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EnCana Generates Third Quarter Cash Flow of US$2.2 Billion, or $2.93 Per Share - Up 27 Percent

Posted on: Thursday, 25 October 2007, 06:00 CDT

CALGARY, Oct. 25 /PRNewswire-FirstCall/ -- EnCana Corporation (TSX & NYSE: ECA) continued to generate solid cash flow during the third quarter of 2007 due to strong natural gas production growth and favourable gas price hedges that offset weaker gas prices, plus solid performance from the downstream segment of the company's integrated oilsands business.

"This strong performance is the result of the actions we have taken over the last several years to establish EnCana as a leading producer of unconventional natural gas and integrated in-situ oilsands, a company with a unique, low-risk, sustainable growth profile. Our financial and operating performance is on track for 2007, which is evidence that our resource play model is working extremely well. Natural gas production is up 16 percent per share, led by production from our key gas resource plays: Cutbank Ridge in northeast British Columbia, East Texas, Bighorn in west-central Alberta and Jonah in Wyoming. As well, we continue to expand our integrated oilsands business and capture value from strong refining margins in our downstream operations," said Randy Eresman, EnCana's President & Chief Executive Officer.

IMPORTANT NOTE: EnCana reports in U.S. dollars unless otherwise noted and follows U.S. protocols, which report production, sales and reserves on an after-royalties basis. The company's financial statements are prepared in accordance with Canadian generally accepted accounting principles (GAAP). Third Quarter 2007 Highlights ----------------------------- (all comparisons are to the third quarter of 2006) Financial - US$ - Cash flow per share diluted increased 27 percent to $2.93, or $2.2 billion - Operating earnings per share diluted down 3 percent to $1.27, or $961 million, which is lower compared to the same quarter of 2006 in part due to a $255 million after-tax gain on the sale of a Brazil asset in the third quarter of 2006 - Net earnings per share diluted down 25 percent to $1.24, or $934 million - Realized gains of $323 million, after tax, from commodity price risk management measures - Integrated oilsands downstream business generated $344 million of pre-tax cash flow from U.S. refineries - Capital investment up 7 percent to $1.58 billion - Generated $643 million of free cash flow (as defined in Note 1 on page 7) - Purchased approximately 3.5 million EnCana shares at an average price of $61.60 under the Normal Course Issuer Bid, completing the company's planned purchase of 5 percent of shares in 2007 Operating - Upstream - Natural gas production increased 8 percent to 3.63 billion cubic feet per day (Bcf/d), up 16 percent per share - Oil and natural gas liquids (NGLs) production up 1 percent on a pro forma basis to about 136,000 barrels per day (bbls/d), up 9 percent per share (see note 1, Production & Drilling Summary, page 3) - Total natural gas and liquids production increased 7 percent on a pro forma basis to 4.45 billion cubic feet of gas equivalent per day (Bcfe/d), up 15 percent per share - Key natural gas resource play production up 15 percent - Oilsands production grew 33 percent to about 57,000 bbls/d (about 29,000 bbls/d net to EnCana) at Foster Creek and Christina Lake - Operating and administrative costs of $1.01 per thousand cubic feet equivalent (Mcfe) Operating - Downstream - Refined products production averaged 484,000 bbls/d (242,000 bbls/d net to EnCana) - Began processing Canadian bitumen blend through the Borger refinery in July, a major milestone for the refinery - Refinery crude utilization of 102 percent was higher than the second quarter of 2007 due to the resumption of normal operations at the Borger refinery after the installation and start-up of the new coker in late June. Year-to-date utilization of 95 percent, or 430,000 bbls/d crude throughput (215,000 bbls/d net to EnCana), continues to exceed expectations due to record throughput at the Wood River refinery. Natural gas production on track with 2007 forecast

Natural gas production in the third quarter rose steadily with strong year-over-year increases in a number of key resource plays - 47 percent in Cutbank Ridge, 36 percent in East Texas, 32 percent in Bighorn, 29 percent in Jonah and 22 percent in coalbed methane (CBM). Gas production to date in 2007 has averaged about 3.5 Bcf/d, in line with full-year guidance of 3.46 Bcf/d. Current production is about 3.6 Bcf/d. The company is on track to modestly exceed its full-year natural gas production guidance. EnCana expects it will likely achieve closer to 4 percent growth in gas production as opposed to its original 3 percent growth forecast.

Integrated oilsands business solid performance continues

The financial performance of EnCana's emerging integrated oilsands business continues to be strong. Regional and local market factors have an impact on refining crack spreads. EnCana's two refineries are located in markets influenced by U.S. Mid-continent and Chicago 3-2-1 crack spreads which have been strong relative to U.S. Gulf Coast and NYMEX crack spreads. Third quarter pre-tax cash flow from the integrated oilsands business was $411 million, composed of $344 million from downstream and $67 million from upstream. During the first nine months of 2007, the integrated oilsands business delivered more than $1 billion of pre-tax cash flow, about 14 percent of EnCana's total pre-tax cash flow.

"The financial and operating performance of our integrated oilsands business continues to validate our market integration initiatives," Eresman said. "The downstream performance also reflects the strength of ConocoPhillips' management and operating teams and their commitment and contribution to the success of this business venture."

Deep Panuke gas project off Nova Scotia moves ahead

EnCana's Board of Directors has sanctioned the development of the company's Deep Panuke natural gas project located about 175 kilometres offshore Nova Scotia. The $700 million project (about $550 million net to EnCana) is expected to start production in 2010 and is expected to deliver between 200 million and 300 million cubic feet of natural gas per day to markets in Canada and the northeast United States.

"Over the past five years, EnCana employees, the Government of Nova Scotia, federal and provincial regulators and the Atlantic energy community have worked diligently to achieve this important milestone. We are excited to move ahead with the development of the Deep Panuke discovery," Eresman said.

------------------------------------------------------------------------- Financial Summary - Total Consolidated ------------------------------------------------------------------------- (for the period ended Sept 30) 9 9 ($ millions, except per Q3 Q3 % months months % share amounts) 2007 2006 change 2007 2006 change ------------------------------------------------------------------------- Cash flow(1) 2,218 1,894 + 17 6,519 5,400 + 21 Per share diluted 2.93 2.30 + 27 8.49 6.39 + 33 ------------------------------------------------------------------------- Operating earnings(1) 961 1,078 - 11 3,195 2,596 + 23 Per share diluted 1.27 1.31 - 3 4.16 3.07 + 36 ------------------------------------------------------------------------- Net earnings 934 1,358 - 31 2,877 4,989 - 42 Per share diluted 1.24 1.65 - 25 3.75 5.90 - 36 ------------------------------------------------------------------------- Capital investment 1,575 1,474 + 7 4,230 5,052 - 16 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Earnings Reconciliation Summary - Total Consolidated ------------------------------------------------------------------------- Net earnings from continuing operations 934 1,343 - 30 2,877 4,408 - 35 Net earnings from discontinued operations - 15 n/a - 581 n/a ------------------------------------------------------------------------- ------------------------------------------------------------------------- Net earnings (loss) (Add back losses & deduct gains) 934 1,358 - 31 2,877 4,989 - 42 Unrealized mark-to-market hedging gain (loss), after-tax (69) 285 n/a (445) 1,275 n/a Unrealized foreign exchange gain (loss) on translation of U.S. dollar Notes issued from Canada, after-tax 17 (3) n/a 6 128 n/a Future tax recovery due to Canada and Alberta tax rate reductions - - n/a 37 457 n/a Gain (loss) on discontinuance, after-tax 25 (2) n/a 84 533 n/a ------------------------------------------------------------------------- Operating earnings(1) 961 1,078 - 11 3,195 2,596 + 23 Per share diluted 1.27 1.31 - 3 4.16 3.07 + 36 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Cash flow and operating earnings are non-GAAP measures as defined in Note 1 on page 7. ------------------------------------------------------------------------- Production & Drilling Summary ------------------------------------------------------------------------- Total Consolidated ------------------------------------------------------------------------- (for the period ended Sept 30) 9 9 (After royalties) Q3 Q3 % months months % 2007 2006(1) change 2007 2006(1) change ------------------------------------------------------------------------- Natural gas (MMcf/d) 3,630 3,359 + 8 3,513 3,354 + 5 ------------------------------------------------------------------------- Natural gas production per 1,000 shares (Mcf) 445 382 + 16 1,263 1,100 + 15 ------------------------------------------------------------------------- Oil and NGLs (Mbbls/d) 136 135 + 1 133 153 - 13 ------------------------------------------------------------------------- Oil and NGLs production per 1,000 shares (Mcfe) 100 92 + 9 288 302 - 5 ------------------------------------------------------------------------- Total Production (MMcfe/d) 4,448 4,170 + 7 4,314 4,275 + 1 ------------------------------------------------------------------------- Total per 1,000 shares (Mcfe) 545 474 + 15 1,551 1,402 + 11 ------------------------------------------------------------------------- Net wells drilled 1,339 1,001 + 34 3,171 2,841 + 12 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) 2006 information has been adjusted on a pro forma basis to reflect the integrated oilsands transaction; the nine months of 2006 includes production from EnCana's Ecuador assets, which were sold in the first quarter 2006. ------------------------------------------------------------------------- Key natural gas resource play production up 15 percent from past year

Third quarter 2007 natural gas production from key resource plays increased 15 percent to 2.78 Bcf/d compared to 2.41 Bcf/d in the third quarter of 2006. This increased production was driven mainly by double-digit production increases in six of the company's nine gas resource plays, led by Cutbank Ridge in northeast British Columbia, East Texas, Bighorn in west-central Alberta, Jonah in Wyoming, the Barnett Shale play in the Fort Worth basin, and CBM in central and southern Alberta. The growth in Cutbank Ridge is the result of continued production growth from the Cadomin zone, along with an increasing contribution from the Montney and Doig formations. The increase in Jonah, EnCana's second largest resource play, can be attributed to improved response from frac stimulations and increased availability of capacity on regional pipelines due to system expansion and added compression on the gas gathering system.

Oilsands production from Foster Creek and Christina Lake was up 33 percent to about 57,000 bbls/d (about 29,000 bbls/d net to EnCana). Overall, third quarter gas and oil resource play production increased 15 percent in the past year, on a pro forma basis.

Growth from key North American resource plays ------------------------------------------------------------------------- Daily Production ------------------------------------------------------------ Resource Play 2007 2006 2005 ------------------------------------------------------------ (After Full Full royalties) YTD Q3 Q2 Q1 Year Q4 Q3 Q2 Q1 Year ------------------------------------------------------------------------- Natural gas (MMcf/d) Jonah 539 588 523 504 464 487 455 450 461 435 Piceance 346 354 349 334 326 335 331 324 316 307 East Texas 129 144 139 103 99 95 106 93 99 90 Fort Worth 119 128 124 106 101 99 104 108 93 70 Greater Sierra 208 220 219 186 213 212 209 224 208 219 Cutbank Ridge 227 245 226 210 170 199 167 173 140 92 Bighorn 116 128 115 104 91 99 97 95 72 55 CBM (1) 251 256 245 251 194 211 209 179 177 112 Shallow Gas(2) 725 713 729 735 739 737 734 730 756 765 ------------------------------------------------------------------------- Total natural gas (MMcf/d) 2,660 2,776 2,669 2,533 2,397 2,474 2,412 2,376 2,322 2,145 ------------------------------------------------------------------------- Oil (Mbbls/d) Foster Creek(3) 24 26 25 20 18 21 19 16 18 14 Christina Lake(3) 3 3 3 3 3 3 3 3 3 3 Pelican Lake(4) 23 24 23 23 24 20 23 22 29 26 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Total oil (Mbbls/d) 50 53 51 46 45 44 45 41 50 43 ------------------------------------------------------------------------- Total (MMcfe/d) 2,959 3,090 2,972 2,811 2,667 2,736 2,680 2,624 2,624 2,403 ------------------------------------------------------------------------- % change from Q3 2006 15 ------------------------------------------------------------------------- % change from prior period 4.0 5.7 2.7 11 2.1 2.1 - -2.9 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) CBM volumes were restated in 2006 to account for commingled volumes from the coal and sand intervals based upon regulatory approval. (2) Shallow Gas volumes were restated in the first quarter 2007 to report commingled volumes from multiple zones within the same geographic area based upon regulatory approval. (3) Foster Creek and Christina Lake volumes in 2006 and 2005 were restated in the first quarter 2007 on a pro forma basis to reflect the integrated oilsands transaction. (4) Pelican Lake reached royalty payout in April 2006. Drilling activity in key North American resource plays ------------------------------------------------------------------------- Net Wells Drilled ----------------------------------------------------------- Resource Play 2007 2006 2005 ----------------------------------------------------------- Full Full YTD Q3 Q2 Q1 Year Q4 Q3 Q2 Q1 Year ------------------------------------------------------------------------- Natural gas Jonah 112 31 42 39 163 41 48 48 26 104 Piceance 209 72 72 65 220 50 48 59 63 266 East Texas 27 9 11 7 59 11 12 17 19 84 Fort Worth 60 17 29 14 97 19 22 27 29 59 Greater Sierra 82 27 32 23 115 5 16 34 60 164 Cutbank Ridge 70 18 25 27 116 19 35 36 26 135 Bighorn 52 15 9 28 52 7 7 18 20 51 CBM (1) 749 323 18 408 729 157 156 35 381 1,245 Shallow Gas(2) 1,265 608 241 416 1,310 389 475 217 229 1,389 ------------------------------------------------------------------------- Total gas wells 2,626 1,120 479 1,027 2,861 698 819 491 853 3,497 ------------------------------------------------------------------------- Oil Foster Creek(3) 17 8 1 8 3 - - - 3 20 Christina Lake(3) 3 1 2 - 1 - - - 1 - Pelican Lake - - - - - - - - - 52 ------------------------------------------------------------------------- Total oil wells 20 9 3 8 4 - - - 4 72 ------------------------------------------------------------------------- Total 2,646 1,129 482 1,035 2,865 698 819 491 857 3,569 ------------------------------------------------------------------------- (1) CBM net wells drilled were restated in 2006 to account for commingled volumes from the coal and sand intervals based upon regulatory approval. (2) Shallow Gas net wells drilled were restated in the first quarter 2007 as a result of reporting commingled volumes from multiple zones within the same geographic area based upon regulatory approval. (3) Foster Creek and Christina Lake net wells drilled in 2006 and 2005 were restated in the first quarter 2007 on a pro forma basis to reflect the integrated oilsands transaction. ------------------------------------------------------------------------- Third quarter 2007 natural gas and oil prices ------------------------------------------------------------------------- Q3 Q3 % 9 months 9 months % 2007 2006 change 2007 2006 change ------------------------------------------------------------------------- Natural gas ($/Mcf, realized prices include hedging) NYMEX 6.16 6.58 - 6 6.83 7.45 - 8 EnCana Realized Gas Price 6.75 6.57 + 3 7.19 6.74 + 7 ------------------------------------------------------------------------- Oil and NGLs ($/bbl, realized prices include hedging) WTI 75.15 70.54 + 7 66.22 68.26 - 3 Western Canadian Select (WCS) 52.71 51.71 + 2 46.86 46.55 + 1 Differential WTI/WCS 22.44 18.83 + 19 19.36 21.71 - 11 EnCana Realized Liquids Price 49.01 46.92 + 4 45.71 42.03 + 9 ------------------------------------------------------------------------- 3-2-1 Crack Spread ($/bbl) U.S. Gulf Coast 11.74 11.00 + 7 15.36 12.18 + 26 U.S. Mid-Continent 20.92 17.75 + 18 22.34 15.72 + 42 Chicago 18.48 15.29 + 21 20.50 14.67 + 40 ------------------------------------------------------------------------- Price risk management

Risk management positions at September 30, 2007 are presented in Note 19 to the unaudited Interim Consolidated Financial Statements. In the third quarter of 2007, EnCana's commodity price risk management measures resulted in realized gains of approximately $323 million after-tax, composed of a $364 million gain on gas hedges and a $41 million loss on oil and other hedges.

About 1.1 Bcf/d of 2008 gas production hedged at $8.30 per Mcf

EnCana currently has fixed price contracts on about 1.1 Bcf/d of expected 2008 gas production, at a NYMEX equivalent price of about $8.30 per Mcf. For the fourth quarter of 2007, EnCana has about 1.8 Bcf/d of gas production with downside price protection, composed of 1.6 Bcf/d under fixed price contracts at an average NYMEX equivalent price of $8.77 per Mcf and 240 MMcf/d with put options at a NYMEX equivalent strike price of $6.00 per Mcf. EnCana has hedged 23,000 bbls/d of expected 2008 oil production at a price of WTI $70.13 per bbl. EnCana also has about 126,000 bbls/d of 2007 oil production with downside price protection, composed of 34,500 bbls/d under fixed price contracts at an average West Texas Intermediate (WTI) price of $64.40 per bbl, plus put options on 91,500 bbls/d at an average strike price of WTI $55.34 per bbl. This price hedging strategy helps reduce uncertainty in cash flow during periods of commodity price volatility.

U.S. Rockies and Canadian basis differential hedges

North American natural gas prices are impacted by volatile pricing disconnects caused primarily by transportation constraints between producing regions and consuming regions. EnCana's production gives rise to exposure to these price discounts, also known as basis differentials. For the remainder of 2007 EnCana has hedged 100 percent of its expected U.S. Rockies basis exposure using a combination of downstream transportation and basis hedges. The basis hedges have an effective annual average differential of NYMEX less 67 cents per Mcf. During the third quarter of 2007 the U.S. Rockies-NYMEX natural gas price differential averaged $3.22 per Mcf. For 2008, EnCana has hedged 100 percent of its expected U.S. Rockies basis exposure using a combination of downstream transportation and basis hedges, including some hedges that are based on a percentage of NYMEX prices. At the end of the third quarter, the basis hedges had an effective annual average differential of NYMEX less $1.01 per Mcf. In Canada for 2007, EnCana has hedged 33 percent of its expected AECO basis exposure at 72 cents per Mcf. EnCana has an additional 31 percent of expected Canadian basis exposure subject to transport and aggregator contracts. In the third quarter of 2007, the AECO basis differential averaged 84 cents per Mcf. In Canada for 2008, EnCana has hedged 8 percent of its expected production at an average AECO basis differential of 78 cents per Mcf. During the third quarter of 2007, EnCana's basis hedging resulted in a realized gain before tax of about $255 million.

Corporate developments ---------------------- Alberta Royalty Review

The Government of Alberta is in the midst of a comprehensive review of the province's oil and natural gas royalty structure. Until detailed and specific information of any royalty changes is outlined publicly and thoroughly evaluated by the company, EnCana is unable to comment on how potential changes may impact the company's operations.

Columbia River Basin

EnCana has concluded its exploration program in the Columbia River Basin in Washington state after drilling three wells, Anderville Farms Inc. # 1, Anderson 11-5, and Brown 7-24. Each well indicated the presence of natural gas. Although commercial flow rates were not established in these wells, there remains potential for large natural gas accumulations in the basin, which has only been partially tested. Exxel Energy Corp. took over operatorship and ownership of the Brown well in late September and is planning to conduct additional completion testing on the well. Because this is a non-core play for EnCana, the company anticipates that any future activities on EnCana's acreage position will likely be funded by third-party capital under farm-in or similar arrangements. As a result, EnCana has no immediate plans for additional drilling.

Quarterly dividend of 20 cents per share approved

EnCana's board of directors has approved a quarterly dividend of 20 cents per share, which is payable on December 31, 2007 to common shareholders of record as of December 14, 2007.

Normal Course Issuer Bid

In the past 12 months under its Normal Course Issuer Bid, EnCana purchased 63.4 million common shares, representing approximately 7.9 percent of the company's outstanding shares on November 1, 2006, at an average price of approximately US$51.54 per common share.

Financial strength ------------------

EnCana maintains a strong balance sheet, targeting a net debt-to-capitalization ratio between 30 and 40 percent. At September 30, 2007, the company's net debt-to-capitalization ratio was 27:73. At the end of the third quarter EnCana's net debt-to-adjusted-EBITDA multiple, on a trailing 12-month basis, was 0.8 times. The company expects its net debt-to-capitalization ratio to remain at the lower end of the targeted range.

In the third quarter of 2007, EnCana invested $1,575 million in capital. Net acquisitions were $16 million, resulting in net capital investment in continuing operations of $1,591 million.

------------------------------------------------------------------------- CONFERENCE CALL TODAY 11 a.m. Mountain Time (1 p.m. Eastern Time) EnCana Corporation will host a conference call today, Thursday, October 25, 2007 starting at 11:00 a.m. MT (1:00 p.m. ET). To participate, please dial (866) 215-9524 (toll-free in North America) or (416) 915-9619 approximately 10 minutes prior to the conference call. An archived recording of the call will be available from approximately 3:00 p.m. MT on October 25 until midnight October 29, 2007 by dialing (888) 203-1112 or (719) 457-0820 and entering access code 6834269. A live audio webcast of the conference call will also be available via EnCana's website, http://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, pre-tax cash flow, operating earnings and free cash flow.

- Cash flow is a non-GAAP measure defined as Cash from Operating Activities excluding net change in other assets and liabilities, net change in non-cash working capital from continuing operations and net change in non-cash working capital from discontinued operations, all of which are defined on the Consolidated Statement of Cash Flows. - Pre-tax cash flow is calculated as cash flow before cash taxes. - Operating earnings is a non-GAAP measure that shows net earnings excluding non-operating items such as the after-tax impacts of a gain/loss on discontinuance, the after-tax gain/loss of unrealized mark-to-market accounting for derivative instruments, the after-tax gain/loss on translation of U.S. dollar denominated Notes issued from Canada and the partnership contribution receivable and the effect of the reduction in income tax rates. Management believes that these excluded items reduce the comparability of the company's underlying financial performance between periods. The majority of the unrealized gains/losses that relate to U.S. dollar denominated Notes issued from Canada are for debt with maturity dates in excess of five years. - Free cash flow is a non-GAAP measure that EnCana defines as cash flow in excess of total capital investment and is used to determine the funds available for other investing and/or financing activities.

These measures have been described and presented in this news release in order to provide shareholders and potential investors with additional information regarding EnCana's liquidity and its ability to generate funds to finance its operations.

EnCana Corporation

With an enterprise value of approximately US$55 billion, EnCana is a leading North American unconventional natural gas and integrated oilsands company. By partnering with employees, community organizations and other businesses, EnCana contributes to the strength and sustainability of the communities where it operates. EnCana common shares trade on the Toronto and New York stock exchanges under the symbol ECA.

ADVISORY REGARDING RESERVES DATA AND OTHER OIL AND GAS INFORMATION - EnCana's disclosure of reserves data and other oil and gas information is made in reliance on an exemption granted to EnCana by Canadian securities regulatory authorities which permits it to provide such disclosure in accordance with U.S. disclosure requirements. The information provided by EnCana may differ from the corresponding information prepared in accordance with Canadian disclosure standards under National Instrument 51-101 (NI 51-101). EnCana's reserves quantities represent net proved reserves calculated using the standards contained in Regulation S-X of the U.S. Securities and Exchange Commission. Further information about the differences between the U.S. requirements and the NI 51-101 requirements is set forth under the heading "Note Regarding Reserves Data and Other Oil and Gas Information" in EnCana's Annual Information Form.

In this news release, certain crude oil and NGLs volumes have been converted to cubic feet equivalent (cfe) on the basis of one barrel (bbl) to six thousand cubic feet (Mcf). Also, certain natural gas volumes have been converted to barrels of oil equivalent (BOE) on the same basis. BOE and cfe may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the well head.

ADVISORY REGARDING FORWARD-LOOKING STATEMENTS - In the interests of providing EnCana shareholders and potential investors with information regarding EnCana, including management's assessment of EnCana's and its subsidiaries' future plans and operations, certain statements contained in this news release are forward-looking statements or information within the meaning of applicable securities legislation, collectively referred to herein as "forward-looking statements." Forward-looking statements in this news release include, but are not limited to: future economic and operating performance (including per share growth, net debt-to-capitalization ratio, sustainable growth and returns, cash flow, cash flow per share and increases in net asset value); anticipated ability to meet the company's guidance forecasts; anticipated life of proved reserves; anticipated growth and success of resource plays and the expected characteristics of resource plays; the anticipated production, timing thereof, and expenditures associated with the Deep Panuke Project; anticipated potential of and third party capital for the Columbia River Basin; planned expansion of in-situ oilsands production; anticipated crude oil and natural gas prices, including basis differentials for various regions; the expected impact of proposed Rockies Express Pipeline on Rockies basis differentials; anticipated expansion and production at Foster Creek and Christina Lake; anticipated increased capacity for the Borger and Wood River refineries; anticipated integrated oilsands cash flow; projections for future crack spreads and anticipated refining profits; anticipated drilling inventory; expected proportion of total production and cash flows contributed by natural gas; anticipated success of EnCana's market risk mitigation strategy and EnCana's ability to reduce uncertainty in cash flow during periods of commodity price volatility and provide downside price protection; anticipated purchases pursuant to the Normal Course Issuer Bid and the source of funding therefor; potential demand for natural gas; anticipated bitumen production in 2007 and beyond; anticipated drilling; potential capital expenditures and investment; potential oil, natural gas and NGLs production in 2007 and beyond; anticipated costs and inflationary pressures; potential risks associated with drilling and references to potential exploration. Readers are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur, which may cause the company's actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. These risks and uncertainties include, among other things: volatility of and assumptions regarding oil and gas prices; assumptions based upon the company's current guidance; fluctuations in currency and interest rates; product supply and demand; market competition; risks inherent in the company's marketing operations, including credit risks; imprecision of reserves estimates and estimates of recoverable quantities of oil, natural gas and liquids from resource plays and other sources not currently classified as proved reserves; the ability of the company and ConocoPhillips to successfully manage and operate the integrated North American heavy oil business and the ability of the parties to obtain necessary regulatory approvals; refining and marketing margins; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; potential failure of new products to achieve acceptance in the market; unexpected cost increases or technical difficulties in constructing or modifying manufacturing or refining facilities; unexpected difficulties in manufacturing, transporting or refining synthetic crude oil; risks associated with technology; the company's ability to replace and expand oil and gas reserves; its ability to generate sufficient cash flow from operations to meet its current and future obligations; its ability to access external sources of debt and equity capital; the timing and the costs of well and pipeline construction; the company's ability to secure adequate product transportation; changes in royalty, tax, environmental and other laws or regulations or the interpretations of such laws or regulations; political and economic conditions in the countries in which the company operates; the risk of war, hostilities, civil insurrection and instability affecting countries in which the company operates and terrorist threats; risks associated with existing and potential future lawsuits and regulatory actions made against the company; and other risks and uncertainties described from time to time in the reports and filings made with securities regulatory authorities by EnCana. Although EnCana believes that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned that the foregoing list of important factors is not exhaustive.

Furthermore, the forward-looking statements contained in this news release are made as of the date of this news release, and, except as required by law, EnCana does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this news release are expressly qualified by this cautionary statement.

Third quarter report for the period ended September 30, 2007 CONSOLIDATED STATEMENT OF EARNINGS (unaudited) Three Months Ended Nine Months Ended September 30, September 30, ($ millions, except per --------------------------------------- share amounts) 2007 2006 2007 2006 ------------------------------------------------------------------------- REVENUES, NET OF ROYALTIES (Note 6) Upstream $ 2,883 $ 2,622 $ 8,597 $ 7,817 Integrated Oilsands 2,191 248 5,614 713 Market Optimization 629 731 2,107 2,272 Corporate - Unrealized gain (loss) on risk management (107) 428 (673) 1,921 ------------------------------------------------------------------------- 5,596 4,029 15,645 12,723 EXPENSES (Note 6) Production and mineral taxes 79 79 228 269 Transportation and selling 220 271 732 795 Operating 530 420 1,646 1,227 Purchased product 2,192 677 5,879 2,160 Depreciation, depletion and amortization 988 791 2,730 2,346 Administrative 73 54 263 187 Interest, net (Note 9) 102 83 297 254 Accretion of asset retirement obligation (Note 15) 17 13 46 37 Foreign exchange (gain) loss, net (Note 10) 74 - 69 (158) (Gain) loss on divestitures (Note 8) (29) (304) (87) (321) ------------------------------------------------------------------------- 4,246 2,084 11,803 6,796 ------------------------------------------------------------------------- NET EARNINGS BEFORE INCOME TAX 1,350 1,945 3,842 5,927 Income tax expense (Note 11) 416 602 965 1,519 ------------------------------------------------------------------------- NET EARNINGS FROM CONTINUING OPERATIONS 934 1,343 2,877 4,408 NET EARNINGS FROM DISCONTINUED OPERATIONS (Note 7) - 15 - 581 ------------------------------------------------------------------------- NET EARNINGS $ 934 $ 1,358 $ 2,877 $ 4,989 ------------------------------------------------------------------------- ------------------------------------------------------------------------- NET EARNINGS FROM CONTINUING OPERATIONS PER COMMON SHARE (Note 18) Basic $ 1.24 $ 1.66 $ 3.79 $ 5.32 Diluted $ 1.24 $ 1.63 $ 3.75 $ 5.21 ------------------------------------------------------------------------- ------------------------------------------------------------------------- NET EARNINGS PER COMMON SHARE (Note 18) Basic $ 1.24 $ 1.68 $ 3.79 $ 6.02 Diluted $ 1.24 $ 1.65 $ 3.75 $ 5.90 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying Notes to Consolidated Financial Statements. CONSOLIDATED STATEMENT OF RETAINED EARNINGS (unaudited) Nine Months Ended September 30, ------------------- ($ millions) 2007 2006 ------------------------------------------------------------------------- RETAINED EARNINGS, BEGINNING OF YEAR $ 11,344 $ 9,481 Net Earnings 2,877 4,989 Dividends on Common Shares (453) (226) Charges for Normal Course Issuer Bid (Note 16) (1,618) (2,450) ------------------------------------------------------------------------- RETAINED EARNINGS, END OF PERIOD $ 12,150 $ 11,794 ------------------------------------------------------------------------- ------------------------------------------------------------------------- CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (unaudited) Three Months Ended Nine Months Ended September 30, September 30, --------------------------------------- ($ millions) 2007 2006 2007 2006 ------------------------------------------------------------------------- NET EARNINGS $ 934 $ 1,358 $ 2,877 $ 4,989 OTHER COMPREHENSIVE INCOME, NET OF TAX Foreign Currency Translation Adjustment 859 (7) 1,798 531 ------------------------------------------------------------------------- COMPREHENSIVE INCOME $ 1,793 $ 1,351 $ 4,675 $ 5,520 ------------------------------------------------------------------------- ------------------------------------------------------------------------- CONSOLIDATED STATEMENT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (unaudited) Nine Months Ended September 30, ------------------- ($ millions) 2007 2006 ------------------------------------------------------------------------- ACCUMULATED OTHER COMPREHENSIVE INCOME, BEGINNING OF YEAR $ 1,375 $ 1,262 Foreign Currency Translation Adjustment 1,798 531 ------------------------------------------------------------------------- ACCUMULATED OTHER COMPREHENSIVE INCOME, END OF PERIOD $ 3,173 $ 1,793 ------------------------------------------------------------------------- ------------------------------------------------------------------------- As at September 30, 2007, the accumulated other comprehensive income consists of foreign currency translation adjustments of $3,173 million (December 31, 2006 - $1,375 million; September 30, 2006 - $1,793 million). See accompanying Notes to Consolidated Financial Statements. CONSOLIDATED BALANCE SHEET (unaudited) As at As at September 30, December 31, ($ millions) 2007 2006 ------------------------------------------------------------------------- ASSETS Current Assets Cash and cash equivalents $ 515 $ 402 Accounts receivable and accrued revenues 2,146 1,721 Current portion of partnership contribution receivable (Note 5, 12) 293 - Risk management (Note 19) 820 1,403 Inventories (Note 13) 775 176 ------------------------------------------------------------------------- 4,549 3,702 Property, Plant and Equipment, net (Note 6) 32,156 28,213 Investments and Other Assets 604 533 Partnership Contribution Receivable (Note 5, 12) 3,223 - Risk Management (Note 19) 57 133 Goodwill 2,873 2,525 ------------------------------------------------------------------------- (Note 6) $ 43,462 $ 35,106 ------------------------------------------------------------------------- ------------------------------------------------------------------------- LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities Accounts payable and accrued liabilities $ 3,717 $ 2,494 Income tax payable 687 926 Current portion of partnership contribution payable (Note 5, 12) 284 - Risk management (Note 19) 98 14 Current portion of long-term debt (Note 14) 1,000 257 ------------------------------------------------------------------------- 5,786 3,691 Long-Term Debt (Note 14) 6,246 6,577 Other Liabilities 205 79 Partnership Contribution Payable (Note 5, 12) 3,236 - Risk Management (Note 19) 12 2 Asset Retirement Obligation (Note 15) 1,272 1,051 Future Income Taxes 6,865 6,240 ------------------------------------------------------------------------- 23,622 17,640 ------------------------------------------------------------------------- Shareholders' Equity Share capital (Note 16) 4,457 4,587 Paid in surplus 60 160 Retained earnings 12,150 11,344 Accumulated other comprehensive income 3,173 1,375 ------------------------------------------------------------------------- Total Shareholders' Equity 19,840 17,466 ------------------------------------------------------------------------- $ 43,462 $ 35,106 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying Notes to Consolidated Financial Statements. CONSOLIDATED STATEMENT OF CASH FLOWS (unaudited) Three Months Ended Nine Months Ended September 30, September 30, --------------------------------------- ($ millions) 2007 2006 2007 2006 ------------------------------------------------------------------------- OPERATING ACTIVITIES Net earnings from continuing operations $ 934 $ 1,343 $ 2,877 $ 4,408 Depreciation, depletion and amortization 988 791 2,730 2,346 Future income taxes (Note 11) 102 401 (9) 690 Cash tax on sale of assets (Note 8) - 49 - 49 Unrealized (gain) loss on risk management (Note 19) 107 (428) 666 (1,919) Unrealized foreign exchange (gain) loss 83 4 142 (79) Accretion of asset retirement obligation (Note 15) 17 13 46 37 (Gain) loss on divestitures (Note 8) (29) (304) (87) (321) Other 16 14 154 90 Cash flow from discontinued operations - 11 - 99 Net change in other assets and liabilities 1 21 5 48 Net change in non-cash working capital from continuing operations (19) (247) (247) 3,305 Net change in non-cash working capital from discontinued operations - (13) - (2,476) ------------------------------------------------------------------------- Cash From Operating Activities 2,200 1,655 6,277 6,277 ------------------------------------------------------------------------- INVESTING ACTIVITIES Capital expenditures (Note 6) (1,650) (1,486) (4,329) (5,350) Proceeds on disposal of assets (Note 8) 59 377 505 634 Cash tax on sale of assets (Note 8) - (49) - (49) Net change in investments and other 32 (56) 26 (38) Net change in non-cash working capital from continuing operations 69 (18) (34) (169) Discontinued operations - - - 2,377 ------------------------------------------------------------------------- Cash (Used in) Investing Activities (1,490) (1,232) (3,832) (2,595) ------------------------------------------------------------------------- FINANCING ACTIVITIES Net issuance (repayment) of revolving long-term debt (871) 470 (909) (512) Issuance of long-term debt (Note 14) 492 - 924 - Repayment of long-term debt - (73) - (73) Issuance of common shares (Note 16) 5 39 158 140 Purchase of common shares (Note 16) (218) (900) (2,025) (2,973) Dividends on common shares (149) (80) (453) (226) Other 2 2 (1) (9) ------------------------------------------------------------------------- Cash (Used in) Financing Activities (739) (542) (2,306) (3,653) ------------------------------------------------------------------------- DEDUCT: FOREIGN EXCHANGE LOSS ON CASH AND CASH EQUIVALENTS HELD IN FOREIGN CURRENCY 11 - 26 - ------------------------------------------------------------------------- INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (40) (119) 113 29 CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 555 253 402 105 ------------------------------------------------------------------------- CASH AND CASH EQUIVALENTS, END OF PERIOD $ 515 $ 134 $ 515 $ 134 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying Notes to Consolidated Financial Statements. Notes to Consolidated Financial Statements (unaudited) (All amounts in $ millions unless otherwise specified) 1. BASIS OF PRESENTATION The interim Consolidated Financial Statements include the accounts of EnCana Corporation and its subsidiaries ("EnCana" or the "Company"), and are presented in accordance with Canadian generally accepted accounting principles. EnCana's continuing operations are in the business of exploration for, and production and marketing of natural gas, crude oil and natural gas liquids, refining operations and power generation operations. The interim Consolidated Financial Statements have been prepared following the same accounting policies and methods of computation as the annual audited Consolidated Financial Statements for the year ended December 31, 2006, except as noted below. The disclosures provided below are incremental to those included with the annual audited Consolidated Financial Statements. The interim Consolidated Financial Statements should be read in conjunction with the annual audited Consolidated Financial Statements and the notes thereto for the year ended December 31, 2006. 2. CHANGES IN ACCOUNTING POLICIES AND PRACTICES As disclosed in the December 31, 2006 annual audited Consolidated Financial Statements, on January 1, 2007, the Company adopted the Canadian Institute of Chartered Accountants ("CICA") Handbook Section 1530 "Comprehensive Income", Section 3251 "Equity", Section 3855 "Financial Instruments - Recognition and Measurement", and Section 3865 "Hedges". As required by the new standards, prior periods have not been restated, except to reclassify the foreign currency translation adjustment balance as described under Comprehensive Income. The adoption of these standards has had no material impact on the Company's net earnings or cash flows. The other effects of the implementation of the new standards are discussed below. Comprehensive Income The new standards introduce comprehensive income, which consists of net earnings and other comprehensive income ("OCI"). The Company's Consolidated Financial Statements now include a Statement of Comprehensive Income, which includes the components of comprehensive income. For EnCana, OCI is currently comprised of the changes in the foreign currency translation adjustment balance. The cumulative changes in OCI are included in accumulated other comprehensive income ("AOCI"), which is presented as a new category within shareholders' equity in the Consolidated Balance Sheet. The accumulated foreign currency translation adjustment, formerly presented as a separate category within shareholders' equity, is now included in AOCI. The Company's Consolidated Financial Statements now include a Statement of Accumulated Other Comprehensive Income, which provides the continuity of the AOCI balance. The adoption of comprehensive income has been made in accordance with the applicable transitional provisions. Accordingly, the September 30, 2007 period end accumulated foreign currency translation adjustment balance of $3,173 million has been reclassified to AOCI (December 31, 2006 - $1,375 million; September 30, 2006 - $1,793 million). In addition, the change in the accumulated foreign currency translation adjustment balance for the three months and nine months ended September 30, 2007 of $859 million and $1,798 million, respectively, is now included in OCI in the Statement of Comprehensive Income (three months and nine months ended September 30, 2006 - $(7) million and $531 million, respectively). Financial Instruments The financial instruments standard establishes the recognition and measurement criteria for financial assets, financial liabilities and derivatives. All financial instruments are required to be measured at fair value on initial recognition of the instrument, except for certain related party transactions. Measurement in subsequent periods depends on whether the financial instrument has been classified as "held-for- trading", "available-for-sale", "held-to-maturity", "loans and receivables", or "other financial liabilities" as defined by the standard. Financial assets and financial liabilities "held-for-trading" are measured at fair value with changes in those fair values recognized in net earnings. Financial assets "available-for-sale" are measured at fair value, with changes in those fair values recognized in OCI. Financial assets "held-to-maturity", "loans and receivables" and "other financial liabilities" are measured at amortized cost using the effective interest method of amortization. The methods used by the Company in determining fair value of financial instruments are unchanged as a result of implementing the new standard. Cash and cash equivalents are designated as "held-for-trading" and are measured at carrying value, which approximates fair value due to the short-term nature of these instruments. Accounts receivable and accrued revenues and the partnership contribution receivable are designated as "loans and receivables". Accounts payable and accrued liabilities, the partnership contribution payable and long-term debt are designated as "other financial liabilities". The adoption of the financial instruments standard has been made in accordance with its transitional provisions. Accordingly, at January 1, 2007, $52 million of other assets were reclassified to long-term debt to reflect the adopted policy of capitalizing long-term debt transaction costs, premiums and discounts within long-term debt. The costs capitalized within long-term debt will be amortized using the effective interest method. Previously, the Company deferred these costs within other assets and amortized them straight-line over the life of the related long-term debt. The adoption of the effective interest method of amortization had no effect on opening retained earnings. Risk management assets and liabilities are derivative financial instruments classified as "held-for-trading" unless designated for hedge accounting. Additional information on the Company's accounting treatment of derivative financial instruments is contained in Note 1 of the Company's annual audited Consolidated Financial Statements for the year ended December 31, 2006. 3. UPDATE TO ACCOUNTING POLICIES AND PRACTICES As a result of the new joint venture with ConocoPhillips, EnCana has updated the following significant accounting policies and practices to incorporate the refining business (see Note 5): Revenue Recognition Revenues associated with the sales of EnCana's natural gas, crude oil, NGLs and petroleum and chemical products are recognized when title passes from the Company to its customer. Natural gas and crude oil produced and sold by EnCana below or above its working interest share in the related resource properties results in production underliftings or overliftings. Underliftings are recorded as inventory and overliftings are recorded as deferred revenue. Realized gains and losses from the Company's natural gas and crude oil commodity price risk management activities are recorded in revenue when the product is sold. Market optimization revenues and purchased product are recorded on a gross basis when EnCana takes title to product and has risks and rewards of ownership. Purchases and sales of inventory with the same counterparty that are entered into in contemplation of each other are recorded on a net basis. Revenues associated with the services provided where EnCana acts as agent are recorded as the services are provided. Revenues associated with the sale of natural gas storage services are recognized when the services are provided. Sales of electric power are recognized when power is provided to the customer. Unrealized gains and losses from the Company's natural gas and crude oil commodity price risk management activities are recorded as revenue based on the related mark-to-market calculations at the end of the respective period. Inventory Product inventories, including petroleum and chemical products, are valued at the lower of average cost and net realizable value on a first- in, first-out basis. Materials and supplies are valued at cost. Property, Plant and Equipment Upstream EnCana accounts for natural gas and crude oil properties in accordance with the Canadian Institute of Chartered Accountants' guideline on full cost accounting in the oil and gas industry. Under this method, all costs, including internal costs and asset retirement costs, directly associated with the acquisition of, exploration for, and the development of natural gas and crude oil reserves, are capitalized on a country-by- country cost centre basis. Costs accumulated within each cost centre are depreciated, depleted and amortized using the unit-of-production method based on estimated proved reserves determined using estimated future prices and costs. For purposes of this calculation, oil is converted to gas on an energy equivalent basis. Capitalized costs subject to depletion include estimated future costs to be incurred in developing proved reserves. Proceeds from the divestiture of properties are normally deducted from the full cost pool without recognition of gain or loss unless that deduction would result in a change to the rate of depreciation, depletion and amortization of 20 percent or greater, in which case a gain or loss is recorded. Costs of major development projects and costs of acquiring and evaluating significant unproved properties are excluded, on a cost centre basis, from the costs subject to depletion until it is determined whether or not proved reserves are attributable to the properties, or impairment has occurred. Costs that have been impaired are included in the costs subject to depreciation, depletion and amortization. An impairment loss is recognized in net earnings when the carrying amount of a cost centre is not recoverable and the carrying amount of the cost centre exceeds its fair value. The carrying amount of the cost centre is not recoverable if the carrying amount exceeds the sum of the undiscounted cash flows from proved reserves. If the sum of the cash flows is less than the carrying amount, the impairment loss is limited to the amount by which the carrying amount exceeds the sum of: i. the fair value of proved and probable reserves; and ii. the costs of unproved properties that have been subject to a separate impairment test. Downstream Refining Refining facilities are carried at cost, including asset retirement costs, and depreciated on a straight-line basis over the estimated service lives of the assets, which are approximately 25 years. Midstream Facilities Midstream facilities, including natural gas storage facilities, natural gas liquids extraction plant facilities and power generation facilities, are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets, which range from 20 to 25 years. Capital assets related to pipelines are carried at cost and depreciated or amortized using the straight-line method over their economic lives, which range from 20 to 35 years. Corporate Costs associated with office furniture, fixtures, leasehold improvements, information technology and aircraft are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets, which range from 3 to 25 years. Assets under construction are not subject to depreciation. Land is carried at cost. Asset Retirement Obligation The fair value of estimated asset retirement obligations is recognized in the Consolidated Balance Sheet when identified and a reasonable estimate of fair value can be made. Asset retirement obligations include those legal obligations where the Company will be required to retire tangible long-lived assets such as producing well sites, offshore production platforms, natural gas processing plants, and refining facilities. These obligations also include items for which the Company has made promissory estoppel. The asset retirement cost, equal to the initially estimated fair value of the asset retirement obligation, is capitalized as part of the cost of the related long-lived asset. Changes in the estimated obligation resulting from revisions to estimated timing or amount of undiscounted cash flows are recognized as a change i

Source: PRNewswire-FirstCall

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