "Stable" from "Positive".
The timing of cash outflows relating to financial liabilities are
outlined in the table below:
2 - 4 - beyond
1 year 3 years 5 years 5 years Total
-------------------------------------------------------------------------
Accounts payable and accrued
liabilities $ 4,888 $ - $ - $ - $ 4,888
Risk management liabilities 1,617 73 - - 1,690
Long-term debt(x) 491 450 3,314 6,136 10,391
Partnership contribution
payable(x) 297 649 732 1,631 3,309
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x) Principal, including current portion.

Included in EnCana's total long-term debt obligations of
$10,391 million at June 30, 2008 are $2,323 million in obligations
related to Bankers' Acceptances, Commercial Paper and LIBOR loans.
These amounts are fully supported and Management expects that they
will continue to be supported by revolving credit and term loan
facilities that have no repayment requirements within the next year.
18. CONTINGENCIES
Legal Proceedings
The Company is involved in various legal claims associated with the
normal course of operations. The Company believes it has made adequate
provision for such legal claims.
Discontinued Merchant Energy Operations
During the period between 2003 and 2005, EnCana and its indirect wholly
owned U.S. marketing subsidiary, WD Energy Services Inc. ("WD"), along
with other energy companies, were named as defendants in several
lawsuits, some of which were class action lawsuits, relating to sales of
natural gas from 1999 to 2002. The lawsuits allege that the defendants
engaged in a conspiracy with unnamed competitors in the natural gas
markets in California in violation of U.S. and California anti-trust and
unfair competition laws.
Without admitting any liability in the lawsuits, WD agreed to settle all
of the class action lawsuits in both state and federal court for payment
of $20.5 million and $2.4 million, respectively. Also, as previously
disclosed, without admitting any liability whatsoever, WD concluded
settlements with the U.S. Commodity Futures Trading Commission ("CFTC")
for $20 million and of a previously disclosed consolidated class action
lawsuit in the United States District Court in New York for $8.2 million.
Also, without admitting any liability whatsoever, WD concluded settlement
negotiations with a group of individual plaintiffs. It was agreed that WD
would settle these claims for $23 million. Execution of the Settlement
Agreement is pending.
The remaining lawsuit was commenced by E. & J. Gallo Winery ("Gallo").
The Gallo lawsuit claims damages in excess of $30 million. California law
allows for the possibility that the amount of damages assessed could be
tripled.
The Company and WD intend to vigorously defend against this outstanding
claim; however, the Company cannot predict the outcome of these
proceedings or any future proceedings against the Company, whether these
proceedings would lead to monetary damages which could have a material
adverse effect on the Company's financial position, or whether there will
be other proceedings arising out of these allegations.
19. RECLASSIFICATION
Certain information provided for prior periods has been reclassified to
conform to the presentation adopted in 2008.
>>

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

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

investor.relations@encana.com

ECA stock price

TSX $14.99 Can 0.060

NYSE $11.75 USD 0.110

As of 2017-11-22 16:02. Minimum 15 minute delay