U.S. SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549

FORM 40-F

(Check One)

[   ] Registration statement pursuant to Section 12 of the Securities Exchange Act of 1934

or

[X] Annual report pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2009

Commission file number 1-15226

ENCANA CORPORATION

(Exact name of registrant as specified in its charter)

1800-855 2nd Street, S.W., P.O. Box 2850, Calgary, Alberta, Canada  T2P 2S5
(403) 645-2000
(Address and Telephone Number of Registrant’s Principal Executive Offices)

CT Corporation System, 111 8th Avenue, New York, NY  10011
(212) 894-8940
(Name, Address (Including Zip Code) and Telephone Number
(Including Area Code) of Agent For Service in the United States)

Securities registered or to be registered pursuant to Section 12(b) of the Act.

Securities registered or to be registered pursuant to Section 12(g) of the Act.       None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.    Debt Securities

For annual reports, indicate by check mark the information filed with this Form:

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report:  751,281,403

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 (the “Exchange Act”) during the preceding 12 months (or for such shorter period that the registrant was required to file such reports); and (2) has been subject to such filing requirements for the past 90 days.

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (s.232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).

The Annual Report on Form 40-F shall be incorporated by reference into or as an exhibit to, as applicable, each of the registrant’s Registration Statements under the Securities Act of 1933:  Form F-3 (File No. 333-150453), Form S-8 (File Nos. 333-124218, 333-13956 and 333-140856) and Form F-9 (File No. 333-149370).

FORM 40-F

Principal Documents

The following documents have been filed as part of this Annual Report on Form 40-F, beginning on the following page:

(a)                               Annual Information Form for the fiscal year ended December 31, 2009;

(b)                              Management’s Discussion and Analysis for the fiscal year ended December 31, 2009; and

(c)                               Consolidated Financial Statements for the fiscal year ended December 31, 2009 (Note 23 to the Consolidated Financial Statements relates to United States Accounting Principles and Reporting (U.S. GAAP)).

40-F1

ENCANA CORPORATION

Annual Information Form

February 18, 2010

This is the annual information form of EnCana Corporation (“EnCana” or the “Corporation”) for the year ended December 31, 2009. In this annual information form, unless otherwise specified or the context otherwise requires, reference to “EnCana” or to the “Corporation” includes reference to subsidiaries of and partnership interests held by EnCana Corporation and its subsidiaries.

On November 30, 2009, EnCana completed a corporate reorganization (the “Split Transaction”) involving the division of EnCana into two independent publicly traded energy companies – EnCana Corporation and Cenovus Energy Inc. (“Cenovus”). The Split Transaction is more fully described under “General Development of the Business”. Except where indicated otherwise, the financial, production and other operating data for EnCana in this annual information form for periods prior to the Split Transaction have not been adjusted to remove the results associated with the upstream assets which were transferred to Cenovus under the Split Transaction.

Unless otherwise specified, all dollar amounts are expressed in United States (“U.S.”) dollars and all references to “dollars”, “$” or to “US$” are to U.S. dollars and all references to “C$” are to Canadian dollars. All production and reserves information is presented on an after royalties basis consistent with U.S. reporting protocol.

In this annual information form, the term “liquids” is used to represent crude oil and natural gas liquids (“NGLs”). Liquids also include condensate volumes. Certain liquids volumes have been converted to millions of cubic feet equivalent (“MMcfe”) or thousands of cubic feet equivalent (“Mcfe”) 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. MMcfe, Mcfe and BOE 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.

Unless otherwise indicated, all financial information included in this annual information form is determined using Canadian Generally Accepted Accounting Principles (“Canadian GAAP”), which differs from Generally Accepted Accounting Principles in the United States (“U.S. GAAP”). The notes to EnCana’s audited consolidated financial statements contain a discussion of the principal differences between EnCana’s financial results calculated under Canadian GAAP and under U.S. GAAP.

Readers are directed to the sections titled “Note Regarding Forward-Looking Statements” and “Note Regarding Reserves Data and Other Oil and Gas Information”.

EnCana Corporation is incorporated under the Canada Business Corporations Act (“CBCA”). Its executive and registered office is located at 1800, 855 - 2nd Street S.W., Calgary, Alberta, Canada T2P 2S5.

In conjunction with the Split Transaction (described under “General Development of the Business”), EnCana’s articles were amended to make certain changes to its share capital. Further information on the Corporation’s share capital is disclosed under “Description of Share Capital”.

The following table presents the name, the percentage of voting securities owned and the jurisdiction of incorporation, continuance or formation of EnCana’s principal subsidiaries and partnerships as at December 31, 2009. Each of these subsidiaries and partnerships had total assets that exceeded 10 percent of the total consolidated assets of EnCana or annual revenues that exceeded 10 percent of the total consolidated annual revenues of EnCana as at December 31, 2009.

The above table does not include all of the subsidiaries and partnerships of EnCana. The assets and annual revenues of unnamed subsidiaries and partnerships in the aggregate did not exceed 20 percent of the total consolidated assets or total consolidated annual revenues as at December 31, 2009.

As a general matter, EnCana reorganizes its subsidiaries as required to maintain proper alignment of its business, operating and management structures.

EnCana was formed in 2002 through the business combination of Alberta Energy Company Ltd. (“AEC”) and PanCanadian Energy Corporation (“PanCanadian”). EnCana is currently one of North America’s leading natural gas producers and its strategy is to be a natural gas pure-play company focused on the development of unconventional resources across North America. EnCana’s other operations include the transportation and marketing of natural gas and liquids production. EnCana pursues profitable growth from its portfolio of long-life resource plays situated in Canada and the U.S.  All of EnCana’s proved reserves and production are located in North America.

On November 30, 2009, EnCana completed a corporate reorganization to split into two independent publicly traded energy companies – EnCana Corporation, a natural gas company, and Cenovus Energy Inc., an integrated oil company.

The Split Transaction was initially proposed in May 2008 and was designed to enhance long-term value for shareholders by creating two independent and sustainable companies, each with the ability to pursue and achieve greater success by employing operational strategies best suited to its unique assets and business plan. In October 2008, due to an unusually high level of uncertainty and volatility in the global debt and equity markets, EnCana delayed seeking shareholder and court approval for the Split Transaction until there were clear signs that the global financial markets had stabilized. In September 2009, EnCana announced plans to proceed with the split.

The Split Transaction was effected by way of an arrangement under the CBCA, under which the holders of Common Shares of EnCana received one new EnCana Common Share and one Common Share of Cenovus for each EnCana Common Share previously held. Holders of stock options of EnCana became the holders of stock options of EnCana and Cenovus, with the exercise prices under the stock options being adjusted based on the relative share trading prices of the EnCana and Cenovus Common Shares.

In connection with the Split Transaction, EnCana entered into an Arrangement Agreement with Cenovus and another subsidiary of EnCana dated October 20, 2009 and a Separation and Transition Agreement with Cenovus dated November 20, 2009. The Arrangement Agreement set out the terms and conditions to the arrangement, including the plan of arrangement. The Separation and Transition Agreement set out the mechanics for the separation of the businesses including the dividing of assets, assumption of liabilities and matters governing certain ongoing relationships between EnCana and Cenovus, including reciprocal indemnities with respect to the assets and liabilities kept by EnCana or transferred to Cenovus.

EnCana employs a decentralized decision making structure organized by operating divisions. Prior to the completion of the Split Transaction, EnCana’s divisions included the Canadian Foothills Division, the Canadian Plains Division, the Integrated Oil Division and the USA Division. Under the Split Transaction, the assets associated with the Canadian Plains Division and the Integrated Oil Division were transferred to Cenovus.

EnCana’s operations are currently divided into two operating divisions:

EnCana’s proprietary production is substantially sold by the Midstream, Marketing & Fundamentals team, which is focused on enhancing the Corporation’s netback price. Midstream, Marketing & Fundamentals manages EnCana’s Market Optimization activities, which include third party purchases and sales of product to provide operational flexibility for transportation commitments, product type, delivery points and customer diversification.

In 2009, the Corporation formed the Natural Gas Economy team to focus on pursuing the development of expanded natural gas markets in North America, particularly within the areas of power generation and transportation. Due to the technical breakthroughs with unconventional natural gas extraction, the commercial resource in North America has grown to a historical high. This abundance improves the longer term affordability and reliability of natural gas for these potential markets. In addition, increased use of natural gas has the potential to yield lower green house gas and volatile organic compound emissions as compared to other fossil fuel use.

For 2009 financial reporting purposes, EnCana’s reportable segments were: (i) Canada; (ii) USA; (iii) Market Optimization; and (iv) Corporate and Other. The Canada reportable segment includes the results from the Canadian Division and Canada – Other. Canada – Other includes the results from the former Canadian Plains Division and the former Integrated Oil Division – Canada operations which were transferred to Cenovus as part of the Split Transaction.

The financial, production and other operating data for EnCana for periods prior to the November 30, 2009 Split Transaction have not been adjusted to remove the results associated with Canada – Other assets which were transferred to Cenovus. The Canada – Other results are reported as continuing operations in accordance with the full cost accounting rules. The U.S. Downstream Refining results prior to the November 30, 2009 Split Transaction are reported as discontinued operations for financial reporting purposes.

The following describes other significant events in the development of EnCana’s business over the last three years. In this section, all divestiture proceeds are provided on a before-tax basis unless otherwise noted.

2009

·      EnCana completed the divestiture of mature conventional oil and natural gas assets for proceeds of approximately $1,000 million in the Canadian Division, $73 million in the USA Division and $17 million in Canada – Other operations.

2008

·      EnCana acquired, in several transactions, certain land and mineral interests in the Haynesville shale in Texas and Louisiana for approximately $1,010 million, net to EnCana. These acquisitions increased EnCana’s land position in the Haynesville shale to approximately 435,000 net acres, including approximately 63,000 net mineral acres.

·      EnCana completed the divestiture of mature, non-core conventional oil and natural gas assets for proceeds of approximately $400 million in the Canadian Division, $251 million in the USA Division and $47 million in Canada – Other operations.

·      EnCana completed the sale of all of its interests in France and Brazil and withdrew from Qatar.

·      In the third quarter of 2008, the Wood River refinery received regulatory approvals to start construction on the Coker and Refinery Expansion (“CORE”) project. The Wood River refinery was part of the Downstream Refining assets transferred to Cenovus as part of the Split Transaction.

2007

·      EnCana, with ConocoPhillips, completed a transaction to create an integrated oil business. The integrated oil business was comprised of two 50-50 operating entities, a Canadian upstream enterprise operated by EnCana and a U.S. downstream enterprise operated by ConocoPhillips. The integrated oil business was subsequently transferred to Cenovus as part of the Split Transaction.

·      A subsidiary of EnCana completed the sale of all of its interests in Chad.

·      EnCana completed the sale of The Bow office project assets for approximately $57 million. As part of the transaction, EnCana, as tenant, signed a 25-year lease agreement. EnCana has subleased approximately 50 percent of The Bow office space to Cenovus as part of the Split Transaction.

·      EnCana’s Board of Directors authorized funding for the development of the Deep Panuke natural gas project located offshore Nova Scotia.

·      A subsidiary of EnCana acquired all of the Deep Bossier natural gas and land interests of the privately-owned Leor Energy group in Texas for approximately $2.55 billion before closing adjustments. EnCana first entered the Deep Bossier play in 2005 by acquiring a 30 percent interest in the Amoruso field from Leor Energy, and then increased its interest to 50 percent in June 2006. The November 2007 transaction brought EnCana’s interest in the Amoruso field to 100 percent and added an additional 75 million cubic feet per day of natural gas production in 2007.

The following map outlines the location of EnCana’s North American landholdings and key resource plays as at December 31, 2009.

EnCana’s operations are focused on exploiting North American long-life unconventional natural gas formations, including tight gas, shales and CBM. EnCana attempts to identify early-stage, geographically expansive gas-charged basins and then assembles a large land position to try to capture core resource opportunities. EnCana then focuses on determining cost efficient means for extracting natural gas through a combination of detailed reservoir studies and pilot testing available and emerging drilling and completions technologies. EnCana’s manufacturing-style development approach extends over many years. Capital and operating efficiencies are pursued on an ongoing basis and shared across EnCana’s expansive portfolio.

EnCana’s operations are primarily located in Canada and the U.S.  All of EnCana’s current proved reserves and production are located in North America.

The Canadian Division, formerly the Canadian Foothills Division, includes EnCana’s natural gas assets in British Columbia and Alberta, and the Deep Panuke natural gas project located offshore Nova Scotia. Four key resource plays are located in the Division: (i) Greater Sierra; (ii) Cutbank Ridge; (iii) Bighorn; and (iv) CBM. The CBM key resource play (Horseshoe Canyon coalbed methane and commingled shallow gas) is located within the Clearwater area. In addition, EnCana has established a leading land position in the Horn River Devonian shale, currently included as part of the Greater Sierra key resource play, and the Montney formation which is included in the Cutbank Ridge key resource play. The Canadian Division also manages the offshore Deep Panuke natural gas project in Atlantic Canada.

In 2009, the Canadian Division had total capital investment in Canada of approximately $1,869 million and drilled approximately 699 net wells. As at December 31, 2009, the Canadian Division had an established land position in Canada of approximately 11.0 million gross acres (9.3 million net acres); of these, approximately 6.0 million gross acres (5.0 million net acres) are undeveloped. The mineral rights on approximately 44 percent of the total net acreage are owned in fee title by EnCana, which means that the mineral rights are held by EnCana in perpetuity and production is subject to a mineral tax that is generally less than the Crown royalty imposed on production from land where the government owns the mineral rights. The Canadian Division’s 2009 production averaged approximately 1,319 million cubic feet equivalent per day. The 2009 average production volumes were lowered by approximately 120 million cubic feet equivalent per day, due to shut-in and curtailed production and delayed well completions and tie-ins as a result of the low natural gas price environment.

The following tables summarize the Canadian Division landholdings, daily production and producing wells as at and for the periods indicated.

Notes:

(1)     Figures exclude wells capable of producing, but not producing, as of December 31, 2009.

(2)     At December 31, 2009, the CBM key resource play had approximately 6,243 gross producing gas wells (5,866 net gas wells).

Key Resource Plays and Activities in the Canadian Division

Greater Sierra

The Greater Sierra area is a key resource play located in northeast British Columbia. The primary focus is on the continued development of the Devonian Jean Marie formation and the Horn River Devonian shale formation. In 2009, EnCana drilled approximately 57 net wells in the area and production averaged approximately 199 million cubic feet per day of natural gas. Production has remained relatively constant over the last five years while EnCana has reduced capital expenditures.

At December 31, 2009, EnCana held an average 94 percent working interest in 14 production facilities in the area that were capable of processing approximately 525 million cubic feet per day of natural gas. EnCana also held a 100 percent working interest in the Ekwan pipeline which has a capacity of approximately 400 million cubic feet per day and transports natural gas from northeast British Columbia to Alberta.

At December 31, 2009, EnCana controlled approximately 440,000 undeveloped gross acres (256,000 net acres) in the Devonian shale formation of the Horn River Basin in northeast British Columbia. The Horn River formation shales (Muskwa, Otter Park and Evie) within EnCana’s focus area are upwards of 500 feet thick. At December 31, 2009, these shales have been evaluated with 60 wells (five vertical and 55 horizontal), 13 of which have been placed on long-term production (one vertical and 12 horizontal). In 2009, EnCana and its partner commenced drilling a larger program of horizontal wells in the Two Island Lake area, and constructed a compressor station and 24-inch raw gas transmission pipeline.

EnCana is the operator of the Cabin Gas Plant project to process Horn River shale gas. EnCana continues to make progress on the project and at December 31, 2009, regulatory timelines remained on schedule. The British Columbia Environmental Assessment Office submitted its favourable project recommendation to the Government Cabinet of British Columbia in December 2009. The application is for approximately 800 million cubic feet per day processing capacity, of which EnCana has a 30 percent ownership in the first phase of approximately 400 million cubic feet per day. In January 2010, EnCana received an Environmental Assessment Certificate from the British Columbia Ministry of Environment for the Cabin Gas Plant project. EnCana expects the first phase of processing capacity will be on stream by September 2012. Additional approvals from the British Columbia Oil and Gas Commission are still required and are expected to be forthcoming near the end of the first quarter of 2010.

Cutbank Ridge

The Cutbank Ridge area is a key resource play located in the Canadian Rocky Mountain foothills, southwest of Dawson Creek, British Columbia. Key producing horizons in Cutbank Ridge include the Montney, Cadomin and Doig formations. The Montney and Cadomin formations are almost exclusively being developed with horizontal well technology. Significant improvements have been achieved with respect to horizontal well completions with the application of multi-stage hydraulic fracturing. In 2009, EnCana drilled approximately 71 net wells in the area and production averaged approximately 310 million cubic feet per day of natural gas.

EnCana holds approximately 720,000 net acres covering the unconventional deep basin Montney formation, with approximately 244,000 net acres located within EnCana’s core development area near Dawson Creek, British Columbia. EnCana has tested the deep basin Montney play extensively over the last several years and by applying advanced technology has reduced overall development costs significantly, achieving a greater than 80 percent reduction in costs on a completed interval basis over the past three years.

EnCana has sour gas processing capacity of approximately 380 million cubic feet per day at its 100 percent owned gas plants at Hythe and Steeprock.

Bighorn

The Bighorn area is a key resource play in west central Alberta, with a focus on exploiting multi-zone stacked Cretaceous sands in the Deep Basin. The primary properties in Bighorn are Resthaven, Kakwa, Redrock and Berland. In 2009, EnCana drilled approximately 69 net wells in the area and production averaged approximately 159 million cubic feet per day of sweet natural gas.

EnCana has a working interest in a number of natural gas plants within the Bighorn area. The Resthaven plant, in which EnCana has approximately 70 percent working interest, has a capacity of approximately 100 million cubic feet per day. The Kakwa gas plant has a capacity of approximately 60 million cubic feet per day. EnCana owns 50 percent of this plant and has firm processing capacity for the remaining 50 percent. EnCana holds a 24 percent working interest in the Berland River plant, which has a capacity of approximately 165 million cubic feet per day.

Clearwater

The Clearwater area extends from the U.S. border to central Alberta. The primary focus of the Clearwater area is the CBM key natural gas resource play which involves Horseshoe Canyon Coals integrated with shallower sands. Within Clearwater, EnCana holds approximately 5.1 million net acres with approximately 2.1 million net acres on the Horseshoe Canyon trend. Approximately 80 percent of the total net acreage landholdings are owned in fee title. In 2009, EnCana drilled approximately 490 net CBM wells and production averaged approximately 316 million cubic feet per day of natural gas from the CBM key resource play.

Atlantic Canada

At December 31, 2009, EnCana held an interest in approximately 76,000 gross acres (32,000 net acres) in Atlantic Canada, which includes Nova Scotia and Newfoundland and Labrador. EnCana operates five of its eight licenses in these areas and has an average working interest of approximately 42 percent.

EnCana is the operator of the Deep Panuke gas field, located offshore Nova Scotia, and owned and operated 100 percent of the field at December 31, 2009, after acquiring all of the interests in the licenses making up the field in July 2009. The Deep Panuke natural gas project involves the installation of the facilities required to produce natural gas from the field, located approximately 250 kilometres southeast of Halifax (on the Scotian shelf). Produced gas will be transported to shore by subsea pipeline and EnCana will transport this natural gas via the Maritimes & Northeast Pipeline to a delivery point in eastern Canada. Work has been progressing in anticipation of first production by mid 2011.

The USA Division includes EnCana’s natural gas assets in the Jonah field in southwest Wyoming, the Piceance Basin in northwest Colorado and the East Texas and Fort Worth basins in Texas. The USA Division is also focused on exploration and development of the Haynesville shale in Texas and Louisiana and the Marcellus shale in Pennsylvania. The majority of the production in the U.S. is from the following four key resource plays: (i) Jonah; (ii) Piceance; (iii) East Texas; and (iv) Fort Worth.

In 2009, the USA Division had total capital investment of approximately $1,821 million and drilled approximately 390 net wells. At December 31, 2009, EnCana’s landholdings in the U.S. were approximately 4.3 million gross acres (3.5 million net acres). Approximately 3.5 million gross acres were undeveloped (2.9 million net acres), with the majority in Texas, Colorado, Louisiana and Wyoming. The USA Division’s 2009 production averaged approximately 1,684 million cubic feet equivalent per day. The 2009 average production volumes were lowered by approximately 200 million cubic feet equivalent per day, due to shut-in and curtailed production and delayed well completions and tie-ins as a result of the low natural gas price environment.

The following tables summarize the USA Division landholdings, daily production and producing wells as at and for the periods indicated.

Note:

(1)          Figures exclude wells capable of producing, but not producing, as of December 31, 2009.

Key Resource Plays and Activities in the USA Division

Jonah

The Jonah field is a key resource play located in the Green River Basin in southwest Wyoming. Production is from the Lance formation, which contains vertically stacked sands that exist at depths between 8,500 and 13,000 feet. The wells are stimulated with multi-stage advanced hydraulic fracturing techniques. Historically, EnCana’s operations have been conducted in the over-pressured core portion of the field. In 2008 and 2009, EnCana conducted development in the adjacent normally pressured lands. At December 31, 2009, EnCana controlled approximately 125,000 undeveloped gross acres (111,000 net acres).

Within the over-pressured area, EnCana plans to drill the field to ten acre spacing with higher densities in some areas. Outside of the over-pressured area, EnCana owns approximately 120,000 gross acres, where 40 acre and possibly 20 acre drilling potential exists.

In 2009, EnCana drilled approximately 100 net wells within the core area and eight net wells in the adjacent lands. The Jonah field produced an average of approximately 571 million cubic feet per day of natural gas production.

Piceance

The Piceance Basin is a key resource play located in northwest Colorado. The basin is characterized by thick natural gas accumulations primarily in the Williams Fork formation. EnCana’s 2004 acquisition of Tom Brown, Inc. provided a significant amount of the acreage under current development. At December 31, 2009, EnCana controlled approximately 699,000 undeveloped gross acres (634,000 net acres).

Between 2006 and 2009, EnCana finalized eight agreements to jointly develop portions of the Piceance Basin. During 2009, EnCana drilled approximately 91 net wells with third party funds. For the period of 2010 to 2013, it is expected that EnCana will drill approximately 344 net wells with third party funds from all existing agreements.

Compression and processing facilities in the Piceance Basin include approximately 2,500 kilometres of pipelines and a processing facility with a capacity of approximately 60 million cubic feet per day. In addition, EnCana has access to third party processing facilities within the Piceance Basin.

In 2009, EnCana drilled approximately 129 net wells and produced an average of approximately 362 million cubic feet per day of natural gas.

East Texas

East Texas is a key resource play characterized as a tight gas play with multi-zone targets in the Bossier and Cotton Valley zones. EnCana first entered East Texas in 2004 with the acquisition of Tom Brown, Inc.

In 2005, EnCana entered the Deep Bossier play through an acquisition of a 30 percent interest in the Leor Energy group’s Deep Bossier assets. Subsequently, in 2006, EnCana increased this interest to 50 percent. In November 2007, EnCana acquired the Leor Energy group’s remaining interests in the Deep Bossier play as well as additional East Texas acreage. At December 31, 2009, EnCana controlled approximately 224,000 undeveloped gross acres (196,000 net acres).

In 2009, EnCana drilled approximately 38 net wells and produced an average of approximately 324 million cubic feet per day of natural gas.

Fort Worth

The Fort Worth Basin is a key resource play located in north Texas, producing from the prolific Barnett shale. Since entering the basin in 2003, EnCana has applied horizontal drilling and multi-stage reservoir stimulation to improve performance in this play. At December 31, 2009, EnCana controlled approximately 29,000 undeveloped gross acres (18,000 net acres).

In 2009, EnCana drilled approximately 26 net wells and produced an average of approximately 136 million cubic feet per day of natural gas.

Haynesville Shale

EnCana has established a leading land and resource position in the Haynesville shale in Texas and Louisiana. EnCana acquired its first leases in 2005, drilled its first three vertical wells in 2006, and has continued to acquire land.

In 2007, EnCana signed a 50/50 joint exploration agreement with an unrelated party to explore and develop the lands. In 2008, EnCana increased its leased acreage in the Haynesville shale play to approximately 435,000 net acres through a series of transactions totaling approximately $1,010 million. Included in this land position is approximately 63,000 net acres of mineral rights that were purchased by EnCana in July 2008 for approximately $300 million, net to EnCana. At December 31, 2009, EnCana controlled approximately 570,000 undeveloped gross acres (379,000 net acres), with the majority of the leaseholds in North Louisiana being located in the DeSoto and Red River parishes. Certain Haynesville shale undeveloped acreage is subject to leases that will expire over the next several years unless production is established on the acreage held. EnCana’s near term drilling plans are focused on land retention and completion optimization.

At the end of 2009, EnCana finalized a joint venture with an unrelated party to develop part of the Haynesville shale in east Texas.

In 2009, EnCana drilled approximately 49 net wells and produced an average of approximately 70 million cubic feet per day of natural gas. The December 2009 exit rate production for the Haynesville shale was approximately 125 million cubic feet per day.

Marcellus Shale

In 2009, EnCana established an entry level land position of approximately 19,000 net undeveloped acres in the Marcellus shale in Pennsylvania through a joint venture agreement with an unrelated party. In 2010, EnCana will begin evaluating these lands.

Other Operations

Canada – Other

Canada – Other includes the results from the former Canadian Plains Division and former Integrated Oil – Canada operations which were transferred to Cenovus as part of the Split Transaction on November 30, 2009. Canada – Other included established natural gas development and production activities in southern Alberta and southern Saskatchewan, crude oil development and production activities in Alberta and Saskatchewan as well as exploration for, and development and production of bitumen using enhanced oil recovery methods in Alberta. Five key resource plays were contained in Canada - Other: (i) Shallow Gas in southeast Alberta and Saskatchewan; (ii) Pelican Lake in northeast Alberta; (iii) Weyburn in Saskatchewan; (iv) Foster Creek in northeast Alberta; and (v) Christina Lake in northeast Alberta.  The Foster Creek and Christina Lake enhanced oil recovery projects were part of the integrated oil business created by EnCana and ConocoPhillips in January 2007.

For 2009, Canada – Other had combined capital investment of approximately $848 million (2008 - $1,500 million) and had drilled approximately 639 net wells (2008 - 1,514 net wells). For 2009, natural gas production was approximately 762 million cubic feet per day (2008 - 905 million cubic feet per day) and liquids production was approximately 99,900 barrels per day (2008 - 100,250 barrels per day).

Except where indicated otherwise, the financial, production and other operating data for EnCana in this annual information form as at dates prior to, or for periods entirely or partly prior to, the Split Transaction have not been adjusted to remove the results associated with Canada – Other (former Canadian Plains Division and former Integrated Oil Division – Canada operations) assets which were transferred to Cenovus under the Split

Transaction. Canada – Other results are reported as continuing operations in accordance with the full cost accounting requirements.

Former U.S. Downstream Refining

Prior to the Split Transaction, EnCana’s Integrated Oil Division was comprised of the Integrated Oil – Canada operations and U.S. Downstream Refining. U.S. Downstream Refining focused on the refining of crude oil into petroleum and chemical products at the Borger refinery located in Borger, Texas and the Wood River refinery located in Roxana, Illinois. The refineries were acquired through the creation of the integrated oil business between EnCana and ConocoPhillips in January 2007. The refineries were 50 percent owned by EnCana and operated by ConocoPhillips.  U.S. Downstream Refining was transferred to Cenovus as part of the Split Transaction on November 30, 2009.

For 2009, U.S. Downstream Refining had capital investment of approximately $829 million (2008 - $478 million). The expenditures primarily related to the Wood River refinery’s CORE project.   For the period ended September 30, 2009, the refineries’ gross crude oil capacity was approximately 452 thousand barrels per day (year ended December 31, 2008 - 452 thousand barrels per day) and crude utilization was approximately 90 percent (year ended December 31, 2008 - 93 percent).

The U.S. Downstream Refining results prior to the Split Transaction are reported as discontinued operations for financial reporting purposes.

Market Optimization

Market Optimization activities are managed by EnCana’s Midstream, Marketing & Fundamentals Corporate Group. Market Optimization is focused on enhancing the netback price of the Corporation’s proprietary production. Market Optimization activities include third party purchases and sales of product to provide operational flexibility for transportation commitments, product type, delivery points and customer diversification.

Natural Gas Marketing

EnCana’s produced natural gas is primarily marketed to local distribution companies, industrials, other producers, and energy marketing companies. Prices received by EnCana are based primarily upon prevailing index prices for natural gas in the region in which it is sold. Prices are impacted by competing fuels in such markets and by regional supply and demand for natural gas.

EnCana seeks to mitigate the market risk associated with future cash flows by entering into various risk management contracts relating to produced natural gas.  Details of those contracts related to EnCana’s various risk management positions are found in Note 20 to EnCana’s audited consolidated financial statements for the year ended December 31, 2009.

Other Marketing Activities

EnCana sells and manages the transportation of its crude oil, condensate and NGLs to markets in Canada and the U.S.  Sales are normally executed under spot, monthly evergreen and term contracts with delivery to major pipeline/sales hubs at current market prices. In addition, EnCana holds interests in two power assets, the Cavalier and Balzac Power Stations, to optimize its electricity costs, particularly in Alberta.

Reserve Quantities and Other Oil and Gas Information

Since inception, EnCana has retained independent qualified reserves evaluators (“IQREs”) to evaluate and prepare reports on 100 percent of EnCana’s natural gas and liquids reserves annually. In 2009, EnCana’s Canadian reserves were evaluated by McDaniel & Associates Consultants Ltd. and GLJ Petroleum Consultants Ltd., and its U.S. reserves were evaluated by Netherland, Sewell & Associates, Inc. and DeGolyer and MacNaughton.

EnCana’s Vice President, Corporate Reserves & Competitor Analysis and four other staff under this individual’s direction oversee the preparation of the reserves estimates by the IQREs. Currently this internal staff of three professional engineers, an engineering technologist and a business analyst have combined relevant experience of over 85 years. The Vice President and other engineering staff are all members of the appropriate provincial or state professional associations and are members of various industry associations such as the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.

EnCana has a Reserves Committee of independent board members which reviews the qualifications and appointment of the IQREs. The Reserves Committee also reviews the procedures for providing information to the evaluators. All booked reserves are based upon annual evaluations by the IQREs.

The evaluations by the IQREs are conducted from the fundamental petrophysical, geological, engineering, financial and accounting data. Processes and procedures are in place to ensure that the IQREs are in receipt of all relevant information. Reserves are estimated based on material balance analysis, decline analysis, volumetric calculations or a combination of these methods, in all cases having regard to economic considerations. In the case of producing reserves, the emphasis is on decline analysis where volumetric analysis is considered to limit forecasts to reasonable levels. Non-producing reserves are estimated by analogy to producing offsets, with consideration of volumetric estimates of in place quantities.

EnCana provides disclosure of its reserves and other oil and gas information in accordance with U.S. disclosure requirements. See “Note Regarding Reserves Data and Other Oil and Gas Information”. In 2009, the U.S. Securities and Exchange Commission (“SEC”) amended its oil and gas reporting requirements effective for EnCana’s 2009 year end reporting. The U.S. Financial Accounting Standards Board (“FASB”) also amended its oil and gas reserve estimation and disclosure requirements to align with the amended SEC requirements. The amendments included changing the price used to calculate reserves from a year-end single day price to a historical 12-month average price and permitting optional disclosure of the sensitivity of reserves to price.

Net Proved Reserves

EnCana’s natural gas reserves decreased by approximately 19 percent in 2009, largely as a result of low 12-month average prices and the Split Transaction. Approximately 75 percent of the decrease attributable to negative revisions was a direct result of low 12-month average prices and approximately 80 percent of the sale of reserves in place was associated with the Split Transaction. Technical revisions were not significant. Extensions and discoveries were 2,132 billion cubic feet, of which approximately two-thirds was in the U.S. and the balance was in Canada.

During 2008, EnCana’s natural gas reserves increased by approximately 3 percent as a result of successful exploration and development drilling, which resulted in extensions and discoveries of 1,966 billion cubic feet. Approximately two-thirds of extensions and discoveries were in Canada with the balance being in the U.S.  Purchase and sale of reserves in place were not material.

In 2007, natural gas reserves increased primarily from development drilling.

In 2009, EnCana’s crude oil and natural gas liquids reserves decreased by approximately 77 percent and EnCana’s bitumen reserves were divested, substantially all as a result of the Split Transaction.

At year-end 2008, EnCana’s crude oil and natural gas liquids reserves, including bitumen, increased approximately 8 percent in comparison to year-end 2007, largely as a result of positive revisions associated with the Corporation’s interests in Foster Creek and Christina Lake.

As at December 31, 2007, EnCana’s crude oil and natural gas liquids reserves, including bitumen, were approximately 18 percent lower than at year-end 2006 as a consequence of the contribution of the Corporation’s interests in Foster Creek and Christina Lake into the integrated oil business effective January 2, 2007. Subsequent to this transaction, EnCana’s crude oil and natural gas liquids reserves, including bitumen, increased approximately 26 percent over the balance of the year, mainly due to bookings at Foster Creek and Christina Lake.

In keeping with U.S. standards requiring that the reserves and related future net revenue be estimated under existing economic conditions, operating methods and government regulations, 2008 and 2007 reserves and future net revenues were determined based on the year-end single day product prices. Under the amended SEC rules, the 2009 reserves and future net revenues have been determined based on a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. Reference prices for 2009 were as follows: natural gas - Henry Hub $3.87/MMbtu, AECO C$3.77/MMbtu, decreases of 32 percent and 39 percent from year-end 2008, respectively; crude oil - WTI $61.18/bbl, Edmonton Light C$65.64/bbl, increases of 37 percent and 48 percent from year-end 2008, respectively.

The following table sets forth reserves continuity information prepared by EnCana in accordance with U.S. disclosure standards. The year-end numbers represent estimates derived from the reports of the independent qualified reserves evaluators referred to above.

Net Proved Reserves (EnCana Share After Royalties) (1,2)

Constant Pricing

Notes:

(1)          Definitions:

a.         “Net” reserves are the remaining reserves of EnCana, after deduction of estimated royalties and including royalty interests.

b.         “Proved” oil and gas reserves are those quantities of oil and gas which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations.

c.         “Developed” oil and gas reserves are reserves of any category that are expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

d.         “Undeveloped” oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(2)          EnCana does not file any estimates of total net proved natural gas and liquids reserves with any U.S. federal authority or agency other than the SEC.

(3)          EnCana’s disclosure of bitumen reserve volumes is in accordance with amended SEC rules regarding disclosure by final products.  2008 and 2007 crude oil and natural gas liquids totals have been revised to exclude bitumen volumes.

(4)          Contribution of bitumen interests to the integrated oil business with ConocoPhilips.

(5)          The estimates of reserves for the year-end 2009 differ from those that were determined in previous years, which were determined by employing year-end single day pricing.  Single day prices as at December 31, 2009 were as follows: natural gas – Henry Hub $5.78/Mmbtu and AECO C$5.63/MMbtu, which were approximately 49 percent higher than the 12-month average prices; crude oil – WTI $79.36/bbl and Edmonton Light C$82.69/bbl, which were approximately 30 percent and 26 percent higher than the 12-month average prices, respectively.  The 2009 reserve estimates for natural gas and crude oil and natural gas liquids using the year-end single day pricing would have been higher by approximately 11 percent and 7 percent respectively, than those reported pursuant to the amended SEC rules utilizing the 12-month average price.

(6)          Revisions and improved recovery includes revisions due to price.  Approximately 75 percent of the negative revisions to natural gas in 2009 were attributable to the significantly lower prices in effect for SEC reporting purposes.

(7)          The transfer of EnCana’s Canadian Plains and Integrated Oil Divisions’ upstream assets to Cenovus, effective November 30, 2009 pursuant to the Split Transaction, accounts for approximately 80 percent of the sale of reserves in place for natural gas and substantially all of the sale of reserves in place for crude oil and natural gas liquids and for bitumen.

Proved Undeveloped Reserves

EnCana’s proved undeveloped natural gas reserves represented approximately 41 percent of total proved natural gas reserves at December 31, 2009, up from approximately 37 percent at December 31, 2008.  At December 31, 2009, approximately 34 percent of EnCana’s proved crude oil and liquids reserves were proved undeveloped, up from approximately 28 percent at December 31, 2008. These increases were largely a result of the transfer of assets with lower levels of proved undeveloped reserves as part of the Split Transaction.

During 2009, approximately 633 billion cubic feet equivalent of proved undeveloped reserves were converted to proved developed. Investments made during 2009 to convert proved undeveloped reserves to proved developed reserves were approximately $1.2 billion. Proved undeveloped reserves increased by approximately 260 billion cubic feet of natural gas as a result of amendments to the SEC rules relating to estimates of proved undeveloped reserves.

At December 31, 2009, the proved undeveloped reserves which have remained undeveloped for five years or more in both Canada and the United States were not material. All of the proved undeveloped reserves at December 31, 2009 are scheduled for development within the next five years in both Canada and the United States.

Sensitivity of 2009 Reserves to Prices

The following table summarizes EnCana’s estimates of its proved reserves as at December 31, 2009 based on the 2009 12-month average prices (“SEC case”) and on the prices set forth below.

The business case assumes the following prices: natural gas – Henry Hub $5.50/MMbtu in 2010 and $6.50/MMbtu thereafter, and AECO C$5.49/MMbtu in 2010 and C$6.39/MMbtu in 2011 decreasing to C$6.04/MMbtu by 2014 and thereafter; crude oil – WTI $75.00/bbl and Edmonton Light C$76.84/bbl.