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

CALGARY, Jul 24, 2008 (Canada NewsWire via COMTEX) ----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* 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 ------------------------------------------------------------------------- -------------------------------------------------------------------------
   * 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* 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 -------------------------------------------------------------------------
   ------------------------------------------------------------------------- * 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* 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 ------------------------------------------------------------------------- -------------------------------------------------------------------------
   * 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* 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 -------------------------------------------------------------------------
   ------------------------------------------------------------------------- * 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* 56 43 110 106 Interest Income* (53) (67)
   (113) (129) ------------------------------------------------------------------------- $ 147 $ 94 $ 281 $ 195 -------------------------------------------------------------------------
   ------------------------------------------------------------------------- * 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* - (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% ------------------------------------------------------------------------- -------------------------------------------------------------------------
   * 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*
   61 66 Debt Discounts and Financing Costs (83) (83) Current Portion of Long-Term Debt (491) (703) -------------------------------------------------------------------------
   $ 9,878 $ 8,840 ------------------------------------------------------------------------- -------------------------------------------------------------------------
   * 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 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
   i