EnCana generates 2008 cash flow of US$9.4 billion, or $12.48 per share, up 13 percent

Posted on: Thursday, 12 February 2009, 05:00 CST

Operating earnings per share up 9 percent; Proved reserves additions 150% of production

CALGARY, Feb. 12 /PRNewswire-FirstCall/ - EnCana Corporation (TSX & NYSE: ECA) achieved solid increases in 2008 cash flow and operating earnings as a result of strong growth in natural gas and oil production and higher prices. Financial results were enhanced in the fourth quarter by EnCana's favourable natural gas price hedges. Again in 2008, EnCana achieved strong year-over-year proved reserves additions.

"Despite the unprecedented volatility in oil and natural gas prices and a challenging operating environment in 2008, EnCana delivered strong operational and financial performance. We met or exceeded all of our targets, including those for cash flow, production and capital investment. Overall production grew 6 percent, driven by our key resource plays which increased 13 percent year-over-year. We added reserves of 2.5 trillion cubic feet of gas equivalent, replacing 150 percent of production at a very competitive finding and development cost of US$2.50 per thousand cubic feet of gas equivalent," said Randy Eresman, EnCana's President & Chief Executive Officer.

"EnCana is pursuing a conservative and prudent capital program in 2009 and we have built flexibility into our plans to adjust investment depending on how the year unfolds. With widespread economic uncertainty, we remain intently focused on our core business objectives: maintaining financial strength, generating significant free cash flow, further optimizing our capital investments and continuing to pay a stable dividend to shareholders - currently $1.60 per share annualized, which at the current share price results in a yield of about 3.7 percent.

"Natural gas and oil prices are expected to remain low at least through the first quarter of 2009. While we have seen some indication of a softening in service and supply costs, reductions are likely to be more pronounced in the latter half of 2009. We are affirming our 2009 corporate guidance. Our cash flow forecast for the year is underpinned by strong hedges - about two- thirds of expected natural gas production hedged through October 2009 at an average price of $9.13 per thousand cubic feet, well above the current spot price. In addition, we are continually seeking new ways to strengthen our financial position, including cost-reduction initiatives, project reviews throughout the year and exploring and implementing operational efficiencies across our company.

"EnCana's low-risk, low-cost resource play business model provides financial resilience and positions the company very well for dealing with the economic downturn. We can apply an even higher level of scrutiny and fine tune investments in order to target optimal project returns and long-term value creation," Eresman said.

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 in 2006 have been adjusted on a pro-forma basis to reflect the integrated oil transaction. Unless otherwise noted in this news release, EnCana's proved reserves and production for 2007 and 2008 are reported on a post integrated oil basis. 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).

2008 Highlights --------------- Financial - US$ - Cash flow increased 13 percent per share to $12.48, or $9.4 billion - Operating earnings were up 9 percent per share to $5.86, or $4.4 billion - Net earnings were up 53 percent per share to $7.91, or $5.9 billion, primarily due to an after-tax unrealized mark-to-market hedging gain of $1.8 billion in 2008 compared to an after-tax loss of $811 million in 2007. - Capital investment, excluding acquisitions and divestitures, was up 17 percent to $7.1 billion - Generated $2.3 billion of free cash flow (as defined in Note 1 on page 10), down $112 million from 2007 - Operating cash flow nearly doubled to $421 million from the company's Foster Creek and Christina Lake upstream projects, whereas lower refining margins and higher purchased product costs resulted in a $241 million loss in operating cash flow for the downstream business. As a result, EnCana's integrated oil business venture with ConocoPhillips generated $180 million of operating cash flow - Purchased approximately 4.8 million EnCana shares at an average price of $67.13 under the Normal Course Issuer Bid, for a total cost of approximately $326 million - Doubled quarterly dividend to 40 cents per share in March 2008, or $1.60 per share on an annualized basis - At year end, debt to capitalization was 28 percent and debt to adjusted EBITDA was 0.7 times Operating - Upstream - Natural gas production increased 8 percent to 3.8 billion cubic feet per day (Bcf/d), up 9 percent per share - Increased production from natural gas key resource plays by 14 percent - Oil and natural gas liquids (NGLs) production was relatively flat at about 134,000 barrels per day (bbls/d) - Integrated oil production grew 13 percent to 30,183 bbls/d at Foster Creek and Christina Lake - Operating and administrative costs of $1.25 per thousand cubic feet equivalent (Mcfe), compared to $1.17 per Mcfe in 2007 Operating - Downstream - Refined products averaged 448,000 bbls/d (224,000 bbls/d net to EnCana) - Refinery crude utilization of 93 percent or 423,000 bbls/d crude throughput (211,500 bbls/d net to EnCana) Reserves - Total proved reserves increased 5 percent to 19.7 trillion cubic feet of gas equivalent (Tcfe) - Added 2.5 Tcfe of proved reserves, compared to production of 1.7 Tcfe, for a production replacement of 150 percent - Proved natural gas reserves increased 3 percent to 13.7 trillion cubic feet (Tcf) - Proved oil and NGLs reserves increased 8 percent to 1.0 billion barrels - Proved reserves additions, excluding acquisitions and divestitures, included approximately 1.9 Tcf of natural gas reserves and 130 million bbls of oil and NGLs reserves - Finding and development (F&D) costs were $2.50 per Mcfe - Three-year (2006-2008) F&D costs averaged $2.02 per Mcfe - F&D costs for natural gas and associated liquids were approximately $2.90 per Mcfe - Proved reserves life index of approximately 12 years - Reserves replacement costs are outlined on page 7 Strategic developments - Acquired additional land and mineral interests in the Haynesville Shale play in Louisiana and Texas for approximately $1.0 billion - Began construction of a Coker and Refinery Expansion (CORE) project at the Wood River refinery in Roxana, Illinois that is expected to expand heavy oil processing capacity and increase production of clean transportation fuels for the U.S. Midwest market - Signed a contract for the design and construction of the Production Field Centre for the Deep Panuke natural gas project offshore Nova Scotia - Divested mature conventional oil and natural gas assets in North America for approximately $698 million as well as interests in Brazil for approximately $164 million, before closing adjustments

Fourth quarter natural gas production grows 4 percent

EnCana's fourth quarter natural gas production increased 4 percent to 3.9 Bcf/d, compared to the same quarter in 2007. Oil and natural gas liquids production in the quarter was flat at 136,000 bbls/d. Total production increased 3 percent to 4.7 Bcfe/d. Fourth quarter cash flow per share decreased 32 percent to $1.73, or $1.3 billion, and operating earnings per share decreased 46 percent to $0.60, or $449 million, largely due to a 30 percent drop in heavy oil prices and a 31 percent decrease in the Chicago 3-2- 1 crack spread.

------------------------------------------------------------------------- Financial Summary - Total Consolidated ------------------------------------------------------------------------- (for the period ended December 31) ($ millions, except Q4 Q4 % % per share amounts) 2008 2007 change 2008 2007 change ------------------------------------------------------------------------- Cash flow(1) 1,299 1,934 -33 9,386 8,453 +11 Per share diluted 1.73 2.56 -32 12.48 11.06 +13 ------------------------------------------------------------------------- Operating earnings(1) 449 849 -47 4,405 4,100 +7 Per share diluted 0.60 1.12 -46 5.86 5.36 +9 ------------------------------------------------------------------------- Net earnings 1,077 1,082 - 5,944 3,959 +50 Per share diluted 1.43 1.43 - 7.91 5.18 +53 ------------------------------------------------------------------------- Capital investment 1,925 1,805 +7 7,080 6,035 +17 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Earnings Reconciliation Summary - Total Consolidated ------------------------------------------------------------------------- Net earnings 1,077 1,082 - 5,944 3,959 +50 Add back (losses) & deduct gains: Unrealized mark-to-market hedging gain (loss), after-tax 747 (366) 1,818 (811) Non-operating foreign exchange gain (loss), after-tax (119) 267 (378) 217 Gain on discontinuance, after-tax - 68 99 152 Future tax recovery due to tax rate reductions - 264 - 301 ------------------------------------------------------------------------- Operating earnings(1) 449 849 -47 4,405 4,100 +7 Per share diluted 0.60 1.12 -46 5.86 5.36 +9 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Cash flow and operating earnings are non-GAAP measures as defined in Note 1 on Page 10. ------------------------------------------------------------------------- 2008 Cash Flow Information (for the period ended December 31, $ millions) Q4 2008 ------------------------------------------------------------------------- Cash from operating activities 2,043 8,855 Deduct (Add back): Net change in other assets and liabilities 21 (262) Net change in non-cash working capital from continuing operations 723 (269) ------------------------------------------------------------------------- Cash flow(1) 1,299 9,386 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Cash flow is a non-GAAP measure as defined in Note 1 on Page 10.

Year-over-year increase in net earnings related to unrealized

mark-to-market accounting gains

EnCana's net earnings in 2008 increased more than 50 percent to $5.9 billion. Net earnings in 2008 included a $1.8 billion after-tax unrealized gain, whereas net earnings in 2007 included an $811 million after-tax unrealized loss, both due to mark-to-market accounting for hedging contracts. The large unrealized gain in 2008 resulted from a decrease in commodity prices during the second half of the year. The gain essentially reversed unrealized mark-to-market losses recognized earlier in the year when natural gas prices were rising. It is because of these dramatic mark-to-market accounting swings in net earnings that EnCana focuses on operating earnings, which excludes the unrealized mark-to-market accounting gains and losses, as a better measure of earnings performance. Operating earnings in 2008 were up 7 percent compared to 2007, reflecting stronger prices in 2008 and EnCana's 6 percent increase in daily production.

------------------------------------------------------------------------- Production & Drilling Summary - Total Consolidated ------------------------------------------------------------------------- (for the period ended December 31) Q4 Q4 % % (After royalties) 2008 2007 change 2008 2007 change ------------------------------------------------------------------------- Natural Gas production (MMcf/d) 3,858 3,722 +4 3,838 3,566 +8 ------------------------------------------------------------------------- Natural gas production per 1,000 shares (Mcf) 473 457 +4 1,873 1,720 +9 ------------------------------------------------------------------------- Oil and NGLs production (Mbbls/d) 136 136 - 134 134 - ------------------------------------------------------------------------- Oil and NGLs production per 1,000 shares (Mcfe) 100 100 - 391 388 +1 ------------------------------------------------------------------------- Total production (MMcfe/d) 4,673 4,539 +3 4,639 4,371 +6 ------------------------------------------------------------------------- Total production per 1,000 shares (Mcfe) 573 557 +3 2,264 2,108 +7 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Total Net wells drilled 1,047 1,313 -20 3,329 4,484 -26 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Natural gas production growth benefits from a 14 percent increase from key resource plays

Natural gas production averaged about 3.8 Bcf/d in 2008, an increase of 8 percent from 2007. Natural gas key resource play production increased 14 percent in 2008 compared with 2007. EnCana's production growth was led by a 21 percent increase in gas production in the U.S. mainly from East Texas, which continues to benefit from drilling and operational successes and the incremental volumes from Deep Bossier, where the company doubled its interest in late 2007. In Canada, production remained flat as increases from drilling successes in Bighorn, coalbed methane (CBM) and Cutbank Ridge offset natural declines. Total production growth more than offset a production decrease, on an annualized basis, of about 40 million cubic feet per day (MMcf/d) due to freeze-offs, pipeline outages, shut-ins and hurricanes. Production is expected to remain essentially flat in 2009.

Integrated Oil Division benefits from higher 2008 crude oil prices offset by lower refining margins

EnCana's Integrated Oil Division, which includes the company's integrated oil business venture with ConocoPhillips and production from Athabasca and Senlac, generated $375 million in operating cash flow, down 75 percent, from 2007. EnCana saw strong financial performance from its Foster Creek and Christina Lake operations, which benefited from higher heavy oil prices, up about 60 percent, and a 13 percent increase in production to 30,183 bbls/d. Operating cash flow for Foster Creek and Christina Lake nearly doubled to $421 million in 2008 compared to $213 million in 2007. The downstream operations reported a loss of $241 million in operating cash flow, a $1.3 billion decrease compared to 2007, a year with record crack spreads. Downstream operating cash flow was reduced as a result of lower refining margins and higher purchased product costs during the second half of 2008. The Wood River and Borger refineries are located in markets influenced by U.S. Mid-Continent and Chicago 3-2-1 crack spreads. In 2008 the Chicago 3-2-1 crack spread decreased 37 percent to $11.22 per bbl compared to $17.67 per bbl in 2007. The weaker refining margins were offset, somewhat, by the higher upstream pricing, which demonstrates the benefit of the company's integration strategy.

At Foster Creek steaming of Phase 1D and 1E has started and construction is nearing completion. A ramp up of production is expected to begin at the end of the first quarter in 2009. Capital costs for the expansions remain on budget. At Christina Lake construction of the Phase 1C expansion also remains on schedule and on budget.

Growth from key North American resource plays ------------------------------------------------------------------------- Daily Production Resource Play --------------------------------------- 2008 --------------------------------------- (After royalties) Full Year Q4 Q3 Q2 Q1 ------------------------------------------------------------------------- Natural gas (MMcf/d) Jonah 603 573 615 630 595 Piceance 385 377 407 383 372 East Texas 334 408 339 316 273 Fort Worth 142 143 148 137 140 Greater Sierra 220 228 228 219 205 Cutbank Ridge(1) 296 311 322 280 271 Bighorn(1) 167 165 185 170 146 CBM 304 308 309 303 298 Shallow Gas 700 683 691 712 715 ------------------------------------------------------------------------- Total natural gas (MMcf/d) 3,151 3,196 3,244 3,150 3,015 ------------------------------------------------------------------------- Oil (Mbbls/d)(3) Foster Creek 26 29 27 21 27 Christina Lake 4 6 5 4 2 Pelican Lake 22 20 22 21 24 Weyburn(2) 14 15 14 13 14 ------------------------------------------------------------------------- Total oil (Mbbls/d)(3) 66 71 67 59 67 ------------------------------------------------------------------------- Total (MMcfe/d)(1)(2) 3,548 3,621 3,648 3,506 3,417 ------------------------------------------------------------------------- % change from prior period +13.0 -0.7 +4.1 +2.6 +2.7 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Daily Production Resource Play ---------------------------------------------- 2007 2006 ---------------------------------------------- (After royalties) Full Full Year Q4 Q3 Q2 Q1 Year ------------------------------------------------------------------------- Natural gas (MMcf/d) Jonah 557 612 588 523 504 464 Piceance 348 351 354 349 334 326 East Texas 143 187 144 139 103 99 Fort Worth 124 138 128 124 106 101 Greater Sierra 211 221 220 219 186 213 Cutbank Ridge(1) 258 283 269 248 232 189 Bighorn(1) 126 136 136 122 109 97 CBM 259 283 256 245 251 194 Shallow Gas 726 727 713 729 735 739 ------------------------------------------------------------------------- Total natural gas (MMcf/d) 2,752 2,938 2,808 2,698 2,560 2,422 ------------------------------------------------------------------------- Oil (Mbbls/d)(3) Foster Creek 24 25 26 25 20 18 Christina Lake 3 2 3 3 3 3 Pelican Lake 23 24 24 23 23 24 Weyburn(2) 15 14 15 15 15 15 ------------------------------------------------------------------------- Total oil (Mbbls/d)(3) 65 65 67 65 62 60 ------------------------------------------------------------------------- Total (MMcfe/d)(1)(2) 3,141 3,327 3,210 3,088 2,926 2,782 ------------------------------------------------------------------------- % change from prior period +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 in the first quarter of 2008 to include new areas and zones that qualify for key resource play inclusion. (2) Key resource play production volumes in 2007 and 2006 were restated in the first quarter of 2008 to include Weyburn as a key resource play. (3) Totals may not add due to rounding. Drilling activity in key North American resource plays ------------------------------------------------------------------------- Net Wells Drilled --------------------------------------- 2008 Resource Play --------------------------------------- Full Year Q4 Q3 Q2 Q1 ------------------------------------------------------------------------- Natural gas Jonah 175 40 43 49 43 Piceance 328 70 94 81 83 East Texas 78 23 22 22 11 Fort Worth 83 21 21 20 21 Greater Sierra 106 14 29 27 36 Cutbank Ridge(1) 82 17 17 24 24 Bighorn(1) 64 5 11 18 30 CBM 698 359 78 10 251 Shallow Gas 1,195 383 233 83 496 ------------------------------------------------------------------------- Total gas wells 2,809 932 548 334 995 ------------------------------------------------------------------------- Oil Foster Creek 20 1 6 1 12 Christina Lake - - - - - Pelican Lake - - - - - Weyburn(2) 21 3 4 5 9 ------------------------------------------------------------------------- Total oil wells 41 4 10 6 21 ------------------------------------------------------------------------- Total(1)(2) 2,850 936 558 340 1,016 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Net Wells Drilled ---------------------------------------------- 2007 2006 Resource Play ---------------------------------------------- Full Full Year Q4 Q3 Q2 Q1 Year ------------------------------------------------------------------------- Natural gas Jonah 135 23 31 42 39 163 Piceance 286 77 72 72 65 220 East Texas 35 8 9 11 7 59 Fort Worth 75 15 17 29 14 97 Greater Sierra 109 27 27 32 23 115 Cutbank Ridge(1) 93 11 23 26 33 134 Bighorn(1) 62 6 18 10 28 58 CBM 1,079 330 323 18 408 729 Shallow Gas 1,914 649 608 241 416 1,310 ------------------------------------------------------------------------- Total gas wells 3,788 1,146 1,128 481 1,033 2,885 ------------------------------------------------------------------------- Oil Foster Creek 23 6 8 1 8 3 Christina Lake 3 - 1 2 - 1 Pelican Lake - - - - - - Weyburn(2) 37 10 9 9 9 35 ------------------------------------------------------------------------- Total oil wells 63 16 18 12 17 39 ------------------------------------------------------------------------- Total(1)(2) 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 in the first quarter of 2008 to include new areas and zones that qualify for key resource play inclusion. (2) Key resource play net wells drilled in 2007 and 2006 were restated in the first quarter of 2008 to include Weyburn as a key resource play. 2008 proved reserves Proved reserves grow 5 percent at a finding and development cost of $2.50 per Mcfe

In 2008, total proved reserves increased 5 percent to 19.7 Tcfe at an average F&D cost of $2.50 per Mcfe. EnCana added 2.5 Tcfe of proved reserves, compared to production of 1.7 Tcfe, resulting in a reserve replacement of 150 percent of 2008 production. Cutbank Ridge, Bighorn and East Texas resource plays contributed to proved reserves additions of 1.9 Tcf of natural gas. Proved reserves of 387 Bcf were added for the Deep Panuke natural gas project, for which development is well underway and first production is expected in late 2010. About 130 million bbls of oil and NGLs were added, about two-thirds at Foster Creek and Christina Lake, where there were positive reserves revisions. Despite the low-price environment at year end, these projects had no reserves writedowns, which reflects the quality of the underlying reservoirs and EnCana's strong operating performance. EnCana's thermal oil projects have about 670 million bbls of proved reserves, of which about 80 percent is undeveloped.

F&D costs for natural gas and associated liquids were approximately $2.90 per Mcfe. When the cost of acquiring non-developed land in 2008 is excluded from the calculation, F&D costs averaged $2.45 per Mcfe. Natural gas and associated liquids reserves additions were approximately 2.0 Tcfe with capital investments of $5.8 billion in 2008, compared to 2007 reserves additions of about 2.0 Tcfe with capital investments of $4.7 billion. In 2008, F&D costs for crude oil were approximately $8.35 per bbl, up from about $3.60 per bbl in 2007. Crude oil reserves additions were approximately 123 million bbls and capital investments were $1 billion in 2008, compared to 2007 reserves additions of about 233 million bbls and capital investments of $840 million.

Three-year F&D averages $2.02 per Mcfe

For the three years 2006-2008, EnCana's F&D costs averaged $2.02 per Mcfe. For natural gas and associated liquids, F&D costs averaged $2.65 per Mcfe based on reserves additions of about 5.8 Tcfe and capital investments of $15.6 billion. For the same period, F&D costs for crude oil averaged $5.30 per bbl based on reserves additions of about 555 million bbls and capital investments of $2.9 billion.

Reserves replacement cost in 2008

Reserves replacement cost for 2008 was approximately $2.60 per Mcfe, which includes divestitures of 222 Bcfe for proceeds of $800 million. EnCana's three-year (2006-2008) reserves replacement cost was approximately $2.55 per Mcfe.

All of EnCana's proved reserves are evaluated by independent qualified reserves evaluators and are presented in compliance with U.S. Securities and Exchange Commission requirements.

------------------------------------------------------------------------- 2008 Proved Reserves Reconciliation ------------------------------------------------------------------------- Natural gas Crude oil and Gas (Bcf) Natural Gas Liquids Equiv- (MMbbls) alent(1) (Bcfe) ------------------------------------------------------------------------- Canada USA Total Canada USA Total Total ------------------------------------------------------------------------- Start of 2008 7,292 6,008 13,300 868.9 58.3 927.2 18,863 ------------------------------------------------------------------------- Revisions & improved recovery 148 (166) (18) 112.8 (3.6) 109.2 638 Extensions & discoveries 1,311 655 1,966 17.0 3.8 20.8 2,091 Purchase of reserves in place 32 7 39 0.2 - 0.2 40 Sale of reserves in place (129) (75) (204) (0.9) (2.0) (2.9) (222) Production (807) (598) (1,405) (44.0) (4.9) (48.9) (1,698) ------------------------------------------------------------------------- ------------------------------------------------------------------------- End of Year 7,847 5,831 13,678 954.0 51.6 1,005.6 19,712 ------------------------------------------------------------------------- ------------------------------------------------------------------------- % Change +8 -3 +3 +10 -11 +8 +5 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Developed 4,945 3,720 8,665 334.4 33.9 368.3 10,875 Undeveloped 2,902 2,111 5,013 619.6 17.7 637.3 8,837 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Total 7,847 5,831 13,678 954.0 51.6 1,005.6 19,712 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Gas equivalency has been calculated by EnCana. See the Advisory Regarding Reserves Data and Other Oil and Gas Information accompanying this news release. ------------------------------------------------------------------------- Proved Reserves Costs ------------------------------------------------------------------------- 2008 2007 2006 3 Years ------------------------------------------------------------------------- Capital investment ($ millions) ------------------------------------------------------------------------- Finding and development 6,818 5,587 6,107 18,512 Acquisitions 580 2,708 368 3,656 ------------------------------------------------------------------------- Finding, development and acquisitions 7,398 8,295 6,475 22,168 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Reserves additions (Bcfe) Finding and development 2,729 3,386 3,064 9,179 Acquisitions 40 275 69 384 ------------------------------------------------------------------------- Finding, development and acquisitions 2,769 3,661 3,133 9,563 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Proved reserves costs ($/Mcfe) Finding and development 2.50 1.65 1.99 2.02 Finding, development and acquisitions 2.67 2.27 2.07 2.32 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- 2008 Natural Gas and Oil Prices ------------------------------------------------------------------------- Q4 Q4 % % 2008 2007 change 2008 2007 change ------------------------------------------------------------------------- Natural gas NYMEX 6.94 6.97 - 9.04 6.86 +32 EnCana realized gas price(1) 7.18 7.32 -2 7.92 7.22 +10 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Oil and NGLs WTI 59.08 90.50 -35 99.75 72.41 +38 Western Canadian Select (WCS) 39.95 56.85 -30 79.70 49.50 +61 Differential WTI/WCS 19.13 33.65 -43 20.05 22.91 -12 EnCana realized liquids price(1) 36.16 50.84 -29 71.12 47.00 +51 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 3-2-1 crack spread ($/bbl) Chicago 6.31 9.17 -31 11.22 17.67 -37 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Realized prices include the impact of financial hedging.

Price risk management

Risk management positions at December 31, 2008 are presented in Note 18 to the unaudited Interim Consolidated Financial Statements for the fourth quarter of 2008. In 2008, EnCana's commodity price risk management measures resulted in realized losses of approximately $219 million after-tax, composed of a $48 million after-tax loss on gas price and basis hedges and a $171 million after-tax loss on oil price hedges and other hedges.

Two-thirds of expected 2009 gas production hedged during first 10 months of 2009

EnCana has hedged about 2.6 Bcf/d of expected gas production through October 2009 at an average NYMEX equivalent price of $9.13 per Mcf. This price hedging strategy helps reduce uncertainty in cash flow during periods of commodity price volatility. EnCana's risk management policy targets hedging, when appropriate, of up to 50 percent of production from the upcoming year and up to 25 percent of production from the two successive years. EnCana will continue to look for opportunities in 2009 to hedge additional volumes at prices and terms consistent with the company's policy.

EnCana has also hedged 100 percent of its expected U.S. Rockies basis exposure through 2011 using a combination of downstream transportation and basis hedges, including some hedges that are based on a percentage of NYMEX prices and some hedges that move basis risk to alternative markets downstream.

Corporate developments

In May, EnCana announced a plan to split into two independent companies - one a pure-play North American unconventional natural gas company and the other a fully integrated oil company with in-situ oil properties and refineries. Preparations were undertaken in order to complete the transaction in early 2009. Uncertainty in the global financial markets caused EnCana to delay its plans until clear signs of stabilization return. In the meantime, EnCana is continuing to prepare documentation and maintain support systems in anticipation of the proposed transaction.

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 March 31, 2009 to common shareholders of record as of March 16, 2009. Based on the February 11, 2009 closing share price on the New York Stock Exchange of $43.10, this represents an annualized yield of about 3.7 percent.

Normal Course Issuer Bid

In 2008, EnCana purchased 4.8 million of its shares, or less than 1 percent, of the outstanding shares at an average price of $67.13 per share under the company's Normal Course Issuer Bid program, prior to the May announcement of EnCana's intention to split into two independent companies, at which time it suspended purchases under the NCIB. The average diluted shares for the year were 751.8 million and the shares outstanding at year end were 750.4 million. In November 2008, EnCana renewed its Normal Course Issuer Bid program. Under the renewed bid, EnCana may purchase for cancellation up to approximately 75 million of its common shares, representing approximately 10 percent of the common shares outstanding on October 31, 2008, through market purchases. Upon completion of the proposed split transaction and subject to market conditions prevailing at that time, EnCana intends to resume purchases of common shares under the program.

Financial strength

EnCana has a very strong balance sheet, with more than 80 percent of EnCana's outstanding debt comprised of long-term, fixed-rate debt with an average remaining term of more than 14 years. Long-term debt maturities in 2009 are $250 million and $200 million in 2010. At December 31, 2008, EnCana had $2.6 billion in unused committed credit facilities. EnCana targets a debt to capitalization ratio between 30 and 40 percent. At December 31, 2008, the company's debt to capitalization ratio was 28 percent and debt to adjusted EBITDA, on a trailing 12-month basis, was 0.7 times. The company expects to continue to be in the lower end of its managed ranges through 2009.

NOTE: EnCana changed its debt metric calculation to focus on long-term debt rather than net debt. This new calculation excludes the impact of fluctuations related to mark-to-market accounting. The company believes this debt to capitalization ratio, in which debt is defined as the current and long-term portions of long-term debt, provides a more conservative measure of liquidity and is a better reflection of the company's financial position.

In 2008, EnCana invested $7.1 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 venture with ConocoPhillips. Acquisitions in 2008 were $1.2 billion, mainly in the U.S., and largely due to investments in Haynesville properties. Proceeds from divestitures were $0.9 billion. Depending on market conditions in 2009, EnCana may divest between $500 million and $1 billion of assets.

------------------------------------------------------------------------- CONFERENCE CALL TODAY 11 a.m. Mountain Time (1 p.m. Eastern Time) EnCana will host a conference call today Thursday, February 12, 2009 starting at 11:00 a.m. MT (1:00 p.m. ET). To participate, please dial (800) 731-5319 (toll-free in North America) or (416) 644-3422 approximately 10 minutes prior to the conference call. An archived recording of the call will be available from approximately 2:00 p.m. MT on February 12 until midnight February 19, 2009 by dialling (877) 289-8525 or (416) 640-1917 and entering access code 21297063. 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 non-GAAP measures as follows: - Cash flow is a non-GAAP measure defined as cash from operating activities excluding net change in other assets and liabilities and net change in non-cash working capital from continuing operations, both of which are defined on the Consolidated Statement of Cash Flows, in this news release and interim financial statements. - 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 the 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. - Capitalization is a non-GAAP measure defined as debt plus shareholders' equity. Debt to capitalization and debt to adjusted EBITDA are two ratios which 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 $40 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.

RESERVES COST DEFINITIONS - Production replacement is calculated by dividing reserves additions by production in the same period. Reserves additions over a given period, in this case 2008, are calculated by summing one or more of revisions and improved recovery, extensions and discoveries, acquisitions and divestitures. Reserves replacement cost is calculated by dividing total capital invested in finding, development and acquisitions net of divestitures by reserves additions in the same period. Finding and development cost is calculated by dividing total capital invested in finding and development activities by additions to proved reserves, before acquisitions and divestitures, which is the sum of revisions, extensions and discoveries. Finding, development and acquisition cost is calculated by dividing total capital invested in finding, development and acquisition activities by additions to proved reserves, before divestitures, which is the sum of revisions, extensions, discoveries and acquisitions. Proved reserves added in 2008 included both developed and undeveloped quantities. Additions to EnCana's proved undeveloped reserves were consistent with EnCana's resource play focus. The company estimates that approximately 70 percent of its proved undeveloped reserves will be developed within the next four years. 2008 finding, development and acquisition capital includes investment in long lead time projects. EnCana uses the aforementioned metrics as indicators of relative performance, along with a number of other measures. Many performance measures exist, all measures have limitations and historical measures are not necessarily indicative of future performance.

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, debt to capitalization ratio, debt to adjusted EBITDA multiple, sustainable growth and returns, cash flow, free 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; planned expansion of in-situ oil production; anticipated crude oil and natural gas prices, including basis differentials for various regions; anticipated expansion and production at Foster Creek and Christina Lake; anticipated divestitures; the proposed corporate reorganization transaction, the timing thereof and the conditions for proceeding with the transaction; potential dividends; anticipated success of EnCana's market risk mitigation strategy; anticipated purchases pursuant to the Normal Course Issuer Bid, the timing thereof and the source of funding therefor; potential demand for natural gas; anticipated oil production in 2009 and beyond; anticipated drilling; potential capital expenditures and investment; potential oil, natural gas and NGLs production in 2009 and beyond; anticipated costs and inflationary pressures; 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 assumptions, risks and uncertainties include, among other things: volatility of and assumptions regarding oil and gas prices; assumptions based upon the company's current guidance; risks associated with the timing and the ability to obtain any necessary approvals, waivers, consents, court orders and other requirements necessary or desirable to permit or facilitate the proposed corporate reorganization transaction (including regulatory and shareholder approvals); the risk that any applicable conditions of the proposed corporate reorganization transaction may not be satisfied; 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 2009 cash flow and free cash flow for EnCana is based upon achieving average production of oil and gas for 2009 of approximately 4.6 Bcfe/d, average commodity prices for 2009 based on a WTI price of $55 - $75/bbl for oil, a NYMEX price of $5.50 - $7.50/Mcf for natural gas, an average U.S./Canadian dollar foreign exchange rate of $0.75 - $0.85, an average Chicago 3-2-1 crack spread for 2009 of $5 - $10/bbl for refining margins, and an average number of outstanding shares for EnCana of approximately 750 million. Forward-looking information respecting the rescheduling of the proposed corporate reorganization transaction is based upon the assumption that financial and other markets will stabilize. 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 news release.

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.

EnCana Corporation Interim Consolidated Financial Statements (unaudited) For the period ended December 31, 2008 (U.S. Dollars) CONSOLIDATED STATEMENT OF EARNINGS (unaudited) Three Months Ended Twelve Months Ended December 31, December 31, ($ millions, except ------------------- -------------------- per share amounts) 2008 2007 2008 2007 ------------------------------------------------------------------------- REVENUES, NET OF ROYALTIES (Note 5) $ 6,359 $ 5,875 $ 30,064 $ 21,700 EXPENSES (Note 5) Production and mineral taxes 72 63 478 291 Transportation and selling 422 352 1,704 1,264 Operating 549 632 2,475 2,278 Purchased product 2,466 2,704 11,186 8,583 Depreciation, depletion and amortization 996 1,086 4,223 3,816 Administrative 74 121 473 384 Interest, net (Note 8) 158 131 586 428 Accretion of asset retirement obligation (Note 13) 18 18 79 64 Foreign exchange (gain) loss, net (Note 9) 253 (233) 423 (164) (Gain) loss on divestitures (Note 7) 1 22 (140) (65) ------------------------------------------------------------------------- 5,009 4,896 21,487 16,879 ------------------------------------------------------------------------- NET EARNINGS BEFORE INCOME TAX 1,350 979 8,577 4,821 Income tax expense (Note 10) 273 (28) 2,633 937 ------------------------------------------------------------------------- NET EARNINGS FROM CONTINUING OPERATIONS 1,077 1,007 5,944 3,884 NET EARNINGS FROM DISCONTINUED OPERATIONS (Note 6) - 75 - 75 ------------------------------------------------------------------------- NET EARNINGS $ 1,077 $ 1,082 $ 5,944 $ 3,959 ------------------------------------------------------------------------- ------------------------------------------------------------------------- NET EARNINGS FROM CONTINUING OPERATIONS (Note 17) PER COMMON SHARE Basic $ 1.44 $ 1.34 $ 7.92 $ 5.13 Diluted $ 1.43 $ 1.33 $ 7.91 $ 5.08 ------------------------------------------------------------------------- ------------------------------------------------------------------------- NET EARNINGS PER COMMON SHARE (Note 17) Basic $ 1.44 $ 1.44 $ 7.92 $ 5.23 Diluted $ 1.43 $ 1.43 $ 7.91 $ 5.18 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying Notes to Consolidated Financial Statements. CONSOLIDATED STATEMENT OF RETAINED EARNINGS (unaudited) Twelve Months Ended December 31, -------------------- ($ millions) 2008 2007 ------------------------------------------------------------------------- RETAINED EARNINGS, BEGINNING OF YEAR $ 13,082 $ 11,344 Net Earnings 5,944 3,959 Dividends on Common Shares (1,199) (603) Charges for Normal Course Issuer Bid (Note 14) (243) (1,618) ------------------------------------------------------------------------- RETAINED EARNINGS, END OF YEAR $ 17,584 $ 13,082 ------------------------------------------------------------------------- ------------------------------------------------------------------------- CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (unaudited) Three Months Ended Twelve Months Ended December 31, December 31, ------------------- -------------------- ($ millions) 2008 2007 2008 2007 ------------------------------------------------------------------------- NET EARNINGS $ 1,077 $ 1,082 $ 5,944 $ 3,959 OTHER COMPREHENSIVE INCOME, NET OF TAX Foreign Currency Translation Adjustment (1,448) (110) (2,230) 1,688 ------------------------------------------------------------------------- COMPREHENSIVE INCOME $ (371) $ 972 $ 3,714 $ 5,647 ------------------------------------------------------------------------- ------------------------------------------------------------------------- CONSOLIDATED STATEMENT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (unaudited) Twelve Months Ended December 31, -------------------- ($ millions) 2008 2007 ------------------------------------------------------------------------- ACCUMULATED OTHER COMPREHENSIVE INCOME, BEGINNING OF YEAR $ 3,063 $ 1,375 Foreign Currency Translation Adjustment (2,230) 1,688 ------------------------------------------------------------------------- ACCUMULATED OTHER COMPREHENSIVE INCOME, END OF YEAR $ 833 $ 3,063 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying Notes to Consolidated Financial Statements. CONSOLIDATED BALANCE SHEET (unaudited) As at As at December December ($ millions) 31, 2008 31, 2007 ------------------------------------------------------------------------- ASSETS Current Assets Cash and cash equivalents $ 383 $ 553 Accounts receivable and accrued revenues 1,568 2,381 Current portion of partnership contribution receivable 313 297 Risk management (Note 18) 2,818 385 Inventories (Note 11) 520 828 ------------------------------------------------------------------------- 5,602 4,444 Property, Plant and Equipment, net (Note 5) 35,424 35,865 Investments and Other Assets 727 607 Partnership Contribution Receivable 2,834 3,147 Risk Management (Note 18) 234 18 Goodwill 2,426 2,893 ------------------------------------------------------------------------- (Note 5) $ 47,247 $ 46,974 ------------------------------------------------------------------------- ------------------------------------------------------------------------- LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities Accounts payable and accrued liabilities $ 2,871 $ 3,982 Income tax payable 424 1,150 Current portion of partnership contribution payable 306 288 Risk management (Note 18) 43 207 Current portion of long-term debt (Note 12) 250 703 ------------------------------------------------------------------------- 3,894 6,330 Long-Term Debt (Note 12) 8,755 8,840 Other Liabilities 576 242 Partnership Contribution Payable 2,857 3,163 Risk Management (Note 18) 7 29 Asset Retirement Obligation (Note 13) 1,265 1,458 Future Income Taxes 6,919 6,208 ------------------------------------------------------------------------- 24,273 26,270 ------------------------------------------------------------------------- Shareholders' Equity Share capital (Note 14) 4,557 4,479 Paid in surplus - 80 Retained earnings 17,584 13,082 Accumulated other comprehensive income 833 3,063 Total Shareholders' Equity 22,974 20,704 ------------------------------------------------------------------------- $ 47,247 $ 46,974 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying Notes to Consolidated Financial Statements. CONSOLIDATED STATEMENT OF CASH FLOWS (unaudited) Three Months Ended Twelve Months Ended December 31, December 31, ------------------- -------------------- ($ millions) 2008 2007 2008 2007 ------------------------------------------------------------------------- OPERATING ACTIVITIES Net earnings from continuing operations $ 1,077 $ 1,007 $ 5,944 $ 3,884 Depreciation, depletion and amortization 996 1,086 4,223 3,816 Future income taxes (Note 10) 155 (608) 1,646 (617) Cash tax on sale of assets (Note 10) - - 25 - Unrealized (gain) loss on risk management (Note 18) (1,090) 569 (2,729) 1,235 Unrealized foreign exchange (gain) loss 268 (52) 417 41 Accretion of asset retirement obligation (Note 13) 18 18 79 64 (Gain) loss on divestitures (Note 7) 1 22 (140) (65) Other (126) (108) (79) 95 Net change in other assets and liabilities 21 (21) (262) (16) Net change in non-cash working capital from continuing operations 723 280 (269) (8) ------------------------------------------------------------------------- Cash From Operating Activities 2,043 2,193 8,855 8,429 ------------------------------------------------------------------------- INVESTING ACTIVITIES Capital expenditures (Note 5) (1,885) (4,408) (8,254) (8,737) Proceeds from divestitures (Note 7) 311 (24) 904 481 Cash tax on sale of assets (Note 10) - - (25) - Net change in investments and other (101) (31) (267) (5) Net change in non-cash working capital from continuing operations 18 120 89 86 ------------------------------------------------------------------------- Cash (Used in) Investing Activities (1,657) (4,343) (7,553) (8,175) ------------------------------------------------------------------------- FINANCING ACTIVITIES Net issuance (repayment) of revolving long-term debt (304) 1,090 (53) 181 Issuance of long-term debt (Note 12) - 1,485 723 2,409 Repayment of long-term debt - (257) (664) (257) Issuance of common shares (Note 14) 2 18 80 176 Purchase of common shares (Note 14) - - (326) (2,025) Dividends on common shares (300) (150) (1,199) (603) Other - 1 - - ------------------------------------------------------------------------- Cash From (Used in) Financing Activities (602) 2,187 (1,439) (119) ------------------------------------------------------------------------- FOREIGN EXCHANGE GAIN (LOSS) ON CASH AND CASH EQUIVALENTS HELD IN FOREIGN CURRENCY (23) 1 (33) 16 ------------------------------------------------------------------------- INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (239) 38 (170) 151 CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 622 515 553 402 ------------------------------------------------------------------------- CASH AND CASH EQUIVALENTS, END OF PERIOD $ 383 $ 553 $ 383 $ 553 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 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 the exploration for, the development of, and the 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 cost 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 18). 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 15). 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 February 2008, the CICA's Accounting Standards Board confirmed that International Financial Reporting Standards ("IFRS") will replace Canadian generally accepted accounting principles in 2011 for profit- oriented Canadian publicly accountable enterprises. EnCana will be required to report its results in accordance with IFRS beginning in 2011. The Company has developed a changeover plan to complete the transition to IFRS by January 1, 2011, including the preparation of required comparative information. The key elements of EnCana's changeover plan include: - determine appropriate changes to accounting policies and required amendments to financial disclosures; - identify and implement changes in associated processes and information systems; - comply with internal control requirements; - communicate collateral impacts to internal business groups; and - educate and train internal and external stakeholders. The Company is currently analyzing accounting policy alternatives and identifying implementation options for the corresponding process changes. EnCana will update its IFRS changeover plan to reflect new and amended accounting standards issued by the International Accounting Standards Board. As IFRS is expected to change prior to 2011, the impact of IFRS on the Company's consolidated financial statements is not reasonably determinable at this time. 4. PROPOSED CORPORATE REORGANIZATION On May 11, 2008, EnCana announced its plans to split into two independent 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 various natural gas and crude oil resource plays. The proposed corporate reorganization (the "Arrangement") would be implemented through a court approved Plan of Arrangement and is subject to shareholder approval. The Arrangement would result in two publicly traded entities with the names of Cenovus Energy Inc.("Cenovus") and EnCana Corporation. Each EnCana shareholder would receive one share of each entity in exchange for each EnCana Common Share held. On October 15, 2008, EnCana announced the proposed Arrangement would be delayed until the global debt and equity markets regain stability. 5. SEGMENTED INFORMATION The Company's reportable segments are as follows: - Canada includes the Company's exploration for, and development and production of natural gas, crude oil and NGLs and other related activities within the Canadian cost centre. - USA includes the Company's exploration for, and development and production of natural gas, NGLs and other related activities within the United States cost centre. - Downstream Refining is focused on the refining of crude oil into petroleum and chemical products at two refineries located in the United States. The refineries are jointly owned with ConocoPhillips. - Market Optimization is primarily responsible for the sale of the Company's proprietary production. These results are included in the Canada and USA segments. Market optimization activities include 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 and Other mainly 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 segments are based on market values and eliminated on consolidation. The tables in this note present financial information on an after eliminations basis. EnCana has updated its segmented reporting to present the upstream Canadian and United States cost centres and Downstream Refining as separate reportable segments. This results in EnCana presenting the Canadian portion of the Integrated Oil Division as part of the Canada segment. Previously, this was aggregated and presented in the Integrated Oil segment. Prior periods have been restated to reflect the new presentation. EnCana has a decentralized decision making and reporting structure. Accordingly, the Company is organized into Divisions as follows: - Canadian Plains Division includes natural gas production and crude oil development and production assets located in eastern Alberta and Saskatchewan. - Canadian Foothills Division includes natural gas development and production assets located in western Alberta and British Columbia as well as the Company's Canadian offshore assets. - USA Division includes the assets located in the United States and comprises the USA segment described above. - Integrated Oil Division is the combined total of Integrated Oil - Canada and Downstream Refining. Integrated Oil - Canada includes the Company's exploration for, and development and production of bitumen using in-situ recovery methods. Integrated Oil - Canada is composed of EnCana's interests in the FCCL Oil Sands Partnership jointly owned with ConocoPhillips, the Athabasca natural gas assets and other bitumen interests. Operations that have been discontinued are disclosed in Note 6. Results of Continuing Operations (For the three months ended December 31) Segment and Geographic Information Downstream Canada USA Refining ------------------------------------------------------------------------- 2008 2007 2008 2007 2008 2007 ------------------------------------------------------------------------- Revenues, Net of Royalties $ 1,961 $ 2,220 $ 1,273 $ 1,178 $ 1,497 $ 2,206 Expenses Production and mineral taxes 13 16 59 47 - - Transportation and selling 287 265 135 87 - - Operating 280 338 136 154 117 111 Purchased product (25) (27) - - 1,960 1,915 ------------------------------------------------------------------------- 1,406 1,628 943 890 (580) 180 Depreciation, depletion and amortization 481 634 438 330 50 44 ------------------------------------------------------------------------- Segment Income (Loss) $ 925 $ 994 $ 505 $ 560 $ (630) $ 136 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Market Corporate Optimization & Other Consolidated ------------------------------------------------------------------------- 2008 2007 2008 2007 2008 2007 ------------------------------------------------------------------------- Revenues, Net of Royalties $ 543 $ 837 $ 1,085 $ (566) $ 6,359 $ 5,875 Expenses Production and mineral taxes - - - - 72 63 Transportation and selling - - - - 422 352 Operating 18 9 (2) 20 549 632 Purchased product 531 816 - - 2,466 2,704 ------------------------------------------------------------------------- (6) 12 1,087 (586) 2,850 2,124 Depreciation, depletion and amortization 3 6 24 72 996 1,086 ------------------------------------------------------------------------- Segment Income (Loss) $ (9) $ 6 $ 1,063 $ (658) $ 1,854 $ 1,038 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Administrative 74 121 Interest, net 158 131 Accretion of asset retirement obligation 18 18 Foreign exchange (gain) loss, net 253 (233) (Gain) loss on divestitures 1 22 ------------------------------------------------------------------------- 504 59 ------------------------------------------------------------------------- Net Earnings Before Income Tax 1,350 979 Income tax expense 273 (28) ------------------------------------------------------------------------- Net Earnings From Continuing Operations $ 1,077 $ 1,007 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Results of Continuing Operations (For the three months ended December 31) Product and Divisional Information Canada Segment ------------------------------------------------------------------------- Canadian Canadian Integrated Plains Foothills Oil - Canada Total ------------------------------------------------------------------------- 2008 2007 2008 2007 2008 2007 2008 2007 ------------------------------------------------------------------------- Revenues, Net of Royalties $ 789 $ 964 $ 923 $1,017 $ 249 $ 239 $1,961 $2,220 Expenses Production and mineral taxes 10 11 3 5 - - 13 16 Transportation and selling 62 97 72 52 153 116 287 265 Operating 99 128 131 152 50 58 280 338 Purchased product - - - - (25) (27) (25) (27) ------------------------------------------------------------------------- Operating Cash Flow $ 618 $ 728 $ 717 $ 808 $ 71 $ 92 $1,406 $1,628 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Canadian Plains Division ------------------------------------------------------------------------- Gas Oil & NGLs Other Total ------------------------------------------------------------------------- 2008 2007 2008 2007 2008 2007 2008 2007 ------------------------------------------------------------------------- Revenues, Net of Royalties $ 506 $ 567 $ 280 $ 393 $ 3 $ 4 $ 789 $ 964 Expenses Production and mineral taxes 4 3 6 8 - - 10 11 Transportation and selling 16 21 46 76 - - 62 97 Operating 50 65 48 62 1 1 99 128 ------------------------------------------------------------------------- Operating Cash Flow $ 436 $ 478 $ 180 $ 247 $ 2 $ 3 $ 618 $ 728 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Canadian Foothills Division ------------------------------------------------------------------------- Gas Oil & NGLs Other Total ------------------------------------------------------------------------- 2008 2007 2008 2007 2008 2007 2008 2007 ------------------------------------------------------------------------- Revenues, Net of Royalties $ 829 $ 880 $ 84 $ 122 $ 10 $ 15 $ 923 $1,017 Expenses Production and mineral taxes 2 4 1 1 - - 3 5 Transportation and selling 43 50 3 2 26 - 72 52 Operating 117 137 9 10 5 5 131 152 ------------------------------------------------------------------------- Operating Cash Flow $ 667 $ 689 $ 71 $ 109 $ (21)$ 10 $ 717 $ 808 ------------------------------------------------------------------------- ------------------------------------------------------------------------- USA Division ------------------------------------------------------------------------- Gas Oil & NGLs Other Total ------------------------------------------------------------------------- 2008 2007 2008 2007 2008 2007 2008 2007 ------------------------------------------------------------------------- Revenues, Net of Royalties $1,180 $1,011 $ 54 $ 99 $ 39 $ 68 $1,273 $1,178 Expenses Production and mineral taxes 54 40 5 7 - - 59 47 Transportation and selling 135 87 - - - - 135 87 Operating 86 95 - - 50 59 136 154 ------------------------------------------------------------------------- Operating Cash Flow $ 905 $ 789 $ 49 $ 92 $ (11)$ 9 $ 943 $ 890 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Integrated Oil Division ------------------------------------------------------------------------- Downstream Oil* Refining Other* Total ------------------------------------------------------------------------- 2008 2007 2008 2007 2008 2007 2008 2007 ------------------------------------------------------------------------- Revenues, Net of Royalties $ 219 $ 186 $1,497 $2,206 $ 30 $ 53 $1,746 $2,445 Expenses Production and mineral taxes - - - - - - - - Transportation and selling 146 108 - - 7 8 153 116 Operating 37 36 117 111 13 22 167 169 Purchased product - - 1,960 1,915 (25) (27) 1,935 1,888 ------------------------------------------------------------------------- Operating Cash Flow $ 36 $ 42 $ (580)$ 180 $ 35 $ 50 $ (509)$ 272 ------------------------------------------------------------------------- ------------------------------------------------------------------------- *Oil and Other comprise Integrated Oil - Canada. Other includes production of natural gas and bitumen from the Athabasca and Senlac properties. Results of Continuing Operations (For the twelve months ended December 31) Segment and Geographic Information Downstream Canada USA Refining ------------------------------------------------------------------------- 2008 2007 2008 2007 2008 2007 ------------------------------------------------------------------------- Revenues, Net of Royalties $ 10,050 $ 8,308 $ 5,629 $ 4,372 $ 9,011 $ 7,315 Expenses Production and mineral taxes 108 102 370 189 - - Transportation and selling 1,202 947 502 307 - - Operating 1,333 1,204 618 595 492 428 Purchased product (151) (88) - - 8,760 5,813 ------------------------------------------------------------------------- 7,558 6,143 4,139 3,281 (241) 1,074 Depreciation, depletion and amortization 2,198 2,298 1,691 1,181 188 159 ------------------------------------------------------------------------- Segment Income (Loss) $ 5,360 $ 3,845 $ 2,448 $ 2,100 $ (429)$ 915 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Market Corporate Optimization & Other Consolidated ------------------------------------------------------------------------- 2008 2007 2008 2007 2008 2007 ------------------------------------------------------------------------- Revenues, Net of Royalties $ 2,655 $ 2,944 $ 2,719 $ (1,239)$ 30,064 $ 21,700 Expenses Production and mineral taxes - - - - 478 291 Transportation and selling - 10 - - 1,704 1,264 Operating 45 37 (13) 14 2,475 2,278 Purchased product 2,577 2,858 - - 11,186 8,583 ------------------------------------------------------------------------- 33 39 2,732 (1,253) 14,221 9,284 Depreciation, depletion and amortization 15 17 131 161 4,223 3,816 ------------------------------------------------------------------------- Segment Income (Loss) $ 18 $ 22 $ 2,601 $ (1,414) 9,998 5,468 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Administrative 473 384 Interest, net 586 428 Accretion of asset retirement obligation 79 64 Foreign exchange (gain) loss, net 423 (164) (Gain) loss on divestitures (140) (65) ------------------------------------------------------------------------- 1,421 647 ------------------------------------------------------------------------- Net Earnings Before Income Tax 8,577 4,821 Income tax expense 2,633 937 ------------------------------------------------------------------------- Net Earnings From Continuing Operations $ 5,944 $ 3,884 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Results of Continuing Operations (For the twelve months ended December 31) Product and Divisional Information Canada Segment ------------------------------------------------------------------------- Canadian Canadian Integrated Plains Foothills Oil - Canada Total ------------------------------------------------------------------------- 2008 2007 2008 2007 2008 2007 2008 2007 ------------------------------------------------------------------------- Revenues, Net of Royalties $4,418 $3,652 $4,355 $3,679 $1,277 $ 977 $10,050 $8,308 Expenses Production and mineral taxes 74 63 33 39 1 - 108 102 Transportation and selling 392 345 239 201 571 401 1,202 947 Operating 484 440 609 535 240 229 1,333 1,204 Purchased product - - - - (151) (88) (151) (88) ------------------------------------------------------------------------- Operating Cash Flow $3,468 $2,804 $3,474 $2,904 $ 616 $ 435 $7,558 $6,143 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Canadian Plains Division ------------------------------------------------------------------------- Gas Oil & NGLs Other Total ------------------------------------------------------------------------- 2008 2007 2008 2007 2008 2007 2008 2007 ------------------------------------------------------------------------- Revenues, Net of Royalties $2,301 $2,186 $2,106 $1,453 $ 11 $ 13 $4,418 $3,652 Expenses Production and mineral taxes 36 34 38 29 - - 74 63 Transportation and selling 71 82 321 263 - - 392 345 Operating 241 221 239 215 4 4 484 440 ------------------------------------------------------------------------- Operating Cash Flow $1,953 $1,849 $1,508 $ 946 $ 7 $ 9 $3,468 $2,804 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Canadian Foothills Division ------------------------------------------------------------------------- Gas Oil & NGLs Other Total ------------------------------------------------------------------------- 2008 2007 2008 2007 2008 2007 2008 2007 ------------------------------------------------------------------------- Revenues, Net of Royalties $3,720 $3,232 $ 578 $ 390 $ 57 $ 57 $4,355 $3,679 Expenses Production and mineral taxes 28 36 5 3 - - 33 39 Transportation and selling 201 192 12 9 26 - 239 201 Operating 549 482 39 33 21 20 609 535 ------------------------------------------------------------------------- Operating Cash Flow $2,942 $2,522 $ 522 $ 345 $ 10 $ 37 $3,474 $2,904 ------------------------------------------------------------------------- ------------------------------------------------------------------------- USA Division ------------------------------------------------------------------------- Gas Oil & NGLs Other Total ------------------------------------------------------------------------- 2008 2007 2008 2007 2008 2007 2008 2007 ------------------------------------------------------------------------- Revenues, Net of Royalties $4,934 $3,765 $ 407 $ 309 $ 288 $ 298 $5,629 $4,372 Expenses Production and mineral taxes 334 167 36 22 - - 370 189 Transportation and selling 502 307 - - - - 502 307 Operating 352 323 - - 266 272 618 595 ------------------------------------------------------------------------- Operating Cash Flow $3,746 $2,968 $ 371 $ 287 $ 22 $ 26 $4,139 $3,281 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Integrated Oil Division ------------------------------------------------------------------------- Downstream Oil* Refining Other* Total ------------------------------------------------------------------------- 2008 2007 2008 2007 2008 2007 2008 2007 ------------------------------------------------------------------------- Revenues, Net of Royalties $1,117 $ 738 $9,011 $7,315 $ 160 $ 239 $10,288 $8,292 Expenses Production and mineral taxes - - - - 1 - 1 - Transportation and selling 526 366 - - 45 35 571 401 Operating 170 159 492 428 70 70 732 657 Purchased product - - 8,760 5,813 (151) (88) 8,609 5,725 ------------------------------------------------------------------------- Operating Cash Flow $ 421 $ 213 $ (241)$1,074 $ 195 $ 222 $ 375 $1,509 ------------------------------------------------------------------------- ------------------------------------------------------------------------- *Oil and Other comprise Integrated Oil - Canada. Other includes production of natural gas and bitumen from the Athabasca and Senlac properties. Capital Expenditures (Continuing Operations) Three Months Ended Twelve Months Ended December 31, December 31, ------------------------------------------- 2008 2007 2008 2007 ------------------------------------------------------------------------- Capital Canadian Plains $ 254 $ 288 $ 847 $ 846 Canadian Foothills 463 625 2,299 2,439 Integrated Oil - Canada 162 194 656 451 ------------------------------------------------------------------------- Canada 879 1,107 3,802 3,736 USA 815 606 2,615 1,919 Downstream Refining 168 53 478 220 Market Optimization 6 1 17 6 Corporate & Other 57 38 168 154 ------------------------------------------------------------------------- 1,925 1,805 7,080 6,035 ------------------------------------------------------------------------- Acquisition Capital Canadian Foothills 31 8 151 75 Integrated Oil - Canada - - - 14 ------------------------------------------------------------------------- Canada 31 8 151 89 USA (71) 2,595 1,023 2,613 ------------------------------------------------------------------------- (40) 2,603 1,174 2,702 ------------------------------------------------------------------------- Total $ 1,885 $ 4,408 $ 8,254 $ 8,737 ------------------------------------------------------------------------- ------------------------------------------------------------------------- On September 25, 2008, EnCana acquired certain land and property in Louisiana for approximately $101 million before closing adjustments. The purchase was facilitated by an unrelated party, Brown Haynesville Leasehold LLC ("Brown Haynesville"), which holds the majority of the assets in trust for the Company in anticipation of a qualifying like kind exchange for U.S. tax purposes. On July 23, 2008, EnCana acquired certain land and mineral interests in Louisiana for approximately $457 million before closing adjustments. The purchase was facilitated by an unrelated party, Brown Southwest Minerals LLC ("Brown Southwest"), which holds the majority of the assets in trust for the Company in anticipation of a qualifying like kind exchange for U.S. tax purposes. On November 12, 2008, an unrelated party exercised an option to purchase certain interests as part of the above acquisition for approximately $157 million, reducing the qualifying like kind exchange to approximately $300 million. Pursuant to the agreements with Brown Haynesville and Brown Southwest, EnCana operates the properties, receives all the revenue and pays all of the expenses associated with the properties. The arrangements with Brown Haynesville and Brown Southwest will be completed on March 24, 2009 and January 19, 2009 respectively and the assets will be transferred to EnCana at that time. EnCana has determined that each relationship with Brown Haynesville and Brown Southwest represents an interest in a Variable Interest Entity("VIE") and that EnCana is the primary beneficiary of the VIE. EnCana has consolidated Brown Haynesville and Brown Southwest from the dates of acquisition. 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 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 ------------------------------------------------ December December December December 31, 2008 31, 2007 31, 2008 31, 2007 ------------------------------------------------------------------------- Canada $ 17,105 $ 19,519 $ 23,441 $ 27,014 USA 13,541 11,879 14,635 12,948 Downstream Refining 4,032 3,706 4,637 4,887 Market Optimization 140 171 429 478 Corporate & Other 606 590 4,105 1,647 ------------------------------------------------------------------------- Total $ 35,424 $ 35,865 $ 47,247 $ 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 December 31, 2008, Corporate and Other Property, Plant and Equipment and Total Assets includes EnCana's accrual to date of $252 million (2007 - $147 million) 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 December 31, 2008, Canada Property, Plant, and Equipment and Total Assets includes EnCana's accrual to date of $199 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. DISCONTINUED OPERATIONS Midstream The $75 million gain on discontinuance in 2007 was the result of an expired clause included in the December 2005 sale of the Company's Midstream natural gas liquids processing operations. The clause provided potential market price support for the facilities and was accrued for in 2005. 7. DIVESTITURES Proceeds received on the sale of assets and investments were $904 million (2007 - $481 million). The significant items are described below. Canada In 2008, the Company completed the divestiture of mature conventional oil and natural gas assets for proceeds of $39 million (2007 - nil) in Canadian Plains and $400 million (2007 - $213 million) in Canadian Foothills. 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 the Canadian cost centre and reported in Canadian Foothills. USA In 2008, the Company completed the divestiture of mature conventional natural gas assets for proceeds of $251 million (2007 - $10 million). Corporate and Other In September 2008, the Company completed the sale of its interests in Brazil for net proceeds of $164 million, before closing ajdustments, resulting in a gain on sale of $124 million. After recording income tax of $25 million, EnCana recorded an after-tax gain of $99 million. In August 2007, the Company closed the sale of its Australia assets for proceeds of $31 million resulting in a gain on sale of $30 million. After recording income tax of $5 million, EnCana recorded an after-tax gain of $25 million. In 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. In January 2007, the Company completed the sale of its interests in Chad, properties that were in the pre-production stage, for proceeds of $208 million which resulted in a gain on sale of $59 million. 8. INTEREST, NET Three Months Ended Twelve Months Ended December 31, December 31, --------------------------------------------- 2008 2007 2008 2007 ------------------------------------------------------------------------- Interest Expense - Long-Term Debt $ 130 $ 129 $ 556 $ 460 Interest Expense - Other* 80 66 246 244 Interest Income* (52) (64) (216) (276) ------------------------------------------------------------------------- $ 158 $ 131 $ 586 $ 428 ------------------------------------------------------------------------- ------------------------------------------------------------------------- *Interest Expense - Other and Interest Income are primarily due to the Partnership Contribution Payable and Receivable, respectively. 9. FOREIGN EXCHANGE (GAIN) LOSS, NET Three Months Ended Twelve Months Ended December 31, December 31, --------------------------------------------- 2008 2007 2008 2007 ------------------------------------------------------------------------- Unrealized Foreign Exchange (Gain) Loss on: Translation of U.S. dollar debt issued from Canada $ 663 $ (75) $ 1,033 $ (683) Translation of U.S. dollar partnership contribution receivable issued from Canada (390) 22 (608) 617 Other Foreign Exchange (Gain) Loss (20) (180) (2) (98) ------------------------------------------------------------------------- $ 253 $ (233) $ 423 $ (164) ------------------------------------------------------------------------- ------------------------------------------------------------------------- 10. INCOME TAXES The provision for income taxes is as follows: Three Months Ended Twelve Months Ended December 31, December 31, --------------------------------------------- 2008 2007 2008 2007 ------------------------------------------------------------------------- Current Canada $ 102 $ 415 $ 548 $ 900 United States 11 163 396 647 Other Countries 5 2 43 7 ------------------------------------------------------------------------- Total Current Tax 118 580 987 1,554 ------------------------------------------------------------------------- Future 155 (344) 1,646 (316) Future Tax Rate Reductions - (264) - (301) ------------------------------------------------------------------------- $ 273 $ (28) $ 2,633 $ 937 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Included in current tax for 2008 is $25 million related to the sale of assets in Brazil (2007 - nil). The following table reconciles income taxes calculated at the Canadian statutory rate with the actual income taxes: Three Months Ended Twelve Months Ended December 31, December 31, --------------------------------------------- 2008 2007 2008 2007 ------------------------------------------------------------------------- Net Earnings Before Income Tax $ 1,350 $ 979 $ 8,577 $ 4,821 Canadian Statutory Rate 29.7% 32.3% 29.7% 32.3% ------------------------------------------------------------------------- Expected Income Tax 400 316 2,544 1,557 Effect on Taxes Resulting from: Statutory and other rate differences (30) 40 167 76 Effect of tax rate changes* - (264) - (301) Effect of legislative changes - 52 - (179) Non-taxable downstream partnership (income) loss 16 (30) 6 (70) International financing (76) (17) (309) (62) Foreign exchange (gains) losses not included in net earnings (92) - 49 - Non-taxable capital (gains) losses 54 (80) 84 (124) Other 1 (45) 92 40 ------------------------------------------------------------------------- $ 273 $ (28) $ 2,633 $ 937 ------------------------------------------------------------------------- Effective Tax Rate 20.2% (2.9%) 30.7% 19.4% ------------------------------------------------------------------------- ------------------------------------------------------------------------- *The Canadian federal government, during the second quarter of 2007, enacted income tax rate changes. 11. INVENTORIES As at As at December December 31, 2008 31, 2007 ------------------------------------------------------------------------- Product Canada $ 46 $ 65 USA 8 2 Downstream Refining 323 570 Market Optimization 127 180 Parts and Supplies 16 11 ------------------------------------------------------------------------- $ 520 $ 828 ------------------------------------------------------------------------- ------------------------------------------------------------------------- As a result of a significant decline in commodity prices in the latter half of 2008, EnCana has written down its product inventory by $152 million from cost to net realizable value. The total amount of inventories recognized as an expense during the year, including the write-down, was $8,749 million (2007 - $5,752 million). 12. LONG-TERM DEBT As at As at December December 31, 2008 31, 2007 ------------------------------------------------------------------------- Canadian Dollar Denominated Debt Revolving credit and term loan borrowings $ 1,410 $ 1,506 Unsecured notes 1,020 1,138 ------------------------------------------------------------------------- 2,430 2,644 ------------------------------------------------------------------------- U.S. Dollar Denominated Debt Revolving credit and term loan borrowings 247 495 Unsecured notes 6,350 6,421 ------------------------------------------------------------------------- 6,597 6,916 ------------------------------------------------------------------------- Increase in Value of Debt Acquired* 49 66 Debt Discounts and Financing Costs (71) (83) Current Portion of Long-Term Debt (250) (703) ------------------------------------------------------------------------- $ 8,755 $ 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. 13. 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 December December 31, 2008 31, 2007 ------------------------------------------------------------------------- Asset Retirement Obligation, Beginning of Year $ 1,458 $ 1,051 Liabilities Incurred 54 89 Liabilities Settled (115) (100) Liabilities Divested (38) - Change in Estimated Future Cash Flows 54 184 Accretion Expense 79 64 Foreign Currency Translation (227) 163 Other - 7 ------------------------------------------------------------------------- Asset Retirement Obligation, End of Year $ 1,265 $ 1,458 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 14. SHARE CAPITAL December 31, 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 3.0 80 8.3 176 Stock-Based Compensation - 11 - 17 Common Shares Purchased (2.8) (13) (36.0) (301) ------------------------------------------------------------------------- Common Shares Outstanding, End of Year 750.4 $ 4,557 750.2 $ 4,479 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Normal Course Issuer Bid EnCana has received regulatory approval each year under Canadian securities laws to purchase Common Shares under seven consecutive Normal Course Issuer Bids ("Bids"). EnCana is entitled to purchase, for cancellation, up to approximately 75.0 million Common Shares under the renewed Bid which commenced on November 13, 2008 and terminates on November 12, 2009. In 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, valued at $16 million, from the EnCana Employee Benefit Plan Trust that vested under EnCana's Performance Share Unit Plan (See Note 16). For these Common Shares distributed, there was a $54 million adjustment to Retained earnings with a reduction to Paid in surplus of $70 million. In 2007, the Company purchased 38.9 million Common Shares for total consideration of approximately $2,025 million. Of the amount paid, $325 million was charged to Share capital and $1,700 million was charged to Retained earnings. Included in the Common Shares Purchased in 2007 are 2.9 million Common Shares distributed, valued at $24 million, from the EnCana Employee Benefit Plan Trust that vested under EnCana's Performance Share Unit Plan (See Note 16). For these Common Shares distributed, there was an $82 million adjustment to Retained earnings with a reduction to Paid in surplus of $106 million. Stock Options EnCana has stock-based compensation plans that allow employees to purchase Common Shares of the Company. Option exercise prices approximate the market price for the Common Shares on the date the options were granted. Options granted under the plans are generally fully exercisable after three years and expire five years after the date granted. Options granted under predecessor and/or related company replacement plans expire up to 10 years from the date the options were granted. The following tables summarize the information related to options to purchase Common Shares that do not have Tandem Share Appreciation Rights ("TSARs") attached to them at December 31, 2008. Information related to TSARs is included in Note 16. Weighted Stock Average Options Exercise (millions) Price (C$) ------------------------------------------------------------------------- Outstanding, Beginning of Year 3.4 21.82 Exercised (2.9) 23.68 ------------------------------------------------------------------------- Outstanding, End of Year 0.5 11.62 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Exercisable, End of Year 0.5 11.62 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Outstanding Options Exercisable Options ----------------------------------------------------------- Weighted Number of Average Weighted Number of Weighted Options Remaining Average Options Average Outstanding Contractual Exercise Outstanding Exercise (millions) Life (years) Price (C$) (millions) Price (C$) Range of Exercise Price (C$) ------------------------------------------------------------------------- 11.00 to 14.50 0.5 0.9 11.62 0.5 11.62 ------------------------------------------------------------------------- ------------------------------------------------------------------------- At December 31, 2007, the balance in Paid in surplus related to stock-based compensation programs. 15. 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 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 Debt to Capitalization and Debt to Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization ("EBITDA"). These metrics are used to steward the Company's overall debt position as measures of the Company's overall financial strength. To provide a more conservative measure of liquidity, the Company has changed its calculation of these metrics as follows: Net Debt to Capitalization has been changed to Debt to Capitalization and Net Debt to Adjusted EBITDA has been changed to Debt to Adjusted EBITDA. Debt is defined as the current and long-term portions of Long-Term Debt. Previously, Net Debt was defined as Long-Term Debt plus Current Liabilities less Current Assets. The Company believes this presentation is more comparable between periods by excluding the impact of unrealized mark-to-market accounting gains and losses on working capital. EnCana targets a Debt to Capitalization ratio of between 30 and 40 percent. At December 31, 2008, EnCana's Debt to Capitalization ratio was 28 percent (December 31, 2007 - 32 percent) calculated as follows: As at -------------------------- December 31, December 31, 2008 2007 ------------------------------------------------------------------------- Debt $ 9,005 $ 9,543 Total Shareholders' Equity 22,974 20,704 ------------------------------------------------------------------------- Total Capitalization $ 31,979 $ 30,247 ------------------------------------------------------------------------- Debt to Capitalization ratio 28% 32% ------------------------------------------------------------------------- ------------------------------------------------------------------------- Without giving effect to the change in calculation as described above, EnCana's Net Debt to Capitalization ratio would have been 23 percent at December 31, 2008 (December 31, 2007 - 34 percent). EnCana targets a Debt to Adjusted EBITDA of 1.0 to 2.0 times. At December 31, 2008, Debt to Adjusted EBITDA was 0.7x (December 31, 2007 - 1.1x) calculated on a trailing twelve-month basis as follows: As at -------------------------- December 31, December 31, 2008 2007 ------------------------------------------------------------------------- Debt $ 9,005 $ 9,543 ------------------------------------------------------------------------- Net Earnings from Continuing Operations $ 5,944 $ 3,884 Add (deduct): Interest, net 586 428 Income tax expense 2,633 937 Depreciation, depletion and amortization 4,223 3,816 Accretion of asset retirement obligation 79 64 Foreign exchange (gain) loss, net 423 (164) (Gain) loss on divestitures (140) (65) ------------------------------------------------------------------------- Adjusted EBITDA $ 13,748 $ 8,900 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Debt to Adjusted EBITDA 0.7x 1.1x ------------------------------------------------------------------------- ------------------------------------------------------------------------- Without giving effect to the change in calculation as described above, EnCana's Net Debt to Adjusted EBITDA would have been 0.5x at December 31, 2008 (December 31, 2007 - 1.2x). EnCana has a long-standing practice of maintaining capital discipline, managing its capital structure and adjusting its capital structure 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, except as noted above. EnCana is subject to certain financial covenants in its credit facility agreements and is in compliance with all financial covenants. 16. COMPENSATION PLANS The tables below outline certain information related to EnCana's compensation plans at December 31, 2008. Additional information is contained in Note 17 of the Company's annual audited Consolidated Financial Statements for the year ended December 31, 2007. A) Pensions The following table summarizes the net benefit plan expense: Three Months Ended Twelve Months Ended December 31, December 31, --------------------------------------------- 2008 2007 2008 2007 ------------------------------------------------------------------------- Current Service Cost $ 3 $ 5 $ 15 $ 16 Interest Cost 5 5 21 19 Expected Return on Plan Assets (5) (5) (19) (19) Amortization of Net Actuarial Losses 1 1 4 4 Expected Amortization of Past Service Costs 1 1 2 2 Amortization of Transitional Obligation (1) (1) (2) (2) Expense for Defined Contribution Plan 14 9 44 34 ------------------------------------------------------------------------- Net Benefit Plan Expense $ 18 $ 15 $ 65 $ 54 ------------------------------------------------------------------------- ------------------------------------------------------------------------- For the year ended December 31, 2008, contributions of $8 million have been made to the defined benefit pension plans (2007 - $8 million). B) Tandem Share Appreciation Rights ("TSARs") The following table summarizes the information related to the TSARs at December 31, 2008: Weighted Outstanding Average TSARs Exercise Price ------------------------------------------------------------------------- Canadian Dollar Denominated (C$) Outstanding, Beginning of Year 18,854,141 48.44 Granted 4,420,272 70.11 Exercised - SARs (3,173,443) 43.68 Exercised - Options (82,936) 42.00 Forfeited (606,095) 55.27 ------------------------------------------------------------------------- Outstanding, End of Year 19,411,939 53.97 ------------------------------------------------------------------------- Exercisable, End of Year 8,452,111 46.45 ------------------------------------------------------------------------- ------------------------------------------------------------------------- For the year ended December 31, 2008, EnCana recorded a reduction of compensation costs of $47 million related to the outstanding TSARs (2007 - costs of $225 million). C) Performance Tandem Share Appreciation Rights ("Performance TSARs") The following table summarizes the information related to the Performance TSARs at December 31, 2008: Weighted Average Outstanding Exercise TSARs Price ------------------------------------------------------------------------- Canadian Dollar Denominated (C$) Outstanding, Beginning of Year 6,930,925 56.09 Granted 7,058,538 69.40 Exercised - SARs (287,299) 56.09 Exercised - Options (5,123) 56.09 Forfeited (717,316) 59.65 ------------------------------------------------------------------------- Outstanding, End of Year 12,979,725 63.13 ------------------------------------------------------------------------- Exercisable, End of Year 1,461,276 56.09 ------------------------------------------------------------------------- ------------------------------------------------------------------------- For the year ended December 31, 2008, EnCana recorded a reduction of compensation costs of $6 million related to the outstanding Performance TSARs (2007 - costs of $21 million). D) Share Appreciation Rights ("SARs") In 2008, EnCana granted SARs to certain employees which entitles the employee to receive a cash payment equal to the excess of the market price of EnCana's Common Shares at the time of exercise over the grant price. SARs are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years and are fully exercisable after three years and expire five years after the grant date. The following table summarizes the information related to the SARs at December 31, 2008: Weighted Average Outstanding Exercise SARs Price ------------------------------------------------------------------------- Canadian Dollar Denominated (C$) Outstanding, Beginning of Year - - Granted 1,314,115 72.07 Forfeited (29,050) 69.42 ------------------------------------------------------------------------- Outstanding, End of Year 1,285,065 72.13 ------------------------------------------------------------------------- Exercisable, End of Year - - ------------------------------------------------------------------------- ------------------------------------------------------------------------- For the year ended December 31, 2008, EnCana has not recorded any compensation costs related to the outstanding SARs. E) Performance Share Appreciation Rights ("Performance SARs") In 2008, EnCana granted Performance SARs to certain employees which entitles the employee to receive a cash payment equal to the excess of the market price of EnCana's Common Shares at the time of exercise over the grant price. Performance SARs vest and expire under the same terms and service conditions as SARs and are also subject to EnCana attaining prescribed performance relative to pre-determined key measures. Performance SARs that do not vest when eligible are forfeited. The following table summarizes the information related to the Performance SARs at December 31, 2008: Weighted Average Outstanding Exercise SARs Price ------------------------------------------------------------------------- Canadian Dollar Denominated (C$) Outstanding, Beginning of Year - - Granted 1,677,030 69.40 Forfeited (56,100) 69.40 ------------------------------------------------------------------------- Outstanding, End of Year 1,620,930 69.40 ------------------------------------------------------------------------- Exercisable, End of Year - - ------------------------------------------------------------------------- ------------------------------------------------------------------------- For the year ended December 31, 2008, EnCana has not recorded any compensation costs related to the outstanding Performance SARs. F) Deferred Share Units ("DSUs") The following table summarizes the information related to the DSUs at December 31, 2008: Outstanding DSUs ------------------------------------------------------------------------- Canadian Dollar Denominated Outstanding, Beginning of Year 589,174 Granted 85,792 Redeemed (34,008) Units, in Lieu of Dividends 15,883 ------------------------------------------------------------------------- Outstanding, End of Year 656,841 ------------------------------------------------------------------------- ------------------------------------------------------------------------- For the year ended December 31, 2008, EnCana recorded compensation costs of $2 million related to the outstanding DSUs (2007 - $14 million). G) Performance Share Units ("PSUs") The following table summarizes the information related to the PSUs at December 31, 2008: Average Outstanding Share PSUs Price ------------------------------------------------------------------------- Canadian Dollar Denominated (C$) Outstanding, Beginning of Year 1,685,036 38.79 Granted 408,686 70.77 Distributed (2,042,541) 45.34 Forfeited (51,181) 38.32 ------------------------------------------------------------------------- Outstanding, End of Year - - ------------------------------------------------------------------------- ------------------------------------------------------------------------- For the year ended December 31, 2008, EnCana recorded compensation costs of $1 million related to the outstanding PSUs (2007 - $43 million). 17. PER SHARE AMOUNTS The following table summarizes the Common Shares used in calculating Net Earnings per Common Share: Three Months Ended ----------------------------------- March June September 31, 30, 30, ----------------------------------- (millions) 2008 2008 2008 ------------------------------------------------------------------------- Weighted Average Common Shares Outstanding - Basic 749.5 750.2 750.3 Effect of Dilutive Securities 3.5 1.1 1.0 ------------------------------------------------------------------------- Weighted Average Common Shares Outstanding - Diluted 753.0 751.3 751.3 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Three Months Ended Twelve Months Ended --------------------------------------------- December 31, December 31, --------------------------------------------- (millions) 2008 2007 2008 2007 ------------------------------------------------------------------------- Weighted Average Common Shares Outstanding - Basic 750.3 749.8 750.1 756.8 Effect of Dilutive Securities 1.0 5.3 1.7 7.8 ------------------------------------------------------------------------- Weighted Average Common Shares Outstanding - Diluted 751.3 755.1 751.8 764.6 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 18. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT EnCana's financial assets and liabilities are comprised of cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued liabilities, the partnership contribution receivable and payable, risk management assets and liabilities, and long-term debt. Risk management assets and liabilities arise from the use of derivative financial instruments. Fair values of financial assets and liabilities, summarized information related to risk management positions, and discussion of risks associated with financial assets and liabilities are presented as follows. A) Fair Value of Financial Assets and Liabilities The fair values of cash and cash equivalents, accounts receivable and accrued revenues, and accounts payable and accrued liabilities approximate their carrying amount due to the short-term maturity of those instruments. The fair values of the partnership contribution receivable and partnership contribution payable approximate their carrying amount due to the specific nature of these instruments in relation to the creation of the integrated oil joint venture. Further information about these notes is disclosed in Note 10 to the Company's annual audited Consolidated Financial Statements for the year ended December 31, 2007. Risk management assets and liabilities are recorded at their estimated fair value based on the mark-to-market method of accounting, using quoted market prices or, in their absence, third-party market indications and forecasts. Long-term debt is carried at amortized cost using the effective interest method of amortization. The estimated fair values of long-term borrowings have been determined based on market information where available, or by discounting future payments of interest and principal at estimated interest rates expected to be available to the Company at period end. The fair value of financial assets and liabilities were as follows: As at As at December 31, 2008 December 31, 2007 ------------------------------------------- Carrying Fair Carrying Fair Amount Value Amount Value ------------------------------------------------------------------------- Financial Assets Held-for-Trading: Cash and cash equivalents $ 383 $ 383 $ 553 $ 553 Risk management assets* 3,052 3,052 403 403 Loans and Receivables: Accounts receivable and accrued revenues 1,568 1,568 2,381 2,381 Partnership contribution receivable* 3,147 3,147 3,444 3,444 Financial Liabilities Held-for-Trading: Risk management liabilities* $ 50 $ 50 $ 236 $ 236 Other Financial Liabilities: Accounts payable and accrued liabilities 2,871 2,871 3,982 3,982 Long-term debt* 9,005 8,242 9,543 9,763 Partnership contribution payable* 3,163 3,163 3,451 3,451 ------------------------------------------------------------------------- ------------------------------------------------------------------------- * Including current portion. B) Risk Management Assets and Liabilities Net Risk Management Position As at As at December December 31, 31, 2008 2007 ------------------------------------------------------------------------- Risk Management Current asset $ 2,818 $ 385 Long-term asset 234 18 ------------------------------------------------------------------------- 3,052 403 ------------------------------------------------------------------------- Risk Management Current liability 43 207 Long-term liability 7 29 ------------------------------------------------------------------------- 50 236 ------------------------------------------------------------------------- Net Risk Management Asset (Liability) $ 3,002 $ 167 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Summary of Unrealized Risk Management Positions As at December 31, 2008 As at December 31, 2007 ----------------------------------------------------- Risk Management Risk Management ----------------------------------------------------- Asset Liability Net Asset Liability Net ------------------------------------------------------------------------- Commodity Prices Natural gas $2,941 $ 10 $2,931 $ 375 $ 29 $ 346 Crude oil 92 40 52 6 205 (199) Power 19 - 19 19 - 19 Interest Rates - - - 2 - 2 Credit - - - 1 2 (1) ------------------------------------------------------------------------- Total Fair Value $3,052 $ 50 $3,002 $ 403 $ 236 $ 167 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Net Fair Value Methodologies Used to Calculate Unrealized Risk Management Positions As at As at December December 31, 31, 2008 2007 ------------------------------------------------------------------------- Prices actively quoted $2,055 $ 105 Prices sourced from observable data or market corroboration 947 62 ------------------------------------------------------------------------- Total Fair Value $3,002 $ 167 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Prices actively quoted refers to the fair value of contracts valued using quoted prices in an active market. Prices sourced from observable data or market corroboration refers to the fair value of contracts valued in part using active quotes and in part using observable, market-corroborated data. Net Fair Value of Commodity Price Positions at December 31, 2008 Notional Fair Volumes Term Average Price Value ------------------------------------------------------------------------- Natural Gas Contracts Fixed Price Contracts NYMEX Fixed Price 1,648 MMcf/d 2009 9.28 US$/Mcf $1,981 NYMEX Fixed Price 35 MMcf/d 2010 9.21 US$/Mcf 23 Purchased Options NYMEX Call (150) MMcf/d 2009 11.67 US$/Mcf (22) NYMEX Put 516 MMcf/d 2009 9.10 US$/Mcf 536 Basis Contracts Canada 71 MMcf/d 2009 - United States 917 MMcf/d 2009 111 Canada and United States* 2010-2013 193 ------------------------------------------------------------------------- 2,822 Other Financial Positions** (1) ------------------------------------------------------------------------- Total Unrealized Gain on Financial Contracts 2,821 Premiums Paid on Unexpired Options 110 ------------------------------------------------------------------------- Natural Gas Fair Value Position $2,931 ------------------------------------------------------------------------- ------------------------------------------------------------------------- * EnCana has entered into swaps to protect against widening natural gas price differentials between production areas, including Canada, the U.S. Rockies and Texas, and various sales points. These basis swaps are priced using both fixed prices and basis prices determined as a percentage of NYMEX. ** Other financial positions are part of the ongoing operations of the Company's proprietary production management. Fair Value ------------------------------------------------------------------------- Crude Oil Contracts Crude Oil Fair Value Position* $ 52 ------------------------------------------------------------------------- ------------------------------------------------------------------------- *The Crude Oil financial positions are part of the ongoing operations of the Company's proprietary production and condensate management and its share of downstream refining positions. Fair Value ------------------------------------------------------------------------- Power Purchase Contracts Power Fair Value Position $ 19 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Net Earnings Impact of Realized and Unrealized Gains (Losses) on Risk Management Positions Realized Gain (Loss) ------------------------------------------- Three Months Ended Twelve Months Ended December 31, December 31, ------------------------------------------- 2008 2007 2008 2007 ------------------------------------------------------------------------- Revenues, Net of Royalties $ 646 $ 408 $ (309) $ 1,601 Operating Expenses and Other 30 (1) 28 3 ------------------------------------------------------------------------- Gain (Loss) on Risk Management $ 676 $ 407 $ (281) $ 1,604 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Unrealized Gain (Loss) ------------------------------------------- Three Months Ended Twelve Months Ended December 31, December 31, ------------------------------------------- 2008 2007 2008 2007 ------------------------------------------------------------------------- Revenues, Net of Royalties $ 1,084 $ (566) $ 2,717 $ (1,239) Operating Expenses and Other 6 (3) 12 4 ------------------------------------------------------------------------- Gain (Loss) on Risk Management $ 1,090 $ (569) $ 2,729 $ (1,235) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Reconciliation of Unrealized Risk Management Positions from January 1 to December 31, 2008 2008 2007 -------------------------------- Total Total Unrealized Unrealized Fair Gain Gain Value (Loss) (Loss) ------------------------------------------------------------------------- Fair Value of Contracts, Beginning of Year $ 167 Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered into During the Year 2,448 $ 2,448 $ 353 Fair Value of Contracts in Place at Transition that Expired During the Year - - 16 Foreign Exchange Loss on Canadian Dollar Contracts (4) - - Fair Value of Contracts Realized During the Year 281 281 (1,604) ------------------------------------------------------------------------- Fair Value of Contracts Outstanding $ 2,892 $ 2,729 $ (1,235) Premiums Paid on Unexpired Options 110 ------------------------------------------------------------------------- Fair Value of Contracts and Premiums Paid, End of Year $ 3,002 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Commodity Price Sensitivities The following table summarizes the sensitivity of the fair value of the Company's risk management positions to fluctuations in commodity prices, with all other variables held constant. When assessing the potential impact of these commodity price changes, the Company believes 10% volatility is a reasonable measure. Fluctuations in commodity prices could have resulted in unrealized gains (losses) impacting net earnings as at December 31, 2008 as follows: Favorable Unfavorable 10% Change 10% Change ------------------------------------------------------------------------- Natural gas price $ 424 $ (418) Crude oil price 7 (7) Power price 9 (9) ------------------------------------------------------------------------- ------------------------------------------------------------------------- C) Risks Associated with Financial Assets and Liabilities The Company is exposed to financial risks arising from its financial assets and liabilities. Financial risks include market risks (such as commodity prices, foreign exchange and interest rates), credit risk and liquidity risk. The fair value or future cash flows of financial assets or liabilities may fluctuate due to movement in market prices and the exposure to credit and liquidity risks. Commodity Price Risk Commodity price risk arises from the effect that fluctuations of future commodity prices may have on the fair value or future cash flows of financial assets and liabilities. To partially mitigate exposure to commodity price risk, the Company has entered into various financial derivative instruments. The use of these derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors. The Company's policy is to not use derivative financial instruments for speculative purposes. Natural Gas - To partially mitigate the natural gas commodity price risk, the Company has entered into option contracts and swaps, which fix the NYMEX prices. To help protect against widening natural gas price differentials in various production areas, EnCana has entered into swaps to manage the price differentials between these production areas and various sales points. Crude Oil - The Company has partially mitigated its exposure to commodity price risk on its condensate supply with fixed price swaps. Power - The Company has in place two Canadian dollar denominated derivative contracts, which commenced January 1, 2007 for a period of 11 years, to manage its electricity consumption costs. Credit Risk Credit risk arises from the potential the Company may incur a loss if a counterparty to a financial instrument fails to meet its obligation in accordance with agreed terms. This credit risk exposure is mitigated through the use of Board-approved credit policies governing the Company's credit portfolio and with credit practices that limit transactions according to counterparties' credit quality. All foreign currency agreements are with major financial institutions in Canada and the United States or with counterparties having investment grade credit ratings. A substantial portion of the Company's accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. As at December 31, 2008, over 95% of EnCana's accounts receivable and financial derivative credit exposures are with investment grade counterparties. At December 31, 2008, EnCana had 2 counterparties whose net settlement position individually account for more than 10 percent of the fair value of the outstanding in-the-money net financial instrument contracts by counterparty. The maximum credit risk exposure associated with accounts receivable and accrued revenues, risk management assets and the partnership contribution receivable is the total carrying value. Liquidity Risk Liquidity risk is the risk the Company will encounter difficulties in meeting a demand to fund its financial liabilities as they come due. The Company manages its liquidity risk through cash and debt management. As disclosed in Note 15, EnCana targets a Debt to Capitalization ratio between 30 and 40 percent and a Debt to Adjusted EBITDA of 1.0 to 2.0 times to steward the Company's overall debt position. In managing liquidity risk, the Company has access to a wide range of funding at competitive rates through commercial paper, capital markets and banks. As at December 31, 2008, EnCana had available unused committed bank credit facilities in the amount of $2.6 billion and unused capacity under shelf prospectuses, the availability of which is dependent on market conditions, for $5.0 billion. The Company believes it has sufficient funding through the use of these facilities to meet foreseeable borrowing requirements. EnCana maintains investment grade credit ratings on its senior unsecured debt. On May 12, 2008, following the announcement of the proposed Arrangement (See Note 4), Standard & Poor's Ratings Service assigned a rating of A- and placed the Company on "CreditWatch Negative", DBRS Limited assigned a rating of A(low) and placed the Company "Under Review with Developing Implications", and Moody's Investors Service assigned a rating of Baa2 and changed the outlook to "Stable" from "Positive". The timing of cash outflows relating to financial liabilities are outlined in the table below: Less Than 1 - 3 4 - 5 1 Year Years Years Thereafter Total ------------------------------------------------------------------------- Accounts Payable and Accrued Liabilities $ 2,871 $ - $ - $ - $ 2,871 Risk Management Liabilities 43 7 - - 50 Long-Term Debt* 727 1,589 3,344 10,392 16,052 Partnership Contribution Payable* 489 978 978 1,588 4,033 ------------------------------------------------------------------------- ------------------------------------------------------------------------- *Principal and interest, including current portion. Included in EnCana's total long-term debt obligations of $16,052 million at December 31, 2008 are $1,657 million in principal obligations related to Bankers' Acceptances, Commercial Paper and LIBOR loans. These amounts are fully supported and Management expects that they will continue to be supported by revolving credit and term loan facilities that have no repayment requirements within the next year. The revolving credit and term loan facilities are fully revolving for a period of up to five years. Based on the current maturity dates of the credit facilities, these amounts are included in cash outflows for the period disclosed as 4 - 5 Years. Further information on Long-term Debt is contained in Note 12. Foreign Exchange Risk Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash flows of the Company's financial assets or liabilities. As EnCana operates primarily in North America, fluctuations in the exchange rate between the U.S./Canadian dollar can have a significant effect on the Company's reported results. EnCana's functional currency is Canadian dollars, however, the Company reports its results in U.S. dollars as most of its revenue is closely tied to the U.S. dollar and to facilitate a more direct comparison to other North American oil and gas companies. As the effects of foreign exchange fluctuations are embedded in the Company's results, the total effect of foreign exchange fluctuations are not separately identifiable. To mitigate the exposure to the fluctuating U.S./Canadian exchange rate, EnCana maintains a mix of both U.S. dollar and Canadian dollar debt. As disclosed in Note 9, EnCana's foreign exchange (gain) loss is primarily comprised of unrealized foreign exchange gains and losses on the translation of U.S. dollar debt issued from Canada and the translation of the U.S. dollar partnership contribution receivable issued from Canada. At December 31, 2008, EnCana had $5,350 million in U.S. dollar debt issued from Canada ($5,421 million at December 31, 2007) and $3,147 million related to the U.S. dollar partnership contribution receivable ($3,444 million at December 31, 2007). A $0.01 change in the U.S. to Canadian dollar exchange rate would have resulted in an $18 million change in foreign exchange (gain) loss at December 31, 2008. Interest Rate Risk Interest rate risk arises from changes in market interest rates that may affect the fair value or future cash flows from the Company's financial assets or liabilities. The Company partially mitigates its exposure to interest rate changes by maintaining a mix of both fixed and floating rate debt. At December 31, 2008, the increase or decrease in net earnings for each one percent change in interest rates on floating rate debt amounts to $12 million (2007 - $14 million). 19. CONTINGENCIES Legal Proceedings The Company is involved in various legal claims associated with the normal course of operations. The Company believes it has made adequate provision for such legal claims. Discontinued Merchant Energy Operations During the period between 2003 and 2005, EnCana and its indirect wholly owned U.S. marketing subsidiary, WD Energy Services Inc. ("WD"), along with other energy companies, were named as defendants in several lawsuits, some of which were class action lawsuits, relating to sales of natural gas from 1999 to 2002. The lawsuits allege that the defendants engaged in a conspiracy with unnamed competitors in the natural gas markets in California in violation of U.S. and California anti-trust and unfair competition laws. Without admitting any liability in the lawsuits, WD agreed to settle all of the class action lawsuits in both state and federal court for payment of $20.5 million and $2.4 million, respectively. Also, as previously disclosed, without admitting any liability whatsoever, WD concluded settlements with the U.S. Commodity Futures Trading Commission ("CFTC") for $20 million and of a previously disclosed consolidated class action lawsuit in the United States District Court in New York for $8.2 million. Also, without admitting any liability whatsoever, WD concluded settlements with a group of individual plaintiffs for $23 million. The remaining lawsuit was commenced by E. & J. Gallo Winery ("Gallo"). The Gallo lawsuit claims damages in excess of $30 million. California law allows for the possibility that the amount of damages assessed could be tripled. The Company and WD intend to vigorously defend against this outstanding claim; however, the Company cannot predict the outcome of these proceedings or any future proceedings against the Company, whether these proceedings would lead to monetary damages which could have a material adverse effect on the Company's financial position, or whether there will be other proceedings arising out of these allegations. 20. RECLASSIFICATION Certain information provided for prior periods has been reclassified to conform to the presentation adopted in 2008.

SOURCE EnCana Corporation

Source: PR Newswire

More News in this Category

Rating: 2.7 / 5 (6 votes)

Rate this article:

User Comments (0)

Comment on this article

Dec 10, 2009, 4:45 pm
Chronic Sneezer Cured of Mystery Ailment
Dec 10, 2009, 8:52 am
Bright Blazar Flare Captured By Fermi
Dec 10, 2009, 8:45 am
Scientists: The AIDS Virus May Have Peaked
Dec 10, 2009, 8:15 am
Solar Energy Powers Marines On Battlefield
Dec 10, 2009, 8:14 am
NASA | Suzaku: The Intergalactic Prospector
Dec 10, 2009, 8:12 am
Cosmetic Tax: The So-Called Bo-Tax
More Videos

Your Name
Text from the image
Comment max 1200 chars
	* All fields are required

Breaking News Space Science Technology Health Sci-fi & Gaming More...	Streaming Video Top Picks Science Health More...	Images and Photos Images of the Day Image Galleries Wallpapers More...	Space Exploration Mars Phoenix Mission Astronomy Human Spaceflight Ask the Astronomer More...	Science and Research Instruments Calculator Ask the Scientist More...	Technology Tech Today Sites of the day More...	My Health Health Health Videos More...	Our Community Knowledge Network Blogs My Weather
Advertising \| About Us \| Contact Us \| Privacy Statement \| Terms of Service \| Abuse Reporting \| RSS Feeds © 2002-2009 redOrbit.com. All rights reserved. All other copyrights remain the property of their respective owners

EnCana generates 2008 cash flow of US$9.4 billion, or $12.48 per share, up 13 percent

Related Articles

Comment on this article

Related Videos

Most Popular Stories

redOrbit Friends

Breaking News

Streaming Video

Images and Photos

Space Exploration

Science and Research

Technology

My Health

Our Community