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)
Canada |
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1311 |
|
Not
applicable |
1800-855
2nd Street, S.W., P.O. Box 2850, Calgary, Alberta, Canada T2P 2S5
(403) 645-2000
(Address and Telephone Number of Registrants 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.
Title of
each class |
|
Name of
each exchange on which registered |
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:
[X] Annual Information Form |
|
[X] Audited Annual Financial Statements |
Indicate the number of outstanding shares of each of the issuers 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.
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Yes X |
No |
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).
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Yes |
No |
The Annual Report on Form 40-F shall be incorporated by reference into or as an exhibit to, as applicable, each of the registrants 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) Managements 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)).
ENCANA CORPORATION
Annual Information Form
February 18, 2010
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Note Regarding Reserves Data and Other Oil and Gas Information |
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Appendix B - Report on Reserves Data by Independent Qualified Reserves Evaluators |
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Appendix C - Report of Management and Directors on Reserves Data and Other Information |
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EnCana Corporation |
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Annual Information Form |
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 EnCanas audited consolidated financial statements contain a discussion of the principal differences between EnCanas 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 |
|
Annual Information Form |
Name and Incorporation |
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), EnCanas articles were amended to make certain changes to its share capital. Further information on the Corporations share capital is disclosed under Description of Share Capital.
Intercorporate Relationships |
The following table presents the name, the percentage of voting securities owned and the jurisdiction of incorporation, continuance or formation of EnCanas 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.
Subsidiaries & Partnerships |
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Percentage |
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Jurisdiction of |
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EnCana USA Holdings |
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100 |
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Delaware |
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3080763 Nova Scotia Company |
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100 |
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Nova Scotia |
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Alenco Inc. |
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100 |
|
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Delaware |
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EnCana Oil & Gas (USA) Inc. |
|
100 |
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Delaware |
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EnCana Marketing (USA) Inc. |
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100 |
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Delaware |
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EnCana USA Investment Holdings |
|
100 |
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Delaware |
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|
|
|
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|
|
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 Corporation |
|
Annual Information Form |
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 Americas 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. EnCanas 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 EnCanas proved reserves and production are located in North America.
Split Transaction |
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.
Operating Divisions |
EnCana employs a decentralized decision making structure organized by operating divisions. Prior to the completion of the Split Transaction, EnCanas 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.
EnCanas operations are currently divided into two operating divisions:
· |
Canadian Division, formerly the Canadian Foothills Division, which includes natural gas development and production assets located in British Columbia and Alberta, and the Deep Panuke natural gas project offshore Nova Scotia. Four key resource plays are located in the division: (i) Greater Sierra in northeast British Columbia, including the Horn River shale play; (ii) Cutbank Ridge on the Alberta and British Columbia border, including the Montney formation; (iii) Bighorn in west central Alberta; and (iv) Coalbed Methane (CBM) in southern Alberta. |
EnCana Corporation |
|
Annual Information Form |
· |
USA Division, which includes the natural gas development and production assets located in the U.S. Four key resource plays are located in the division: (i) Jonah in southwest Wyoming; (ii) Piceance in northwest Colorado; (iii) East Texas in Texas; and (iv) Fort Worth in Texas. The USA Division is also focused on the development of the Haynesville shale play located in Louisiana and Texas and the recent entrance into the Marcellus shale play located in Pennsylvania. |
EnCanas proprietary production is substantially sold by the Midstream, Marketing & Fundamentals team, which is focused on enhancing the Corporations netback price. Midstream, Marketing & Fundamentals manages EnCanas 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, EnCanas 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.
Other Developments |
The following describes other significant events in the development of EnCanas 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 EnCanas 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.
EnCana Corporation |
|
Annual Information Form |
· 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.
· EnCanas 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 EnCanas interest in the Amoruso field to 100 percent and added an additional 75 million cubic feet per day of natural gas production in 2007.
EnCana Corporation |
|
Annual Information Form |
The following map outlines the location of EnCanas North American landholdings and key resource plays as at December 31, 2009.
EnCana Corporation |
|
Annual Information Form |
EnCanas 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. EnCanas manufacturing-style development approach extends over many years. Capital and operating efficiencies are pursued on an ongoing basis and shared across EnCanas expansive portfolio.
EnCanas operations are primarily located in Canada and the U.S. All of EnCanas current proved reserves and production are located in North America.
The Canadian Division, formerly the Canadian Foothills Division, includes EnCanas 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 Divisions 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.
EnCana Corporation |
|
Annual Information Form |
The following tables summarize the Canadian Division landholdings, daily production and producing wells as at and for the periods indicated.
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Landholdings |
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Developed |
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Undeveloped |
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Total |
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Average |
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(thousands of acres at December 31, 2009) |
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Gross |
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Net |
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Gross |
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Net |
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Gross |
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Net |
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Interest |
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Greater Sierra |
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617 |
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590 |
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1,420 |
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1,168 |
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2,037 |
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1,758 |
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86% |
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Cutbank Ridge |
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369 |
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282 |
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884 |
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780 |
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1,253 |
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1,062 |
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85% |
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Bighorn |
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256 |
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167 |
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394 |
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292 |
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650 |
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459 |
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71% |
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Clearwater |
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3,367 |
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2,959 |
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2,302 |
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2,163 |
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5,669 |
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5,122 |
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90% |
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Atlantic Canada |
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- |
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- |
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76 |
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32 |
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76 |
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32 |
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42% |
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Other |
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416 |
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247 |
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938 |
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574 |
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1,354 |
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821 |
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61% |
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Canadian Division |
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5,025 |
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4,245 |
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6,014 |
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5,009 |
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11,039 |
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9,254 |
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84% |
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Production |
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Natural Gas |
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Liquids |
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Total |
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(annual average) |
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2009 |
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2008 |
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2009 |
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2008 |
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2009 |
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2008 |
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Greater Sierra |
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|
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199 |
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220 |
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871 |
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1,044 |
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|
204 |
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226 |
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||||||
Cutbank Ridge |
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|
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310 |
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296 |
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591 |
|
617 |
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313 |
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300 |
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Bighorn |
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|
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159 |
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167 |
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2,719 |
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3,734 |
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175 |
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189 |
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Clearwater (1) |
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|
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453 |
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495 |
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9,192 |
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10,777 |
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508 |
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560 |
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Other |
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|
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103 |
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122 |
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2,507 |
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3,808 |
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119 |
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145 |
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Canadian Division |
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1,224 |
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1,300 |
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15,880 |
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19,980 |
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1,319 |
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1,420 |
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Note: (1) The CBM key resource play located within the Clearwater area, averaged production of approximately 316 million cubic feet per day in 2009 (304 million cubic feet per day in 2008). |
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Producing Wells |
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Natural Gas |
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Crude Oil |
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Total |
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(number of wells at December 31, 2009) (1) |
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Gross |
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Net |
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Gross |
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Net |
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Gross |
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Net |
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Greater Sierra |
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|
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1,037 |
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998 |
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3 |
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3 |
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1,040 |
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1,001 |
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Cutbank Ridge |
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|
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760 |
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654 |
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8 |
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1 |
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768 |
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655 |
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Bighorn |
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|
|
359 |
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272 |
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10 |
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5 |
|
369 |
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277 |
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Clearwater (2) |
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|
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8,771 |
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8,157 |
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149 |
|
98 |
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8,920 |
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8,255 |
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Other |
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|
|
475 |
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380 |
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104 |
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54 |
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579 |
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434 |
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Canadian Division |
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11,402 |
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10,461 |
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274 |
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161 |
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11,676 |
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10,622 |
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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).
EnCana Corporation |
|
Annual Information Form |
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 EnCanas 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 EnCanas 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 Corporation |
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Annual Information Form |
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 EnCanas 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, EnCanas 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 Divisions 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.
EnCana Corporation |
|
Annual Information Form |
The following tables summarize the USA Division landholdings, daily production and producing wells as at and for the periods indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Landholdings |
|
Developed |
|
|
Undeveloped |
|
|
Total |
|
Average |
|
||||||||||
(thousands of acres at December 31, 2009) |
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Interest |
|
||||||
Jonah |
|
18 |
|
16 |
|
125 |
|
111 |
|
143 |
|
127 |
|
89% |
|
||||||
Piceance |
|
253 |
|
235 |
|
699 |
|
634 |
|
952 |
|
869 |
|
91% |
|
||||||
East Texas |
|
102 |
|
71 |
|
224 |
|
196 |
|
326 |
|
267 |
|
82% |
|
||||||
Fort Worth |
|
63 |
|
58 |
|
29 |
|
18 |
|
92 |
|
76 |
|
83% |
|
||||||
Haynesville Shale |
|
71 |
|
50 |
|
570 |
|
379 |
|
641 |
|
429 |
|
67% |
|
||||||
Other |
|
242 |
|
153 |
|
1,881 |
|
1,539 |
|
2,123 |
|
1,692 |
|
80% |
|
||||||
USA Division |
|
749 |
|
583 |
|
3,528 |
|
2,877 |
|
4,277 |
|
3,460 |
|
81% |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Production |
|
|
|
Natural Gas |
|
|
Liquids |
|
|
Total |
|
||||||||||
(annual average) |
|
|
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
|
2009 |
|
|
2008 |
|
||||
Jonah |
|
|
|
571 |
|
603 |
|
5,067 |
|
5,273 |
|
|
601 |
|
|
635 |
|
||||
Piceance |
|
|
|
362 |
|
385 |
|
1,760 |
|
2,513 |
|
|
373 |
|
|
400 |
|
||||
East Texas |
|
|
|
324 |
|
334 |
|
57 |
|
134 |
|
|
324 |
|
|
335 |
|
||||
Fort Worth |
|
|
|
136 |
|
142 |
|
435 |
|
500 |
|
|
139 |
|
|
145 |
|
||||
Haynesville Shale |
|
|
|
70 |
|
9 |
|
132 |
|
64 |
|
|
71 |
|
|
10 |
|
||||
Other |
|
|
|
153 |
|
160 |
|
3,866 |
|
4,866 |
|
|
176 |
|
|
188 |
|
||||
USA Division |
|
|
|
1,616 |
|
1,633 |
|
11,317 |
|
13,350 |
|
|
1,684 |
|
|
1,713 |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Producing Wells |
|
|
|
|
|
|
|
|
|||||||||||||
|
|
|
|
Natural Gas |
|
|
Crude Oil |
|
|
Total |
|||||||||||
(number of wells at December 31, 2009) (1) |
|
|
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
|
||||||
Jonah |
|
|
|
1,127 |
|
992 |
|
- |
|
- |
|
1,127 |
|
992 |
|
||||||
Piceance |
|
|
|
2,921 |
|
2,557 |
|
3 |
|
- |
|
2,924 |
|
2,557 |
|
||||||
East Texas |
|
|
|
724 |
|
454 |
|
3 |
|
1 |
|
727 |
|
455 |
|
||||||
Fort Worth |
|
|
|
774 |
|
652 |
|
15 |
|
14 |
|
789 |
|
666 |
|
||||||
Haynesville Shale |
|
|
|
226 |
|
102 |
|
3 |
|
1 |
|
229 |
|
103 |
|
||||||
Other |
|
|
|
1,953 |
|
1,379 |
|
12 |
|
7 |
|
1,965 |
|
1,386 |
|
||||||
USA Division |
|
|
|
7,725 |
|
6,136 |
|
36 |
|
23 |
|
7,761 |
|
6,159 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Note:
(1) Figures exclude wells capable of producing, but not producing, as of December 31, 2009.
EnCana Corporation |
|
Annual Information Form |
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, EnCanas 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. EnCanas 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 groups Deep Bossier assets. Subsequently, in 2006, EnCana increased this interest to 50 percent. In November 2007, EnCana acquired the Leor Energy groups 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).
EnCana Corporation |
|
Annual Information Form |
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. EnCanas 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.
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
EnCana Corporation |
|
Annual Information Form |
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, EnCanas 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 refinerys 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 activities are managed by EnCanas Midstream, Marketing & Fundamentals Corporate Group. Market Optimization is focused on enhancing the netback price of the Corporations 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
EnCanas 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 EnCanas various risk management positions are found in Note 20 to EnCanas 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.
EnCana Corporation |
|
Annual Information Form |
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 EnCanas natural gas and liquids reserves annually. In 2009, EnCanas 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.
EnCanas Vice President, Corporate Reserves & Competitor Analysis and four other staff under this individuals 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 EnCanas 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.
EnCanas 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, EnCanas 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, EnCanas crude oil and natural gas liquids reserves decreased by approximately 77 percent and EnCanas bitumen reserves were divested, substantially all as a result of the Split Transaction.
EnCana Corporation |
|
Annual Information Form |
At year-end 2008, EnCanas 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 Corporations interests in Foster Creek and Christina Lake.
As at December 31, 2007, EnCanas 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 Corporations interests in Foster Creek and Christina Lake into the integrated oil business effective January 2, 2007. Subsequent to this transaction, EnCanas 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.
EnCana Corporation |
|
Annual Information Form |
Net Proved Reserves (EnCana Share After Royalties) (1,2)
Constant Pricing
|
|
Natural Gas |
|
|
Crude Oil and Natural Gas |
|
|
Bitumen (3) |
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
United |
|
Total |
|
|
Canada (4) |
|
United |
|
Total |
|
|
Canada |
|
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year |
|
7,028 |
|
5,390 |
|
12,418 |
|
|
279.8 |
|
54.0 |
|
333.8 |
|
|
799.6 |
|
|
Revisions and improved recovery |
|
87 |
|
78 |
|
165 |
|
|
12.8 |
|
3.6 |
|
16.4 |
|
|
62.7 |
|
|
Extensions and discoveries |
|
949 |
|
827 |
|
1,776 |
|
|
13.8 |
|
5.9 |
|
19.7 |
|
|
142.0 |
|
|
Purchase of reserves in place |
|
63 |
|
211 |
|
274 |
|
|
0.2 |
|
- |
|
0.2 |
|
|
- |
|
|
Sale of reserves in place |
|
(24) |
|
(7) |
|
(31) |
|
|
(0.2) |
|
- |
|
(0.2) |
|
|
(398.0 |
) (4) |
|
Production |
|
(811) |
|
(491) |
|
(1,302) |
|
|
(33.0) |
|
(5.2) |
|
(38.2) |
|
|
(10.8 |
) |
|
End of year |
|
7,292 |
|
6,008 |
|
13,300 |
|
|
273.4 |
|
58.3 |
|
331.7 |
|
|
595.5 |
|
|
Developed |
|
4,868 |
|
3,368 |
|
8,236 |
|
|
217.8 |
|
37.0 |
|
254.8 |
|
|
71.7 |
|
|
Undeveloped |
|
2,424 |
|
2,640 |
|
5,064 |
|
|
55.6 |
|
21.3 |
|
76.9 |
|
|
523.8 |
|
|
Total |
|
7,292 |
|
6,008 |
|
13,300 |
|
|
273.4 |
|
58.3 |
|
331.7 |
|
|
595.5 |
|
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year |
|
7,292 |
|
6,008 |
|
13,300 |
|
|
273.4 |
|
58.3 |
|
331.7 |
|
|
595.5 |
|
|
Revisions and improved recovery |
|
148 |
|
(166) |
|
(18) |
|
|
27.9 |
|
(3.6) |
|
24.3 |
|
|
84.9 |
|
|
Extensions and discoveries |
|
1,311 |
|
655 |
|
1,966 |
|
|
17.0 |
|
3.8 |
|
20.8 |
|
|
- |
|
|
Purchase of reserves in place |
|
32 |
|
7 |
|
39 |
|
|
0.2 |
|
0.0 |
|
0.2 |
|
|
- |
|
|
Sale of reserves in place |
|
(129) |
|
(75) |
|
(204) |
|
|
(0.9) |
|
(2.0) |
|
(2.9) |
|
|
- |
|
|
Production |
|
(807) |
|
(598) |
|
(1,405) |
|
|
(32.0) |
|
(4.9) |
|
(36.9) |
|
|
(12.0 |
) |
|
End of year |
|
7,847 |
|
5,831 |
|
13,678 |
|
|
285.6 |
|
51.6 |
|
337.2 |
|
|
668.4 |
|
|
Developed |
|
4,945 |
|
3,720 |
|
8,665 |
|
|
208.5 |
|
33.9 |
|
242.4 |
|
|
125.9 |
|
|
Undeveloped |
|
2,902 |
|
2,111 |
|
5,013 |
|
|
77.1 |
|
17.7 |
|
94.8 |
|
|
542.5 |
|
|
Total |
|
7,847 |
|
5,831 |
|
13,678 |
|
|
285.6 |
|
51.6 |
|
337.2 |
|
|
668.4 |
|
|
2009 (5) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year |
|
7,847 |
|
5,831 |
|
13,678 |
|
|
285.6 |
|
51.6 |
|
337.2 |
|
|
668.4 |
|
|
Revisions and improved recovery (6) |
|
(755) |
|
(845) |
|
(1,600) |
|
|
7.3 |
|
(12.6) |
|
(5.3) |
|
|
(87.6 |
) |
|
Extensions and discoveries |
|
726 |
|
1,406 |
|
2,132 |
|
|
12.5 |
|
6.5 |
|
19.0 |
|
|
159.4 |
|
|
Purchase of reserves in place |
|
28 |
|
- |
|
28 |
|
|
0.5 |
|
- |
|
0.5 |
|
|
- |
|
|
Sale of reserves in place (7) |
|
(1,772) |
|
(89) |
|
(1,861) |
|
|
(243.2) |
|
(0.2) |
|
(243.4) |
|
|
(725.1 |
) |
|
Production |
|
(725) |
|
(590) |
|
(1,315) |
|
|
(27.2) |
|
(4.1) |
|
(31.3) |
|
|
(15.1 |
) |
|
End of year |
|
5,349 |
|
5,713 |
|
11,062 |
|
|
35.5 |
|
41.2 |
|
76.7 |
|
|
- |
|
|
Developed |
|
2,927 |
|
3,571 |
|
6,498 |
|
|
25.1 |
|
25.8 |
|
50.9 |
|
|
- |
|
|
Undeveloped |
|
2,422 |
|
2,142 |
|
4,564 |
|
|
10.4 |
|
15.4 |
|
25.8 |
|
|
- |
|
|
Total |
|
5,349 |
|
5,713 |
|
11,062 |
|
|
35.5 |
|
41.2 |
|
76.7 |
|
|
- |
|
|
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.
EnCana Corporation |
|
Annual Information Form |
(3) EnCanas 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 EnCanas 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
EnCanas 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 EnCanas 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 EnCanas 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.
|
|
Natural Gas |
|
|
Crude Oil and Natural Gas Liquids (millions of barrels) |
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
United |
|
Total |
|
|
Canada |
|
United |
|
Total |
|
|
Price Case |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEC case |
|
5,349 |
|
5,713 |
|
11,062 |
|
|
35.5 |
|
41.2 |
|
76.7 |
|
|
Business case |
|
5,675 |
|
6,605 |
|
12,280 |
|
|
37.2 |
|
45.1 |
|
82.3 |
|
|
Difference versus SEC case |
|
6.1% |
|
15.6% |
|
11.0% |
|
|
4.9% |
|
9.5% |
|
7.4% |
|
|
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.
EnCana Corporation |
|
Annual Information Form |
The following tables summarize the net daily average production volumes for EnCana for the periods indicated.
Production Volumes by Current Divisions |
|
2009 |
||||||||||
|
|
Annual |
|
Q4 |
|
Q3 |
|
Q2 |
|
Q1 |
|
|
Produced Gas (MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Division (1) |
|
1,224 |
|
1,071 |
|
1,201 |
|
1,343 |
|
1,281 |
|
|
USA Division |
|
1,616 |
|
1,616 |
|
1,524 |
|
1,581 |
|
1,746 |
|
|
|
|
2,840 |
|
2,687 |
|
2,725 |
|
2,924 |
|
3,027 |
|
|
Liquids (bbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Division (1) |
|
15,880 |
|
12,477 |
|
15,909 |
|
17,624 |
|
17,567 |
|
|
USA Division |
|
11,317 |
|
11,586 |
|
10,325 |
|
11,699 |
|
11,671 |
|
|
|
|
27,197 |
|
24,063 |
|
26,234 |
|
29,323 |
|
29,238 |
|
|
Total Canadian & USA Divisions (MMcfe/d) |
|
3,003 |
|
2,831 |
|
2,883 |
|
3,100 |
|
3,203 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Division Total (1) (MMcfe/d) |
|
1,319 |
|
1,145 |
|
1,297 |
|
1,449 |
|
1,387 |
|
|
USA Division Total (MMcfe/d) |
|
1,684 |
|
1,686 |
|
1,586 |
|
1,651 |
|
1,816 |
|
|
|
|
3,003 |
|
2,831 |
|
2,883 |
|
3,100 |
|
3,203 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Production Volumes by Country |
|
2009 |
||||||||||
|
|
Annual |
|
Q4 |
|
Q3 |
|
Q2 |
|
Q1 |
|
|
Produced Gas (MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
|
Canada (2) |
|
1,986 |
|
1,588 |
|
2,027 |
|
2,207 |
|
2,123 |
|
|
United States |
|
1,616 |
|
1,616 |
|
1,524 |
|
1,581 |
|
1,746 |
|
|
|
|
3,602 |
|
3,204 |
|
3,551 |
|
3,788 |
|
3,869 |
|
|
Liquids (bbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
Canada (2) |
|
115,780 |
|
87,859 |
|
128,937 |
|
123,954 |
|
122,609 |
|
|
United States |
|
11,317 |
|
11,586 |
|
10,325 |
|
11,699 |
|
11,671 |
|
|
|
|
127,097 |
|
99,445 |
|
139,262 |
|
135,653 |
|
134,280 |
|
|
Total EnCana (MMcfe/d) |
|
|
|
|
|
|
|
|
|
|
|
|
Canada (2) |
|
2,681 |
|
2,115 |
|
2,801 |
|
2,951 |
|
2,859 |
|
|
United States |
|
1,684 |
|
1,686 |
|
1,586 |
|
1,651 |
|
1,816 |
|
|
|
|
4,365 |
|
3,801 |
|
4,387 |
|
4,602 |
|
4,675 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total EnCana (BOE/d) |
|
|
|
|
|
|
|
|
|
|
|
|
Canada (2) |
|
446,780 |
|
352,526 |
|
466,770 |
|
491,787 |
|
476,442 |
|
|
United States |
|
280,650 |
|
280,919 |
|
264,325 |
|
275,199 |
|
302,671 |
|
|
|
|
727,430 |
|
633,445 |
|
731,095 |
|
766,986 |
|
779,113 |
|
|
Notes:
(1) Excludes results for Canada Other (former Canadian Plains and former Integrated Oil Canada operations). These operations were transferred to Cenovus as part of the Split Transaction.
(2) Results prior to November 30, 2009 include production from Canada Other.
EnCana Corporation |
|
Annual Information Form |
Production Volumes by Current Divisions |
|
Annual Average |
|||
|
|
2008 |
|
2007 |
|
Produced Gas (MMcf/d) |
|
|
|
|
|
Canadian Division (1) |
|
1,300 |
|
1,255 |
|
USA Division |
|
1,633 |
|
1,345 |
|
|
|
2,933 |
|
2,600 |
|
Liquids (bbls/d) |
|
|
|
|
|
Canadian Division (1) |
|
19,980 |
|
18,272 |
|
USA Division |
|
13,350 |
|
14,180 |
|
|
|
33,330 |
|
32,452 |
|
Total Canadian & USA Divisions (MMcfe/d) |
|
3,132 |
|
2,795 |
|
|
|
|
|
|
|
Canadian Division Total (1) (MMcfe/d) |
|
1,419 |
|
1,365 |
|
USA Division Total (MMcfe/d) |
|
1,713 |
|
1,430 |
|
|
|
3,132 |
|
2,795 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Volumes by Country |
|
Annual Average |
|||
|
|
2008 |
|
2007 |
|
Produced Gas (MMcf/d) |
|
|
|
|
|
Canada (2) |
|
2,205 |
|
2,221 |
|
United States |
|
1,633 |
|
1,345 |
|
|
|
3,838 |
|
3,566 |
|
Liquids (bbls/d) |
|
|
|
|
|
Canada (2) |
|
120,230 |
|
119,974 |
|
United States |
|
13,350 |
|
14,180 |
|
|
|
133,580 |
|
134,154 |
|
Total EnCana (MMcfe/d) |
|
|
|
|
|
Canada (2) |
|
2,926 |
|
2,941 |
|
United States |
|
1,713 |
|
1,430 |
|
|
|
4,639 |
|
4,371 |
|
|
|
|
|
|
|
Total EnCana (BOE/d) |
|
|
|
|
|
Canada (2) |
|
487,730 |
|
490,141 |
|
United States |
|
285,517 |
|
238,347 |
|
|
|
773,247 |
|
728,488 |
|
Notes:
(1) Excludes results for Canada Other (former Canadian Plains and former Integrated Oil Canada operations). These operations were transferred to Cenovus as part of the Split Transaction.
(2) Results prior to November 30, 2009 include production from Canada Other.
The following tables summarize the net per-unit results for EnCana for the periods indicated, which exclude the impact of realized hedging.
EnCana Corporation |
|
Annual Information Form |
Netbacks by Current Divisions |
2009 |
||||||||||
|
|
Annual |
|
Q4 |
|
Q3 |
|
Q2 |
|
Q1 |
|
Produced Gas ($/Mcf) |
|
|
|
|
|
|
|
|
|
|
|
Canadian Division (1) |
|
|
|
|
|
|
|
|
|
|
|
Price |
|
3.71 |
|
4.21 |
|
2.92 |
|
3.19 |
|
4.58 |
|
Production and mineral taxes |
|
0.03 |
|
- |
|
0.02 |
|
0.04 |
|
0.03 |
|
Transportation and selling |
|
0.33 |
|
0.40 |
|
0.35 |
|
0.30 |
|
0.30 |
|
Operating |
|
1.13 |
|
1.43 |
|
1.09 |
|
1.02 |
|
1.04 |
|
|
|
2.22 |
|
2.38 |
|
1.46 |
|
1.83 |
|
3.21 |
|
USA Division |
|
|
|
|
|
|
|
|
|
|
|
Price |
|
3.75 |
|
4.64 |
|
3.41 |
|
3.01 |
|
3.88 |
|
Production and mineral taxes |
|
0.17 |
|
0.23 |
|
0.08 |
|
0.08 |
|
0.27 |
|
Transportation and selling |
|
0.90 |
|
0.96 |
|
0.99 |
|
0.87 |
|
0.78 |
|
Operating |
|
0.55 |
|
0.61 |
|
0.56 |
|
0.54 |
|
0.51 |
|
|
|
2.13 |
|
2.84 |
|
1.78 |
|
1.52 |
|
2.32 |
|
Total Canadian & USA Divisions |
|
|
|
|
|
|
|
|
|
|
|
Price |
|
3.73 |
|
4.47 |
|
3.19 |
|
3.09 |
|
4.18 |
|
Production and mineral taxes |
|
0.11 |
|
0.14 |
|
0.06 |
|
0.06 |
|
0.17 |
|
Transportation and selling |
|
0.66 |
|
0.74 |
|
0.71 |
|
0.61 |
|
0.58 |
|
Operating |
|
0.80 |
|
0.93 |
|
0.79 |
|
0.76 |
|
0.74 |
|
|
|
2.16 |
|
2.66 |
|
1.63 |
|
1.66 |
|
2.69 |
|
Liquids ($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
Canadian Division (1) |
|
|
|
|
|
|
|
|
|
|
|
Price |
|
47.86 |
|
60.37 |
|
52.48 |
|
45.86 |
|
36.51 |
|
Production and mineral taxes |
|
0.45 |
|
0.34 |
|
0.48 |
|
0.47 |
|
0.47 |
|
Transportation and selling |
|
1.06 |
|
0.49 |
|
1.41 |
|
0.62 |
|
1.61 |
|
Operating |
|
3.62 |
|
3.25 |
|
3.04 |
|
4.09 |
|
3.94 |
|
|
|
42.73 |
|
56.29 |
|
47.55 |
|
40.68 |
|
30.49 |
|
USA Division |
|
|
|
|
|
|
|
|
|
|
|
Price |
|
48.56 |
|
64.39 |
|
55.60 |
|
47.27 |
|
27.43 |
|
Production and mineral taxes |
|
4.39 |
|
5.84 |
|
5.12 |
|
4.18 |
|
2.48 |
|
Transportation and selling |
|
- |
|
- |
|
- |
|
- |
|
- |
|
Operating |
|
- |
|
- |
|
- |
|
- |
|
- |
|
|
|
44.17 |
|
58.55 |
|
50.48 |
|
43.09 |
|
24.95 |
|
Total Canadian & USA Divisions |
|
|
|
|
|
|
|
|
|
|
|
Price |
|
48.15 |
|
62.31 |
|
53.71 |
|
46.42 |
|
32.88 |
|
Production and mineral taxes |
|
2.09 |
|
2.99 |
|
2.31 |
|
1.95 |
|
1.27 |
|
Transportation and selling |
|
0.62 |
|
0.26 |
|
0.85 |
|
0.38 |
|
0.96 |
|
Operating |
|
2.11 |
|
1.68 |
|
1.84 |
|
2.46 |
|
2.37 |
|
|
|
43.33 |
|
57.38 |
|
48.71 |
|
41.63 |
|
28.28 |
|
Total Netback ($/Mcfe) |
|
|
|
|
|
|
|
|
|
|
|
Canadian Division (1) |
|
|
|
|
|
|
|
|
|
|
|
Price |
|
4.02 |
|
4.59 |
|
3.36 |
|
3.51 |
|
4.70 |
|
Production and mineral taxes |
|
0.03 |
|
0.01 |
|
0.02 |
|
0.04 |
|
0.04 |
|
Transportation and selling |
|
0.32 |
|
0.38 |
|
0.34 |
|
0.28 |
|
0.30 |
|
Operating |
|
1.09 |
|
1.37 |
|
1.05 |
|
0.99 |
|
1.01 |
|
|
|
2.58 |
|
2.83 |
|
1.95 |
|
2.20 |
|
3.35 |
|
USA Division |
|
|
|
|
|
|
|
|
|
|
|
Price |
|
3.92 |
|
4.89 |
|
3.64 |
|
3.21 |
|
3.91 |
|
Production and mineral taxes |
|
0.19 |
|
0.26 |
|
0.11 |
|
0.10 |
|
0.28 |
|
Transportation and selling |
|
0.86 |
|
0.92 |
|
0.95 |
|
0.83 |
|
0.75 |
|
Operating |
|
0.53 |
|
0.58 |
|
0.54 |
|
0.52 |
|
0.49 |
|
|
|
2.34 |
|
3.13 |
|
2.04 |
|
1.76 |
|
2.39 |
|
Total Canadian & USA Divisions |
|
|
|
|
|
|
|
|
|
|
|
Price |
|
3.96 |
|
4.77 |
|
3.51 |
|
3.35 |
|
4.25 |
|
Production and mineral taxes |
|
0.12 |
|
0.16 |
|
0.07 |
|
0.08 |
|
0.17 |
|
Transportation and selling |
|
0.63 |
|
0.70 |
|
0.68 |
|
0.58 |
|
0.56 |
|
Operating |
|
0.78 |
|
0.90 |
|
0.76 |
|
0.74 |
|
0.72 |
|
|
|
2.43 |
|
3.01 |
|
2.00 |
|
1.95 |
|
2.80 |
|
Note:
(1) Excludes results for Canada Other (former Canadian Plains and former Integrated Oil Canada operations). These operations were transferred to Cenovus as part of the Split Transaction.
EnCana Corporation |
|
Annual Information Form |
Netbacks by Country |
|
2009 |
|||||||||
|
|
Annual |
|
Q4 |
|
Q3 |
|
Q2 |
|
Q1 |
|
Produced Gas ($/Mcf) |
|
|
|
|
|
|
|
|
|
|
|
Canada (1) |
|
|
|
|
|
|
|
|
|
|
|
Price |
|
3.64 |
|
4.02 |
|
2.89 |
|
3.20 |
|
4.51 |
|
Production and mineral taxes |
|
0.04 |
|
0.03 |
|
0.03 |
|
0.05 |
|
0.04 |
|
Transportation and selling |
|
0.26 |
|
0.31 |
|
0.26 |
|
0.23 |
|
0.24 |
|
Operating |
|
0.98 |
|
1.17 |
|
0.96 |
|
0.89 |
|
0.94 |
|
|
|
2.36 |
|
2.51 |
|
1.64 |
|
2.03 |
|
3.29 |
|
United States |
|
|
|
|
|
|
|
|
|
|
|
Price |
|
3.75 |
|
4.64 |
|
3.41 |
|
3.01 |
|
3.88 |
|
Production and mineral taxes |
|
0.17 |
|
0.23 |
|
0.08 |
|
0.08 |
|
0.27 |
|
Transportation and selling |
|
0.90 |
|
0.96 |
|
0.99 |
|
0.87 |
|
0.78 |
|
Operating |
|
0.55 |
|
0.61 |
|
0.56 |
|
0.54 |
|
0.51 |
|
|
|
2.13 |
|
2.84 |
|
1.78 |
|
1.52 |
|
2.32 |
|
Total EnCana |
|
|
|
|
|
|
|
|
|
|
|
Price |
|
3.69 |
|
4.34 |
|
3.11 |
|
3.12 |
|
4.23 |
|
Production and mineral taxes |
|
0.10 |
|
0.13 |
|
0.05 |
|
0.06 |
|
0.14 |
|
Transportation and selling |
|
0.55 |
|
0.64 |
|
0.58 |
|
0.50 |
|
0.49 |
|
Operating |
|
0.79 |
|
0.89 |
|
0.78 |
|
0.75 |
|
0.75 |
|
|
|
2.25 |
|
2.68 |
|
1.70 |
|
1.81 |
|
2.85 |
|
Liquids ($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
Canada (1) |
|
|
|
|
|
|
|
|
|
|
|
Price |
|
49.75 |
|
61.96 |
|
57.54 |
|
49.31 |
|
32.48 |
|
Production and mineral taxes |
|
0.63 |
|
0.55 |
|
0.62 |
|
0.57 |
|
0.77 |
|
Transportation and selling |
|
1.53 |
|
1.14 |
|
1.66 |
|
1.69 |
|
1.50 |
|
Operating |
|
9.21 |
|
9.56 |
|
8.96 |
|
9.16 |
|
9.29 |
|
|
|
38.38 |
|
50.71 |
|
46.30 |
|
37.89 |
|
20.92 |
|
United States |
|
|
|
|
|
|
|
|
|
|
|
Price |
|
48.56 |
|
64.39 |
|
55.60 |
|
47.27 |
|
27.43 |
|
Production and mineral taxes |
|
4.39 |
|
5.84 |
|
5.12 |
|
4.18 |
|
2.48 |
|
Transportation and selling |
|
- |
|
- |
|
- |
|
- |
|
- |
|
Operating |
|
- |
|
- |
|
- |
|
- |
|
- |
|
|
|
44.17 |
|
58.55 |
|
50.48 |
|
43.09 |
|
24.95 |
|
Total EnCana |
|
|
|
|
|
|
|
|
|
|
|
Price |
|
49.65 |
|
62.25 |
|
57.40 |
|
49.14 |
|
32.03 |
|
Production and mineral taxes |
|
0.97 |
|
1.18 |
|
0.95 |
|
0.88 |
|
0.92 |
|
Transportation and selling |
|
1.39 |
|
1.01 |
|
1.54 |
|
1.55 |
|
1.36 |
|
Operating |
|
8.39 |
|
8.43 |
|
8.30 |
|
8.38 |
|
8.46 |
|
|
|
38.90 |
|
51.63 |
|
46.61 |
|
38.33 |
|
21.29 |
|
Total Netback ($/Mcfe) |
|
|
|
|
|
|
|
|
|
|
|
Canada (1) |
|
|
|
|
|
|
|
|
|
|
|
Price |
|
4.84 |
|
5.59 |
|
4.78 |
|
4.47 |
|
4.74 |
|
Production and mineral taxes |
|
0.05 |
|
0.04 |
|
0.05 |
|
0.06 |
|
0.06 |
|
Transportation and selling |
|
0.26 |
|
0.28 |
|
0.27 |
|
0.25 |
|
0.24 |
|
Operating |
|
1.12 |
|
1.27 |
|
1.11 |
|
1.05 |
|
1.09 |
|
|
|
3.41 |
|
4.00 |
|
3.35 |
|
3.11 |
|
3.35 |
|
United States |
|
|
|
|
|
|
|
|
|
|
|
Price |
|
3.92 |
|
4.89 |
|
3.64 |
|
3.21 |
|
3.91 |
|
Production and mineral taxes |
|
0.19 |
|
0.26 |
|
0.11 |
|
0.10 |
|
0.28 |
|
Transportation and selling |
|
0.86 |
|
0.92 |
|
0.95 |
|
0.83 |
|
0.75 |
|
Operating |
|
0.53 |
|
0.58 |
|
0.54 |
|
0.52 |
|
0.49 |
|
|
|
2.34 |
|
3.13 |
|
2.04 |
|
1.76 |
|
2.39 |
|
Total EnCana |
|
|
|
|
|
|
|
|
|
|
|
Price |
|
4.49 |
|
5.28 |
|
4.36 |
|
4.02 |
|
4.42 |
|
Production and mineral taxes |
|
0.11 |
|
0.14 |
|
0.07 |
|
0.08 |
|
0.15 |
|
Transportation and selling |
|
0.49 |
|
0.57 |
|
0.52 |
|
0.46 |
|
0.44 |
|
Operating |
|
0.89 |
|
0.97 |
|
0.90 |
|
0.86 |
|
0.86 |
|
|
|
3.00 |
|
3.60 |
|
2.87 |
|
2.62 |
|
2.97 |
|
Note:
(1) Results prior to November 30, 2009 include production from Canada Other (former Canadian Plains and former Integrated Oil Canada operations). These operations were transferred to Cenovus as part of the Split Transaction.
EnCana Corporation |
|
Annual Information Form |
Netbacks by Current Divisions |
|
Annual Average |
|||
|
|
2008 |
|
2007 |
|
Produced Gas ($/Mcf) |
|
|
|
|
|
Canadian Division (1) |
|
|
|
|
|
Price |
|
8.12 |
|
6.30 |
|
Production and mineral taxes |
|
0.06 |
|
0.08 |
|
Transportation and selling |
|
0.42 |
|
0.42 |
|
Operating |
|
1.15 |
|
1.05 |
|
|
|
6.49 |
|
4.75 |
|
USA Division |
|
|
|
|
|
Price |
|
7.89 |
|
5.38 |
|
Production and mineral taxes |
|
0.56 |
|
0.34 |
|
Transportation and selling |
|
0.84 |
|
0.62 |
|
Operating |
|
0.59 |
|
0.65 |
|
|
|
5.90 |
|
3.77 |
|
Total Canadian & USA Divisions |
|
|
|
|
|
Price |
|
7.99 |
|
5.82 |
|
Production and mineral taxes |
|
0.34 |
|
0.21 |
|
Transportation and selling |
|
0.66 |
|
0.53 |
|
Operating |
|
0.84 |
|
0.84 |
|
|
|
6.15 |
|
4.24 |
|
Liquids ($/bbl) |
|
|
|
|
|
Canadian Division (1) |
|
|
|
|
|
Price |
|
85.12 |
|
61.73 |
|
Production and mineral taxes |
|
0.63 |
|
0.47 |
|
Transportation and selling |
|
1.64 |
|
1.43 |
|
Operating |
|
5.41 |
|
4.88 |
|
|
|
77.44 |
|
54.95 |
|
USA Division |
|
|
|
|
|
Price |
|
83.18 |
|
59.83 |
|
Production and mineral taxes |
|
7.25 |
|
4.28 |
|
Transportation and selling |
|
- |
|
0.01 |
|
Operating |
|
- |
|
- |
|
|
|
75.93 |
|
55.54 |
|
Total Canadian & USA Divisions |
|
|
|
|
|
Price |
|
84.38 |
|
60.90 |
|
Production and mineral taxes |
|
3.27 |
|
2.12 |
|
Transportation and selling |
|
0.98 |
|
0.81 |
|
Operating |
|
3.40 |
|
3.08 |
|
|
|
76.73 |
|
54.89 |
|
Total Netback ($/Mcfe) |
|
|
|
|
|
Canadian Division (1) |
|
|
|
|
|
Price |
|
8.63 |
|
6.62 |
|
Production and mineral taxes |
|
0.06 |
|
0.08 |
|
Transportation and selling |
|
0.41 |
|
0.40 |
|
Operating |
|
1.13 |
|
1.03 |
|
|
|
7.03 |
|
5.11 |
|
USA Division |
|
|
|
|
|
Price |
|
8.17 |
|
5.65 |
|
Production and mineral taxes |
|
0.59 |
|
0.36 |
|
Transportation and selling |
|
0.80 |
|
0.59 |
|
Operating |
|
0.56 |
|
0.62 |
|
|
|
6.22 |
|
4.08 |
|
Total Canadian & USA Divisions |
|
|
|
|
|
Price |
|
8.38 |
|
6.12 |
|
Production and mineral taxes |
|
0.35 |
|
0.22 |
|
Transportation and selling |
|
0.62 |
|
0.50 |
|
Operating |
|
0.82 |
|
0.82 |
|
|
|
6.59 |
|
4.58 |
|
Note:
(1) Excludes results for Canada Other (former Canadian Plains and former Integrated Oil Canada operations). These operations were transferred to Cenovus as part of the Split Transaction.
EnCana Corporation |
|
Annual Information Form |
Netbacks by Country |
|
Annual Average |
|||
|
|
2008 |
|
2007 |
|
Produced Gas ($/Mcf) |
|
|
|
|
|
Canada (1) |
|
|
|
|
|
Price |
|
7.97 |
|
6.20 |
|
Production and mineral taxes |
|
0.08 |
|
0.09 |
|
Transportation and selling |
|
0.35 |
|
0.35 |
|
Operating |
|
1.03 |
|
0.92 |
|
|
|
6.51 |
|
4.84 |
|
United States |
|
|
|
|
|
Price |
|
7.89 |
|
5.38 |
|
Production and mineral taxes |
|
0.56 |
|
0.34 |
|
Transportation and selling |
|
0.84 |
|
0.62 |
|
Operating |
|
0.59 |
|
0.65 |
|
|
|
5.90 |
|
3.77 |
|
Total EnCana |
|
|
|
|
|
Price |
|
7.94 |
|
5.89 |
|
Production and mineral taxes |
|
0.28 |
|
0.18 |
|
Transportation and selling |
|
0.56 |
|
0.45 |
|
Operating |
|
0.84 |
|
0.82 |
|
|
|
6.26 |
|
4.44 |
|
Liquids ($/bbl) |
|
|
|
|
|
Canada (1) |
|
|
|
|
|
Price |
|
75.85 |
|
48.92 |
|
Production and mineral taxes |
|
1.01 |
|
0.72 |
|
Transportation and selling |
|
1.70 |
|
1.68 |
|
Operating |
|
10.57 |
|
9.47 |
|
|
|
62.57 |
|
37.05 |
|
United States |
|
|
|
|
|
Price |
|
83.18 |
|
59.83 |
|
Production and mineral taxes |
|
7.25 |
|
4.28 |
|
Transportation and selling |
|
- |
|
0.01 |
|
Operating |
|
- |
|
- |
|
|
|
75.93 |
|
55.54 |
|
Total EnCana |
|
|
|
|
|
Price |
|
76.58 |
|
50.05 |
|
Production and mineral taxes |
|
1.63 |
|
1.08 |
|
Transportation and selling |
|
1.53 |
|
1.51 |
|
Operating |
|
9.55 |
|
8.57 |
|
|
|
63.87 |
|
38.89 |
|
Total Netback ($/Mcfe) |
|
|
|
|
|
Canada (1) |
|
|
|
|
|
Price |
|
9.13 |
|
6.69 |
|
Production and mineral taxes |
|
0.10 |
|
0.09 |
|
Transportation and selling |
|
0.33 |
|
0.33 |
|
Operating |
|
1.21 |
|
1.08 |
|
|
|
7.49 |
|
5.19 |
|
United States |
|
|
|
|
|
Price |
|
8.17 |
|
5.65 |
|
Production and mineral taxes |
|
0.59 |
|
0.36 |
|
Transportation and selling |
|
0.80 |
|
0.59 |
|
Operating |
|
0.56 |
|
0.62 |
|
|
|
6.22 |
|
4.08 |
|
Total EnCana |
|
|
|
|
|
Price |
|
8.77 |
|
6.35 |
|
Production and mineral taxes |
|
0.28 |
|
0.18 |
|
Transportation and selling |
|
0.50 |
|
0.42 |
|
Operating |
|
0.97 |
|
0.93 |
|
|
|
7.02 |
|
4.82 |
|
Note:
(1) Results prior to November 30, 2009 include production from Canada Other (former Canadian Plains and former Integrated Oil Canada operations). These operations were transferred to Cenovus as part of the Split Transaction.
EnCana Corporation |
|
Annual Information Form |
The following tables summarize the impact of realized hedging on EnCanas netbacks.
Impact of Realized Hedging on EnCanas Canadian & USA Divisions Netbacks (1)
|
2009 |
||||||||||
|
|
Annual |
|
Q4 |
|
Q3 |
|
Q2 |
|
Q1 |
|
Natural Gas ($/Mcf) |
|
3.30 |
|
1.97 |
|
4.25 |
|
3.93 |
|
3.04 |
|
Liquids ($/bbl) |
|
(0.01) |
|
- |
|
- |
|
- |
|
(0.03) |
|
Total ($/Mcfe) |
|
3.12 |
|
1.87 |
|
4.02 |
|
3.70 |
|
2.87 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Annual Average |
|||
|
|
|
|
|
|
|
|
2008 |
|
2007 |
|
Natural Gas ($/Mcf) |
|
|
|
|
|
|
|
0.07 |
|
1.55 |
|
Liquids ($/bbl) |
|
|
|
|
|
|
|
(3.65) |
|
(1.90) |
|
Total ($/Mcfe) |
|
|
|
|
|
|
|
0.03 |
|
1.42 |
|
Impact of Realized Hedging on EnCanas Total Netbacks (2)
|
|
2009 |
|||||||||
|
|
Annual |
|
Q4 |
|
Q3 |
|
Q2 |
|
Q1 |
|
Natural Gas ($/Mcf) |
|
3.33 |
|
2.11 |
|
4.20 |
|
3.87 |
|
2.99 |
|
Liquids ($/bbl) |
|
0.83 |
|
(0.14) |
|
(0.01) |
|
1.09 |
|
2.21 |
|
Total ($/Mcfe) |
|
2.77 |
|
1.78 |
|
3.39 |
|
3.21 |
|
2.55 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
Annual Average |
|||
|
|
|
|
|
|
|
|
2008 |
|
2007 |
|
Natural Gas ($/Mcf) |
|
|
|
|
|
|
|
(0.02) |
|
1.33 |
|
Liquids ($/bbl) |
|
|
|
|
|
|
|
(5.46) |
|
(3.05) |
|
Total ($/Mcfe) |
|
|
|
|
|
|
|
(0.17) |
|
0.99 |
|
Notes:
(1) Excludes results for Canada Other (former Canadian Plains and former Integrated Oil Canada operations). These operations were transferred to Cenovus as part of the Split Transaction.
(2) Results prior to November 30, 2009, include production from Canada Other.
EnCana Corporation |
|
Annual Information Form |
The following tables summarize EnCanas gross participation and net interest in wells drilled for the periods indicated.
Exploration Wells Drilled (1,2)
|
|
Gas |
|
Oil |
|
Dry & |
|
Total |
|
Royalty |
|
Total |
|||||||||||
|
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Gross |
|
Net |
|
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Division |
|
34 |
|
24 |
|
1 |
|
1 |
|
- |
|
- |
|
35 |
|
25 |
|
25 |
|
60 |
|
25 |
|
USA Division |
|
8 |
|
4 |
|
- |
|
- |
|
1 |
|
- |
|
9 |
|
4 |
|
- |
|
9 |
|
4 |
|
|
|
42 |
|
28 |
|
1 |
|
1 |
|
1 |
|
- |
|
44 |
|
29 |
|
25 |
|
69 |
|
29 |
|
Canada Other (3) |
|
- |
|
- |
|
4 |
|
4 |
|
- |
|
- |
|
4 |
|
4 |
|
8 |
|
12 |
|
4 |
|
Other |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
Total |
|
42 |
|
28 |
|
5 |
|
5 |
|
1 |
|
- |
|
48 |
|
33 |
|
33 |
|
81 |
|
33 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Division |
|
70 |
|
54 |
|
8 |
|
5 |
|
- |
|
- |
|
78 |
|
59 |
|
69 |
|
147 |
|
59 |
|
USA Division |
|
26 |
|
14 |
|
- |
|
- |
|
- |
|
- |
|
26 |
|
14 |
|
- |
|
26 |
|
14 |
|
|
|
96 |
|
68 |
|
8 |
|
5 |
|
- |
|
- |
|
104 |
|
73 |
|
69 |
|
173 |
|
73 |
|
Canada Other (3) |
|
5 |
|
3 |
|
1 |
|
1 |
|
2 |
|
1 |
|
8 |
|
5 |
|
34 |
|
42 |
|
5 |
|
Other |
|
- |
|
- |
|
- |
|
- |
|
3 |
|
1 |
|
3 |
|
1 |
|
- |
|
3 |
|
1 |
|
Total |
|
101 |
|
71 |
|
9 |
|
6 |
|
5 |
|
2 |
|
115 |
|
79 |
|
103 |
|
218 |
|
79 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Division |
|
116 |
|
92 |
|
4 |
|
3 |
|
- |
|
- |
|
120 |
|
95 |
|
91 |
|
211 |
|
95 |
|
USA Division |
|
2 |
|
2 |
|
- |
|
- |
|
- |
|
- |
|
2 |
|
2 |
|
- |
|
2 |
|
2 |
|
|
|
118 |
|
94 |
|
4 |
|
3 |
|
- |
|
- |
|
122 |
|
97 |
|
91 |
|
213 |
|
97 |
|
Canada Other (3) |
|
4 |
|
4 |
|
3 |
|
3 |
|
- |
|
- |
|
7 |
|
7 |
|
89 |
|
96 |
|
7 |
|
Other |
|
- |
|
- |
|
- |
|
- |
|
4 |
|
3 |
|
4 |
|
3 |
|
- |
|
4 |
|
3 |
|
Total |
|
122 |
|
98 |
|
7 |
|
6 |
|
4 |
|
3 |
|
133 |
|
107 |
|
180 |
|
313 |
|
107 |
|
Notes:
(1) Gross wells are the total number of wells in which EnCana has an interest.
(2) Net wells are the number of wells obtained by aggregating EnCanas working interest in each of its gross wells.
(3) Includes wells drilled from Canada Other (former Canadian Plains and former Integrated Oil Canada assets). These assets were transferred to Cenovus as part of the November 30, 2009 Split Transaction.
EnCana Corporation |
|
Annual Information Form |
Development Wells Drilled (1,2)
|
|
Gas |
|
Oil |
|
Dry & |
|
Total |
|
Royalty |
|
Total |
|
||||||||||
|
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Gross |
|
Net |
|
2009 (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Division |
|
731 |
|
672 |
|
3 |
|
2 |
|
- |
|
- |
|
734 |
|
674 |
|
143 |
|
877 |
|
674 |
|
USA Division |
|
495 |
|
382 |
|
- |
|
- |
|
5 |
|
4 |
|
500 |
|
386 |
|
55 |
|
555 |
|
386 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,226 |
|
1,054 |
|
3 |
|
2 |
|
5 |
|
4 |
|
1,234 |
|
1,060 |
|
198 |
|
1,432 |
|
1,060 |
|
Canada Other (4) |
|
560 |
|
507 |
|
144 |
|
120 |
|
8 |
|
8 |
|
712 |
|
635 |
|
255 |
|
967 |
|
635 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
1,786 |
|
1,561 |
|
147 |
|
122 |
|
13 |
|
12 |
|
1,946 |
|
1,695 |
|
453 |
|
2,399 |
|
1,695 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Division |
|
1,088 |
|
989 |
|
17 |
|
16 |
|
- |
|
- |
|
1,105 |
|
1,005 |
|
329 |
|
1,434 |
|
1,005 |
|
USA Division |
|
904 |
|
736 |
|
- |
|
- |
|
- |
|
- |
|
904 |
|
736 |
|
378 |
|
1,282 |
|
736 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,992 |
|
1,725 |
|
17 |
|
16 |
|
- |
|
- |
|
2,009 |
|
1,741 |
|
707 |
|
2,716 |
|
1,741 |
|
Canada Other (4) |
|
1,502 |
|
1,385 |
|
146 |
|
113 |
|
11 |
|
11 |
|
1,659 |
|
1,509 |
|
544 |
|
2,203 |
|
1,509 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
3,494 |
|
3,110 |
|
163 |
|
129 |
|
11 |
|
11 |
|
3,668 |
|
3,250 |
|
1,251 |
|
4,919 |
|
3,250 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Division |
|
1,528 |
|
1,425 |
|
20 |
|
18 |
|
1 |
|
1 |
|
1,549 |
|
1,444 |
|
325 |
|
1,874 |
|
1,444 |
|
USA Division |
|
809 |
|
641 |
|
- |
|
- |
|
1 |
|
1 |
|
810 |
|
642 |
|
36 |
|
846 |
|
642 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,337 |
|
2,066 |
|
20 |
|
18 |
|
2 |
|
2 |
|
2,359 |
|
2,086 |
|
361 |
|
2,720 |
|
2,086 |
|
Canada Other (4) |
|
2,221 |
|
2,117 |
|
216 |
|
167 |
|
10 |
|
7 |
|
2,447 |
|
2,291 |
|
509 |
|
2,956 |
|
2,291 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
4,558 |
|
4,183 |
|
236 |
|
185 |
|
12 |
|
9 |
|
4,806 |
|
4,377 |
|
870 |
|
5,676 |
|
4,377 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes: |
|||
|
(1) |
|
Gross wells are the total number of wells in which EnCana has an interest. |
|
(2) |
|
Net wells are the number of wells obtained by aggregating EnCanas working interest in each of its gross wells. |
|
(3) |
|
At December 31, 2009, EnCana was in the process of drilling the following exploratory and development wells: approximately 5 gross wells (5 net wells) in Canada and approximately 60 gross wells (48 net wells) in the U.S. |
|
(4) |
|
Includes wells drilled from Canada Other (former Canadian Plains and former Integrated Oil Canada assets). These assets were transferred to Cenovus as part of the November 30, 2009 Split Transaction. |
EnCana Corporation |
|
Annual Information Form |
The following table summarizes EnCanas interest in producing wells and wells capable of producing as at December 31, 2009.
|
|
Gas |
|
Oil |
|
Total (1,2) |
|
||||||
(number of wells) |
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Alberta |
|
10,814 |
|
9,759 |
|
398 |
|
225 |
|
11,212 |
|
9,984 |
|
British Columbia |
|
2,133 |
|
1,980 |
|
15 |
|
11 |
|
2,148 |
|
1,991 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Canada |
|
12,947 |
|
11,739 |
|
413 |
|
236 |
|
13,360 |
|
11,975 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Colorado |
|
5,107 |
|
4,482 |
|
6 |
|
2 |
|
5,113 |
|
4,484 |
|
Texas |
|
1,894 |
|
1,318 |
|
36 |
|
25 |
|
1,930 |
|
1,343 |
|
Wyoming |
|
2,067 |
|
1,537 |
|
1 |
|
1 |
|
2,068 |
|
1,538 |
|
Utah |
|
40 |
|
37 |
|
11 |
|
11 |
|
51 |
|
48 |
|
Louisiana |
|
76 |
|
47 |
|
- |
|
- |
|
76 |
|
47 |
|
Kansas |
|
1 |
|
1 |
|
- |
|
- |
|
1 |
|
1 |
|
Montana |
|
1 |
|
1 |
|
- |
|
- |
|
1 |
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total United States |
|
9,186 |
|
7,423 |
|
54 |
|
39 |
|
9,240 |
|
7,462 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
22,133 |
|
19,162 |
|
467 |
|
275 |
|
22,600 |
|
19,437 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes:
|
(1) |
EnCana has varying royalty interests in approximately 8,216 natural gas wells and approximately 5,480 crude oil wells which are producing or capable of producing. |
|
(2) |
Includes wells containing multiple completions as follows: approximately 11,155 gross natural gas wells (1,744 net wells) and approximately 146 gross crude oil wells (92 net wells). |
EnCana Corporation |
|
Annual Information Form |
Interest in Material Properties
The following table summarizes EnCanas developed, undeveloped and total landholdings as at December 31, 2009.
Landholdings (1,2,3,4,5,6) |
|
|
|
Developed |
|
Undeveloped |
|
Total |
|
||||||
(thousands of acres) |
|
|
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Canada |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Alberta |
|
Fee |
|
2,467 |
|
2,467 |
|
1,611 |
|
1,611 |
|
4,078 |
|
4,078 |
|
|
|
Crown |
|
1,312 |
|
741 |
|
1,394 |
|
1,098 |
|
2,706 |
|
1,839 |
|
|
|
Freehold |
|
222 |
|
127 |
|
74 |
|
55 |
|
296 |
|
182 |
|
|
|
|
|
4,001 |
|
3,335 |
|
3,079 |
|
2,764 |
|
7,080 |
|
6,099 |
|
British Columbia |
|
Crown |
|
1,024 |
|
910 |
|
2,807 |
|
2,201 |
|
3,831 |
|
3,111 |
|
|
|
Freehold |
|
- |
|
- |
|
7 |
|
- |
|
7 |
|
- |
|
|
|
|
|
1,024 |
|
910 |
|
2,814 |
|
2,201 |
|
3,838 |
|
3,111 |
|
Newfoundland and Labrador |
|
Crown |
|
- |
|
- |
|
35 |
|
2 |
|
35 |
|
2 |
|
Nova Scotia |
|
Crown |
|
- |
|
- |
|
41 |
|
30 |
|
41 |
|
30 |
|
Northwest Territories |
|
Crown |
|
- |
|
- |
|
45 |
|
12 |
|
45 |
|
12 |
|
Total Canada |
|
|
|
5,025 |
|
4,245 |
|
6,014 |
|
5,009 |
|
11,039 |
|
9,254 |
|
United States |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Colorado |
|
Federal/State Lands |
|
197 |
|
183 |
|
615 |
|
561 |
|
812 |
|
744 |
|
|
|
Freehold |
|
105 |
|
96 |
|
131 |
|
120 |
|
236 |
|
216 |
|
|
|
Fee |
|
3 |
|
3 |
|
31 |
|
31 |
|
34 |
|
34 |
|
|
|
|
|
305 |
|
282 |
|
777 |
|
712 |
|
1,082 |
|
994 |
|
Texas |
|
Federal/State Lands |
|
7 |
|
4 |
|
67 |
|
65 |
|
74 |
|
69 |
|
|
|
Freehold |
|
229 |
|
170 |
|
987 |
|
793 |
|
1,216 |
|
963 |
|
|
|
Fee |
|
- |
|
- |
|
4 |
|
2 |
|
4 |
|
2 |
|
|
|
|
|
236 |
|
174 |
|
1,058 |
|
860 |
|
1,294 |
|
1,034 |
|
Wyoming |
|
Federal/State Lands |
|
142 |
|
83 |
|
473 |
|
343 |
|
615 |
|
426 |
|
|
|
Freehold |
|
15 |
|
8 |
|
28 |
|
15 |
|
43 |
|
23 |
|
|
|
|
|
157 |
|
91 |
|
501 |
|
358 |
|
658 |
|
449 |
|
Louisiana |
|
Federal/State Lands |
|
- |
|
- |
|
4 |
|
4 |
|
4 |
|
4 |
|
|
|
Freehold |
|
28 |
|
16 |
|
514 |
|
325 |
|
542 |
|
341 |
|
|
|
Fee |
|
13 |
|
11 |
|
75 |
|
51 |
|
88 |
|
62 |
|
|
|
|
|
41 |
|
27 |
|
593 |
|
380 |
|
634 |
|
407 |
|
Other |
|
Federal/State Lands |
|
9 |
|
8 |
|
342 |
|
329 |
|
351 |
|
337 |
|
|
|
Freehold |
|
1 |
|
1 |
|
257 |
|
238 |
|
258 |
|
239 |
|
|
|
Fee |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
|
|
|
|
10 |
|
9 |
|
599 |
|
567 |
|
609 |
|
576 |
|
Total United States |
|
|
|
749 |
|
583 |
|
3,528 |
|
2,877 |
|
4,277 |
|
3,460 |
|
International |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Greenland |
|
|
|
- |
|
- |
|
1,700 |
|
808 |
|
1,700 |
|
808 |
|
Azerbaijan |
|
|
|
- |
|
- |
|
346 |
|
17 |
|
346 |
|
17 |
|
Australia |
|
|
|
- |
|
- |
|
104 |
|
40 |
|
104 |
|
40 |
|
Total International |
|
|
|
- |
|
- |
|
2,150 |
|
865 |
|
2,150 |
|
865 |
|
Total |
|
|
|
5,774 |
|
4,828 |
|
11,692 |
|
8,751 |
|
17,466 |
|
13,579 |
|
Notes:
|
(1) |
Fee lands are those lands in which EnCana has a fee simple interest in the mineral rights and has either: (i) not leased out all of the mineral zones; or (ii) retained a working interest; or (iii) one or more substances or products that have not been leased. The current fee lands acreage summary includes all fee titles owned by EnCana that have one or more zones that remain unleased or available for development. |
|
(2) |
This table excludes approximately 2.9 million gross acres of fee lands with one or more substances or products under lease or sublease, reserving to EnCana royalties or other interests. |
|
(3) |
Crown/Federal/State lands are those owned by the federal, provincial or state government or the First Nations, in which EnCana has purchased a working interest lease. |
|
(4) |
Freehold lands are owned by individuals (other than a government or EnCana), in which EnCana holds a working interest lease. |
|
(5) |
Gross acres are the total area of properties in which EnCana has an interest. |
|
(6) |
Net acres are the sum of EnCanas fractional interest in gross acres. |
EnCana Corporation |
|
Annual Information Form |
Acquisitions, Divestitures and Capital Expenditures
EnCanas growth in recent years has been achieved through a combination of internal growth and acquisitions. EnCana has a large inventory of internal growth opportunities and also continues to examine select acquisition opportunities to develop and expand its key resource plays. The acquisition opportunities may include corporate or asset acquisitions. EnCana may finance any such acquisitions with debt, equity, cash generated from operations, proceeds from asset divestitures or a combination of these sources.
The following table summarizes EnCanas net capital investment for 2009, 2008 and 2007.
($ millions) |
|
|
2009 |
|
|
2008 |
|
2007 |
|
Capital Investment |
|
|
|
|
|
|
|
|
|
Canadian Division |
|
|
1,869 |
|
|
2,459 |
|
2,403 |
|
USA Division |
|
|
1,821 |
|
|
2,682 |
|
1,935 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,690 |
|
|
5,141 |
|
4,338 |
|
Market Optimization |
|
|
2 |
|
|
17 |
|
6 |
|
Corporate & Other |
|
|
85 |
|
|
165 |
|
154 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,777 |
|
|
5,323 |
|
4,498 |
|
Acquisitions Property |
|
|
|
|
|
|
|
|
|
Canadian Division |
|
|
190 |
|
|
151 |
|
75 |
|
USA Division (1) |
|
|
46 |
|
|
1,023 |
|
2,613 |
|
Corporate |
|
|
|
|
|
|
|
|
|
Canadian Division (2) |
|
|
24 |
|
|
- |
|
- |
|
|
|
|
|
|
|
|
|
|
|
Divestitures |
|
|
|
|
|
|
|
|
|
Property |
|
|
|
|
|
|
|
|
|
Canadian Division (3) |
|
|
(1,000) |
|
|
(400) |
|
(213) |
|
USA Division |
|
|
(73) |
|
|
(251) |
|
(10) |
|
Corporate & Other (4) |
|
|
(5) |
|
|
(41) |
|
(47) |
|
Corporate |
|
|
|
|
|
|
|
|
|
Corporate & Other (5) |
|
|
(83) |
|
|
(165) |
|
(211) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,876 |
|
|
5,640 |
|
6,705 |
|
Other |
|
|
|
|
|
|
|
|
|
Capital Investment - Canada Other (6) |
|
|
848 |
|
|
1,500 |
|
1,238 |
|
Acquisitions Property - Canada Other (6) |
|
|
3 |
|
|
- |
|
14 |
|
Divestitures Property - Canada Other (6) |
|
|
(17) |
|
|
(47) |
|
- |
|
|
|
|
|
|
|
|
|
|
|
Net Capital Investment Before Discontinued Operations |
|
|
3,710 |
|
|
7,093 |
|
7,957 |
|
Discontinued Operations (7) |
|
|
829 |
|
|
478 |
|
220 |
|
|
|
|
|
|
|
|
|
|
|
Net Capital Investment |
|
|
4,539 |
|
|
7,571 |
|
8,177 |
|
|
|
|
|
|
|
|
|
|
|
Notes:
|
(1) |
In 2008, mainly includes Haynesville shale properties. In 2007, mainly includes the Deep Bossier natural gas assets and land interests. |
|
(2) |
Acquisition of Kerogen Resources Canada, ULC in May 2009. |
|
(3) |
Primarily includes divestures of non-core conventional oil and natural gas assets. |
|
(4) |
In 2007, consists primarily of the sale of EnCanas office building project assets (The Bow) and the sale of Australia assets. |
|
(5) |
In 2009, includes sale of Senlac Oil Limited. In 2008, mainly includes the sale of interests in Brazil. In 2007, sale of interests in Chad and Oman were completed. |
|
(6) |
Canada Other assets (former Canadian Plains and former Integrated Oil Canada assets) were transferred to Cenovus as part of the Split Transaction. |
|
(7) |
Includes U.S. Downstream Refining capital investments, which are reported as discontinued operations as these assets were transferred to Cenovus as part of the Split Transaction. |
EnCana Corporation |
|
Annual Information Form |
As part of ordinary business operations, EnCana has a number of delivery commitments to provide natural gas under existing contracts and agreements. The Corporation has sufficient natural gas reserves to meet these commitments. More detailed information relating to such commitments can be found in the Contractual Obligations and Contingencies section of the Corporations Managements Discussion and Analysis for the year ended December 31, 2009.
All aspects of the oil and gas industry are highly competitive and EnCana actively competes with natural gas and other companies, particularly in the following areas: (i) exploration for and development of new sources of natural gas reserves and liquids; (ii) reserves and property acquisitions; (iii) transportation and marketing of natural gas, liquids, diluents and electricity; (iv) access to services and equipment to carry out exploration, development or operating activities; and (v) attracting and retaining experienced industry personnel. The oil and gas industry also competes with other industries focused on providing alternative forms of energy to consumers. Competitive forces can lead to cost increases or result in an oversupply of natural gas and liquids, both of which could have a negative impact on EnCanas financial results.
EnCanas operations are subject to laws and regulations concerning pollution, protection of the environment and the handling and transport of hazardous materials. These laws and regulations generally require EnCana to remove or remedy the effect of its activities on the environment at present and former operating sites, including dismantling production facilities and remediating damage caused by the use or release of specified substances. The Corporate Responsibility, Environment, Health and Safety Committee of EnCanas Board of Directors reviews and recommends environmental policy to the Board of Directors for approval and oversees compliance with government laws and regulations. Monitoring and reporting programs for environmental, health and safety (EH&S) performance in day-to-day operations, as well as inspections and assessments, are designed to provide assurance that environmental and regulatory standards are met. Contingency plans are in place for a timely response to an environmental event and remediation/reclamation programs are in place and utilized to restore the environment.
EnCana incorporates the potential costs of carbon into future planning. The Corporate Responsibility, Environment, Health and Safety Committee of EnCanas Board of Directors reviews the impact of a variety of carbon constrained scenarios on EnCanas strategy with a current price range from $15 to $65 per tonne of emissions, applied to a range of emissions coverage levels.
EnCana expects to incur abandonment and site reclamation costs as existing oil and gas properties are abandoned and reclaimed. In 2009, expenditures for normal compliance with environmental regulations as well as expenditures beyond normal compliance were not material. Based on EnCanas current estimate, the total anticipated undiscounted future cost of abandonment and reclamation costs to be incurred over the life of the reserves is estimated at approximately $3.8 billion. As at December 31, 2009, EnCana has recorded an asset retirement obligation of $787 million.
Social and Environmental Policies
EnCana has a Corporate Responsibility Policy (the Policy) that outlines EnCanas commitment to deliver strong financial performance and sustainable value while conducting its business in an ethical and responsible way. The Policy applies to any activity undertaken by or on behalf of EnCana, anywhere in the world, associated with the finding, production, transmission and storage of the Corporations products including decommissioning of facilities,
EnCana Corporation |
|
Annual Information Form |
marketing and other business and administrative functions. The Policy has specific requirements in areas related to: (i) leadership commitment; (ii) sustainable value creation; (iii) governance and business practices; (iv) human rights; (v) labour practices; (vi) EH&S; (vii) stakeholder engagement; and (viii) socio-economic and community development.
The Policy and any revisions are approved by EnCanas Executive Team and its Board of Directors. Accountability for implementation of the Policy is at the operational level within EnCanas business units. Business units have established processes to evaluate risks and programs are implemented to minimize that risk. Coordination and oversight of the Policy resides with the EH&S, Security and Corporate Responsibility Group within Corporate Development, EH&S and Reserves.
The Policy states the following with respect to the environment: (i) EnCana will safeguard the environment, and will operate in a manner consistent with recognized global industry standards in EH&S; (ii) in all of its operations, EnCana will strive to make efficient use of resources, to minimize its environmental footprint, and to conserve habitat diversity and the plant and animal populations that may be affected by its operations; and (iii) EnCana will strive to reduce its emissions intensity and increase its energy efficiency.
With respect to EnCanas relationship with the communities in which it does business, the Policy states that: (i) EnCana emphasizes collaborative, consultative and partnership approaches in its community investment and programs, recognizing that no corporation is solely responsible for changing the fundamental economic, environmental and social situation in a community or country; and (ii) through its activities, EnCana will assist in local capacity-building and develop mutually beneficial relationships, to make a positive difference in the communities and regions where it operates.
With respect to human rights, the Policy states that EnCana will not take part in human rights abuse, and will not engage or be complicit in any activity that solicits or encourages human rights abuse.
Some of the steps that EnCana has taken to embed the corporate responsibility approach throughout the organization include: (i) a comprehensive approach to training and communicating policies and practices and a requirement for acknowledgement and sign-off on key policies from the Board of Directors and employees; (ii) an EH&S management system; (iii) a security program to regularly assess security threats to business operations and to manage the associated risks; (iv) a formalized approach to stakeholder relations with a standardized Stakeholder Engagement Guide and specific Aboriginal Community Engagement Guide; (v) corporate responsibility performance metrics to track the Corporations progress; (vi) an energy efficiency program that focuses on reducing energy use at EnCanas operations and supports initiatives at the community level while also incenting employees to reduce energy use in their homes; (vii) contribution of a minimum of 1 percent of EnCanas pre-tax domestic profits to charitable and non-profit organizations in the communities in which EnCana operates; (viii) an Investigations Practice and an Investigations Committee to review and resolve potential violations of EnCana policies or practices and other regulations; (ix) an Integrity Hotline that provides an additional avenue for EnCanas stakeholders to raise their concerns as well as the corporate responsibility website which allows people to write to the Corporation about non-financial issues of concern; (x) an internal corporate EH&S audit program that evaluates EnCanas compliance with the expectations and requirements of the EH&S management system; and (xi) related policies and practices such as an Alcohol and Drug Policy, a Business Conduct & Ethics Practice and guidelines for correct behaviours with respect to the acceptance of gifts, conflicts of interest and the appropriate use of EnCana equipment and technology in a manner that is consistent with leading ethical business practices. In addition, EnCanas Board of Directors approves such policies, and is advised of significant contraventions thereof, and receives updates on trends, issues or events which could have a significant impact on the Corporation.
EnCana Corporation |
|
Annual Information Form |
At December 31, 2009, EnCana employed 3,797 full time equivalent employees as set forth in the following table.
|
|
FTE Employees |
|
Canadian Division |
|
1,656 |
|
USA Division |
|
1,581 |
|
Corporate |
|
560 |
|
Total |
|
3,797 |
|
|
|
|
|
The Corporation also engages a number of contractors and service providers.
As at December 31, 2009, 100 percent of EnCanas reserves and production were located in North America, which limits EnCanas exposure to risks and uncertainties in countries considered politically and economically unstable. EnCanas operations and related assets outside North America may be adversely affected by changes in governmental policy, social instability or other political or economic developments which are not within the control of EnCana, including the expropriation of property, the cancellation or modification of contract rights and restrictions on repatriation of cash. The Corporation has undertaken to mitigate these risks where practical and considered warranted.
EnCana Corporation |
|
Annual Information Form |
The following information is provided for each director and executive officer of EnCana as at the date of this annual information form.
Directors
Name & Municipality of Residence |
|
Director |
|
Principal Occupation |
|
|
|
|
|
David P. OBrien, O.C. (5,7,10) |
|
1990 |
|
Chairman |
|
|
|
|
|
Randall K. Eresman (8) |
|
2006 |
|
President & Chief
Executive Officer |
|
|
|
|
|
Claire S. Farley (2,3,6) |
|
2008 |
|
Advisory Director |
|
|
|
|
|
Fred J. Fowler (3) |
|
2010 |
|
Corporate Director |
|
|
|
|
|
Barry W. Harrison (2,4,5,9) |
|
1996 |
|
Corporate Director and independent businessman |
|
|
|
|
|
Suzanne P. Nimocks (2) |
|
2010 |
|
Corporate Director |
|
|
|
|
|
Jane L. Peverett (2,5,6) |
|
2003 |
|
Corporate Director |
|
|
|
|
|
Allan P. Sawin (2,3,4) |
|
2007 |
|
President, Bear
Investments Inc. |
|
|
|
|
|
Clayton H. Woitas (3,4,6) |
|
2008 |
|
Chairman & Chief
Executive Officer |
|
|
|
|
|
Notes:
|
(1) |
Denotes the year each individual became a director of EnCana or one of its predecessor companies (AEC or PanCanadian). |
|
(2) |
Member of Audit Committee. |
|
(3) |
Member of Corporate Responsibility, Environment, Health and Safety Committee. |
|
(4) |
Member of Human Resources and Compensation Committee. |
|
(5) |
Member of Nominating and Corporate Governance Committee. |
|
(6) |
Member of Reserves Committee. |
|
(7) |
Ex officio non-voting member of all other committees. As an ex officio non-voting member, Mr. OBrien attends as his schedule permits and may vote when necessary to achieve a quorum. |
|
(8) |
As an officer of EnCana and a non-independent director, Mr. Eresman is not a member of any Board committees. |
|
(9) |
Mr. Harrison was a director of Gauntlet Energy Corporation in June 2003 when it filed for and was granted an order pursuant to the Companies Creditors Arrangement Act (Canada). A plan of arrangement for that company received court confirmation later that year. |
|
(10) |
Mr. OBrien resigned as a director of Air Canada on November 26, 2003. On April 1, 2003, Air Canada obtained an order from the Ontario Superior Court of Justice providing creditor protection under the Companies Creditors Arrangement Act (Canada). Air Canada also made a concurrent petition under Section 304 of the U.S. Bankruptcy Code. On September 30, 2004, Air Canada announced that it had successfully completed its restructuring process and implemented its Plan of Arrangement. |
EnCana Corporation |
|
Annual Information Form |
EnCana does not have an Executive Committee of its Board of Directors.
At the date of this annual information form, there are nine directors of the Corporation. As a result of the Split Transaction on November 30, 2009, EnCanas former 13-member Board of Directors was split between the resulting companies, with six members becoming directors of Cenovus and seven members remaining as directors of EnCana. Each of the seven remaining directors were elected at the last annual meeting of shareholders held on April 22, 2009. Following the Split Transaction, two additional directors were appointed by the Board of Directors (Suzanne P. Nimocks and Fred J. Fowler) and the number of directors, as reflected in the above table, currently stands at nine. At the next annual and special meeting, shareholders will be asked to elect as directors the nine individuals listed in the above table, together with one new nominee, Mr. Peter A. Dea. Subject to mandatory retirement age restrictions, which have been established by the Board of Directors, whereby a director may not stand for re-election at the first annual meeting after reaching the age of 71, all of the existing directors shall be eligible for re-election.
Executive Officers
Name & Municipality of Residence |
|
Corporate Office (Divisional Title) |
|
|
|
Randall K. Eresman |
|
President & Chief Executive Officer |
|
|
|
Sherri A. Brillon |
|
Executive Vice-President & Chief Financial Officer |
|
|
|
Michael M. Graham |
|
Executive Vice-President (President, Canadian Division) |
|
|
|
Robert A. Grant |
|
Executive Vice-President, Corporate Development, EH&S and Reserves |
|
|
|
Eric D. Marsh |
|
Executive Vice-President, Natural Gas Economy |
|
|
|
R. William Oliver |
|
Executive Vice-President & Chief Corporate Officer |
|
|
|
William A. Stevenson |
|
Executive Vice-President & Chief Accounting Officer |
|
|
|
Jeff E. Wojahn |
|
Executive Vice-President (President, USA Division) |
|
|
|
Renee E. Zemljak |
|
Executive Vice-President, Midstream, Marketing & Fundamentals |
|
|
|
During the last five years, all of the directors and executive officers have served in various capacities with EnCana or its predecessor companies or have held the principal occupation indicated opposite their names except for the following:
Ms. Farley has been an Advisory Director of Jefferies Randall & Dewey (global oil and gas energy industry advisor) since August 2008. She was Co-President of Jefferies Randall & Dewey from February 2005 to August 2008 and Chief Executive Officer of Randall & Dewey (oil and gas asset transaction advisors) from September 2002 until February 2005 when Randall & Dewey became the Oil and Gas Investment Banking Group
EnCana Corporation |
|
Annual Information Form |
of Jefferies & Company, Inc. She was also a Managing Partner of Castex Energy Partners (private exploration and production limited partnership with assets in south Louisiana) from August 2008 to January 2009.
Mr. Fowler has been Chairman of Spectra Energy Partners L.P. (public entity) since October 2008. He was President & Chief Executive Officer of Spectra Energy Corp. (public oil and gas company) from December 2006 to December 2008 and served as a director from December 2006 to May 2009. He was President & Chief Executive Officer of Duke Energy Gas Transmission, LLC (a subsidiary of Duke Energy Corporation) from April 2006 through December 2006. From June 1997, he occupied various executive positions with Duke Energy Corporation (public oil and gas company), including President & Chief Operating Officer from November 2002 through April 2006.
Ms. Nimocks was a director (senior partner) with McKinsey & Company (global management consulting firm) from June 1999 to March 2010 and was with the firm in various other capacities since 1989, including as a leader in the firms Global Petroleum Practice, Electric Power & Natural Gas Practice, Organization Practice, and Risk Management Practice, as a member of the firms worldwide personnel committees for many years and as the Houston Office Manager for eight years.
Ms. Peverett was President and Chief Executive Officer of BC Transmission Corporation (BCTC) from April 2005 to January 2009 and was Vice-President, Corporate Services and Chief Financial Officer of BCTC from June 2003 to April 2005. She was President of Union Gas Limited from April 2002 to May 2003, President and Chief Executive Officer from April 2001 to April 2002 and Senior Vice President Sales & Marketing from June 2000 to April 2001.
Mr. Sawin is President of Bear Investments Inc., a private investment company. From 1990 until their sale to CCS Income Trust in May 2006, he was President, director and part owner of Grizzly Well Servicing Inc. and related companies.
Mr. Dea is a nominee director who will stand for election at EnCanas April 21, 2010 Annual and Special Meeting of Shareholders. He has been President & Chief Executive Officer of Cirque Resources LP (private oil and gas company) since May 2007. From November 2001 through August 2006, he was President & Chief Executive Officer and a director of Western Gas Resources, Inc. (public natural gas company). He joined Barrett Resources Corporation (public natural gas company) in November 1993 and was CEO from November 1999 and Chairman of the Board from February 2000 through August 2001.
All of the directors and executive officers of EnCana listed above beneficially owned, as of February 10, 2010, directly or indirectly, or exercised control or direction over an aggregate of 503,999 Common Shares representing 0.07 percent of the issued and outstanding voting shares of EnCana, and directors and executive officers held options to acquire an aggregate of 4,381,389 additional Common Shares.
Investors should be aware that some of the directors and officers of the Corporation are directors and officers of other private and public companies. Some of these private and public companies may, from time to time, be involved in business transactions or banking relationships which may create situations in which conflicts might arise. Any such conflicts shall be resolved in accordance with the procedures and requirements of the relevant provisions of the CBCA, including the duty of such directors and officers to act honestly and in good faith with a view to the best interests of the Corporation.
The full text of the Audit Committee mandate is included in Appendix D of this annual information form.
Composition of the Audit Committee
The Audit Committee consists of five members, all of whom are independent and financially literate in accordance with the definitions in National Instrument 52-110 Audit Committees. The relevant education and experience of each Audit Committee member is outlined below.
EnCana Corporation |
|
Annual Information Form |
Claire S. Farley
Ms. Farley holds a Bachelor of Science in exploration geology (Emory University). She is a director of FMC Technologies, Inc. (public global oil and gas equipment and service company) and also serves on the Audit Committee. Ms. Farley has been an Advisory Director of Jefferies Randall & Dewey (global oil and gas energy industry advisor) since August 2008. She was Co-President of Jefferies Randall & Dewey from February 2005 to August 2008 and Chief Executive Officer of Randall & Dewey (oil and gas asset transaction advisors) from September 2002 until February 2005 when Randall & Dewey became the Oil and Gas Investment Banking Group of Jefferies & Company, Inc. She was also a Managing Partner of Castex Energy Partners (private exploration and production limited partnership with assets in south Louisiana) from August 2008 to January 2009.
Barry W. Harrison
Mr. Harrison holds a Bachelor of Business Administration and Banking (Colorado College) and a Bachelor of Laws (University of British Columbia). He is a Corporate Director and an independent businessman. Mr. Harrison is a director and President of Eastgate Minerals Ltd. (private oil and gas company). He is also a director and Chairman (as well as past Chairman of the Audit Committees) of The Wawanesa Mutual Insurance Company (Canadian property and casualty insurer) and its related companies, The Wawanesa Life Insurance Company and its U.S. subsidiary, Wawanesa General Insurance Company, headquartered in California. He was Managing Director of Goepel Shields & Partners Inc. in Calgary.
Suzanne P. Nimocks
Ms. Nimocks holds a Bachelor of Arts in Economics (Tufts University) and a Masters in Business Administration (Harvard Graduate School of Business). She was a director (senior partner) with McKinsey & Company (global management consulting firm) from June 1999 to March 2010 and was with the firm in various other capacities since 1989, including as a leader in the firms Global Petroleum Practice, Electric Power & Natural Gas Practice, Organization Practice, and Risk Management Practice, as a member of the firms worldwide personnel committees for many years and as the Houston Office Manager for eight years.
Jane L. Peverett (Audit Committee Chair)
Ms. Peverett holds a Bachelor of Commerce (McMaster University) and a Master of Business Administration (Queens University), together with a designation as a Certified Management Accountant and a Canadian Security Analyst Certificate. She is also a Fellow of The Society of Management Accountants (FCMA). She was appointed a director of the Canadian Imperial Bank of Commerce in February 2009 and is a member of the Audit Committee. She was President and Chief Executive Officer of BC Transmission Corporation (BCTC) from April 2005 to January 2009 and was Vice President, Corporate Services and Chief Financial Officer of BCTC (electrical transmission) from June 2003 to April 2005. In her 15-year career with the Westcoast Energy Inc./Duke Energy Corporation group of companies, she held senior executive positions with Union Gas Limited (Ontario), including President, President and Chief Executive Officer, Senior Vice President Sales & Marketing and Chief Financial Officer, among others.
Allan P. Sawin
Mr. Sawin holds a Bachelor of Commerce (University of Alberta) and a designation as a Chartered Accountant (Alberta). He is President of Bear Investments Inc. (private investment company). From 1990 until their sale to CCS Income Trust in May 2006, Mr. Sawin was President, director and part owner of Grizzly Well Servicing Inc. and related companies (private oilfield service companies operating drilling and service rigs in western Canada). From 1995 to 2003, he also served as a director and member of the Audit Committee of NQL Drilling Tools Inc. while it was a public company listed on the Toronto Stock Exchange.
The above list does not include David P. OBrien who is an ex officio member of the Audit Committee.
EnCana Corporation |
|
Annual Information Form |
Pre-Approval Policies and Procedures
EnCana has adopted policies and procedures with respect to the pre-approval of audit and permitted non-audit services to be provided by PricewaterhouseCoopers LLP. The Audit Committee of the Board of Directors has established a budget for the provision of a specified list of audit and permitted non-audit services that the Audit Committee believes to be typical, recurring or otherwise likely to be provided by PricewaterhouseCoopers LLP. The budget generally covers the period between the adoption of the budget and the next meeting of the Audit Committee, but at the option of the Audit Committee it may cover a longer or shorter period. The list of services is sufficiently detailed as to the particular services to be provided to ensure that (i) the Audit Committee knows precisely what services it is being asked to pre-approve and (ii) it is not necessary for any member of management to make a judgment as to whether a proposed service fits within the pre-approved services.
Subject to the next paragraph, the Audit Committee has delegated authority to the Chair of the Audit Committee (or if the Chair is unavailable, any other member of the Committee) to pre-approve the provision of permitted services by PricewaterhouseCoopers LLP which have not otherwise been pre-approved by the Audit Committee, including the fees and terms of the proposed services (Delegated Authority). Any required determination about the Chairs unavailability is required to be made by the good faith judgment of the applicable other member(s) of the Audit Committee after considering all facts and circumstances deemed by such member(s) to be relevant. All pre-approvals granted pursuant to Delegated Authority must be presented by the member(s) who granted the pre-approvals to the full Audit Committee at its next meeting.
The fees payable in connection with any particular service to be provided by PricewaterhouseCoopers LLP that has been pre-approved pursuant to Delegated Authority (i) may not exceed C$200,000, in the case of pre-approvals granted by the Chairman of the Audit Committee and (ii) may not exceed C$50,000, in the case of pre-approvals granted by any other member of the Audit Committee.
All proposed services or the fees payable in connection with such services that have not already been pre-approved must be pre-approved by either the Audit Committee or pursuant to Delegated Authority. Prohibited services may not be pre-approved by the Audit Committee or pursuant to Delegated Authority.
External Auditor Service Fees
The following table provides information about the fees billed to the Corporation for professional services rendered by PricewaterhouseCoopers LLP during fiscal 2009 and 2008.
(C$ thousands) |
|
2009 |
|
2008 |
|
Audit Fees (1) |
|
3,963 |
|
4,060 |
|
Audit-Related Fees (2) |
|
1,076 |
|
1,053 |
|
Tax Fees (3) |
|
569 |
|
1,408 |
|
All Other Fees (4) |
|
5 |
|
5 |
|
|
|
|
|
|
|
Total |
|
5,613 |
|
6,526 |
|
|
|
|
|
|
|
Notes:
|
(1) |
Audit fees consist of fees for the audit of the Corporations annual financial statements or services that are normally provided in connection with statutory and regulatory filings or engagements. |
|
(2) |
Audit-related fees consist of fees for assurance and related services that are reasonably related to the performance of the audit or review of the Corporations financial statements and are not reported as Audit Fees. During fiscal 2009 and 2008, the services provided in this category included an audit and reviews of Cenovus carve-out consolidated financial statements and related documents, reviews in connection with acquisitions and divestitures, research of accounting and audit-related issues, review of reserves disclosure and the review of the Corporate Responsibility Report. |
|
(3) |
Tax fees consist of fees for tax compliance services, tax advice and tax planning. During fiscal 2009 and 2008, the services provided in this category included assistance and advice in relation to the preparation of corporate income tax returns. |
|
(4) |
During fiscal 2009 and 2008, the services provided in this category included the payment of maintenance fees associated with a research tool that grants access to a comprehensive library of financial reporting and assurance literature and a working paper documentation package used by the Corporations internal audit group. |
EnCana Corporation |
|
Annual Information Form |
EnCana did not rely on the de minimus exemption provided by Section (c)(7)(i)(C) of Rule 2-01 of SEC Regulation S-X in 2008 or 2009.
The Corporation is authorized to issue an unlimited number of Common Shares, an unlimited number of First Preferred Shares and an unlimited number of Second Preferred Shares. As of December 31, 2009, there were approximately 751 million Common Shares outstanding and no Preferred Shares outstanding.
Common Shares
Under the Split Transaction, 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.
The holders of the Common Shares are entitled to receive dividends if, as and when declared by the Board of Directors of the Corporation. The holders of the Common Shares are entitled to receive notice of and to attend all meetings of shareholders and are entitled to one vote per Common Share held at all such meetings. In the event of the liquidation, dissolution or winding up of the Corporation or other distribution of assets of the Corporation among its shareholders for the purpose of winding up its affairs, the holders of the Common Shares will be entitled to participate rateably in any distribution of the assets of the Corporation.
EnCana has stock-based compensation plans that allow employees to purchase Common Shares of the Corporation. Option exercise prices approximate the market price for the Common Shares on the date that the options were issued. Options granted under the plan are generally fully exercisable after three years and expire five years after the grant date. Options granted under predecessor and/or related company replacement plans expire up to ten years from the date the options were granted.
The Corporation has a shareholder rights plan (the Plan) that was adopted to ensure, to the extent possible, that all shareholders of the Corporation are treated fairly in connection with any take-over bid for the Corporation. The Plan creates a right that attaches to each present and subsequently issued Common Share. Until the separation time, which typically occurs at the time of an unsolicited take-over bid, whereby a person acquires or attempts to acquire 20 percent or more of EnCanas Common Shares, the rights are not separable from the Common Shares, are not exercisable and no separate rights certificates are issued. Each right entitles the holder, other than the 20 percent acquirer, from and after the separation time and before certain expiration times, to acquire one Common Share at 50 percent of the market price at the time of exercise. The Plan was reconfirmed at the 2007 annual and special meeting of shareholders and must be reconfirmed at every third annual meeting thereafter.
Preferred Shares
Preferred Shares may be issued in one or more series. The Board of Directors may determine the designation, rights, privileges, restrictions and conditions attached to each series of Preferred Shares before the issue of such series. Holders of the Preferred Shares are not entitled to vote at any meeting of the shareholders of the Corporation, but may be entitled to vote if the Corporation fails to pay dividends on that series of Preferred Shares. The First Preferred Shares are entitled to priority over the Second Preferred Shares and the Common Shares of the Corporation, and the Second Preferred Shares are entitled to priority over the Common Shares of the Corporation, with respect to the payment of dividends and the distribution of assets of the Corporation in the event of any liquidation, dissolution or winding up of the Corporations affairs.
EnCana Corporation |
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Annual Information Form |
The following table outlines the ratings and outlooks of the Corporations debt as of December 31, 2009.
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Standard & Poors |
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Moodys Investors |
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DBRS Limited (DBRS) |
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Senior Unsecured |
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|
|
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Long-Term Rating |
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BBB+ |
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Baa2 |
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A (low) |
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Outlook |
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Stable |
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Stable |
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Stable |
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Commercial Paper |
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|
|
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Short-Term Rating |
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A-1 (low) |
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P-2 |
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R-1 (low) |
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Outlook |
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Stable |
|
Stable |
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Stable |
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Credit ratings are intended to provide investors with an independent measure of credit quality of any issue of securities. The credit ratings assigned by the rating agencies are not recommendations to purchase, hold or sell the securities nor do the ratings comment on market price or suitability for a particular investor. Any rating may not remain in effect for any given period of time or may be revised or withdrawn entirely by a rating agency in the future if in its judgment circumstances so warrant.
S&Ps long-term credit ratings are on a rating scale that ranges from AAA to D, which represents the range from highest to lowest quality of such securities rated. A rating of BBB+ by S&P is within the fourth highest of ten categories and indicates that the obligation exhibits adequate protection parameters. However, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the obligor to meet its financial commitment on the obligation. The addition of a plus (+) or minus () modifier after a rating indicates the relative standing within a particular rating category. S&Ps Canadian commercial paper ratings scale ranges from A-1 to D, which represents the range from highest to lowest quality. A rating of A-1 (low) is the third highest of eight categories and indicates that the obligor has satisfactory capacity to meet its financial commitments.
Moodys long-term credit ratings are on a rating scale that ranges from Aaa to C, which represents the range from highest to lowest quality of such securities rated. A rating of Baa2 by Moodys is within the fourth highest of nine categories and is assigned to debt securities which are considered medium-grade obligations (i.e., they are subject to moderate credit risk). Such debt securities may possess certain speculative characteristics. The addition of a 1, 2 or 3 modifier after a rating indicates the relative standing within a particular rating category. The modifier 1 indicates that the obligation ranks in the higher end of its generic rating category, the modifier 2 indicates a mid-range ranking and the modifier 3 indicates a ranking in the lower end of its generic rating category. Moodys short-term credit ratings are on a scale that ranges from P-1 (highest quality) to NP (lowest quality). A rating of P-2 is the second highest of four categories and indicates that the issuer has a strong ability to repay short-term debt obligations.
DBRS long-term credit ratings are on a rating scale that ranges from AAA to D, which represents the range from highest to lowest quality of such securities rated. A rating of A (low) by DBRS is within the third highest of ten categories and is assigned to debt securities considered to be of satisfactory credit quality. Protection of interest and principal is substantial, but the degree of strength is less than that of higher rated entities. Entities in the A category are considered to be more susceptible to adverse economic conditions and have greater cyclical tendencies than higher-rated securities. The assignment of a (high) or (low) modifier within each rating category indicates relative standing within such category. DBRS short-term credit ratings are on a scale ranging from R-1 (high) to D, which represents the range from highest to lowest quality. A rating of R-1 (low) is the third highest of ten categories and indicates that the short-term debt is of satisfactory credit quality. The overall strength and outlook for key liquidity, debt and profitability ratios is not normally as favourable as with higher rating categories, but these considerations are still respectable. Any qualifying negative factors that exist are considered manageable, and the entity is normally of sufficient size to have some influence in its industry.
EnCana Corporation |
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Annual Information Form |
All of the outstanding Common Shares of EnCana are listed and posted for trading on the Toronto Stock Exchange (TSX) and the New York Stock Exchange (NYSE) under the symbol ECA. The following table outlines the share price trading range and volume of shares traded by month in 2009.
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Toronto Stock Exchange |
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New York Stock Exchange |
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Share Price Trading Range |
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Share |
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Share Price Trading Range |
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Share |
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||||||||
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High |
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Low |
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Close |
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Volume |
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High |
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Low |
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Close |
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Volume |
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(C$ per share) |
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(millions) |
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($ per share) |
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(millions) |
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||||
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January |
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63.50 |
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51.55 |
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54.57 |
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52.7 |
|
|
53.81 |
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40.95 |
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44.34 |
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79.6 |
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February |
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58.65 |
|
44.64 |
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50.20 |
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52.6 |
|
|
48.04 |
|
35.70 |
|
39.37 |
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94.9 |
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March |
|
55.71 |
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45.67 |
|
51.60 |
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68.2 |
|
|
45.28 |
|
35.46 |
|
40.61 |
|
98.1 |
|
April |
|
57.75 |
|
50.33 |
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54.69 |
|
49.3 |
|
|
47.84 |
|
39.70 |
|
45.73 |
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64.3 |
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May |
|
65.71 |
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54.72 |
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60.00 |
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46.8 |
|
|
57.07 |
|
46.02 |
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55.43 |
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62.3 |
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June |
|
63.35 |
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53.85 |
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57.67 |
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44.4 |
|
|
58.34 |
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46.58 |
|
49.47 |
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56.5 |
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July |
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59.68 |
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51.34 |
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57.78 |
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36.6 |
|
|
54.89 |
|
44.01 |
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53.65 |
|
50.4 |
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August |
|
58.92 |
|
54.65 |
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57.06 |
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33.9 |
|
|
55.74 |
|
49.23 |
|
51.99 |
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36.2 |
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September |
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64.29 |
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54.96 |
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62.00 |
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46.2 |
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|
59.95 |
|
49.71 |
|
57.61 |
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59.6 |
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October |
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65.34 |
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59.00 |
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60.00 |
|
37.3 |
|
|
63.19 |
|
54.18 |
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55.39 |
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58.0 |
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November |
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62.90 |
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55.11 |
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56.57 |
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46.4 |
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|
59.68 |
|
51.91 |
|
53.88 |
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53.4 |
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December (1) |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pre-Split |
|
57.87 |
|
56.00 |
|
56.43 |
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6.1 |
|
|
55.43 |
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50.82 |
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51.09 |
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18.5 |
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Post-Split |
|
34.89 |
|
28.62 |
|
34.11 |
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46.9 |
|
|
33.61 |
|
27.56 |
|
32.39 |
|
42.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note:
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(1) |
The post-Split Common Shares began trading on the TSX for regular settlement at the opening of trading on December 3, 2009 and on the NYSE for regular settlement at the opening of trading on December 9, 2009. |
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In December 2009, EnCana received approval from the TSX to renew its Normal Course Issuer Bid (NCIB). Under the renewed program, EnCana is entitled to purchase up to 5 percent, approximately 37.5 million of its outstanding Common Shares as at November 30, 2009. Purchases may be made through the facilities of the TSX and the NYSE, in accordance with the policies and rules of each exchange.
During 2008, EnCana purchased approximately 4.8 million shares under the program at an average price of $67.13 for total consideration of approximately $326 million. On May 11, 2008, EnCana announced that it had suspended the purchases of Common Shares pending completion of the Split Transaction. EnCana did not purchase any Common Shares under its previous NCIB, which expired on November 12, 2009.
The declaration of dividends is at the discretion of the Board of Directors and is approved quarterly. During 2007, EnCana paid a quarterly dividend of $0.20 per share ($0.80 per share annually). From the first quarter of 2008 to the completion of the Split Transaction, EnCana paid a quarterly dividend of $0.40 per share ($1.60 per share annually). On December 31, 2009, after the Split Transaction, EnCana paid a quarterly dividend of $0.20 per share to Common Shareholders of record on December 21, 2009. The Board of Directors of Cenovus also declared a dividend of $0.20 per share payable on December 31, 2009 to Cenovus Common Shareholders of record on December 21, 2009.
EnCana Corporation |
|
Annual Information Form |
The Corporation is involved in various claims and litigation arising in the normal course of business. While the outcome of these matters is uncertain and there can be no assurance that such matters will be resolved in EnCanas favour, the Corporation does not currently believe that the outcome of any pending or threatened proceedings related to these or other matters, or the amounts which the Corporation may be required to pay by reason thereof, would have a material adverse impact on its financial position, results of operations or liquidity.
If any event arising from the risk factors set forth below occurs, EnCanas business, prospects, financial condition, results of operations or cash flows and in some cases its reputation could be materially adversely affected.
A substantial or extended decline in natural gas and liquids prices could have a material adverse effect on EnCana.
EnCanas financial performance and condition are substantially dependent on the prevailing prices of natural gas and liquids. As EnCana is primarily a natural gas company, it is more significantly affected by changes in natural gas prices than changes in liquids prices. Fluctuations in natural gas and liquids prices could have an adverse effect on the Corporations operations and financial condition and the value and amount of its proved reserves. Prices for natural gas and liquids fluctuate in response to changes in the supply and demand for natural gas and crude oil, market uncertainty and a variety of additional factors beyond the Corporations control.
Natural gas prices realized by EnCana are affected primarily by North American supply and demand, weather conditions and by prices of alternate sources of energy (including refined product, coal, imported liquefied natural gas and renewable energy initiatives). Any substantial or extended decline in the price of natural gas could result in a delay or cancellation of existing or future drilling, development or construction programs or curtailment in production at some properties or could result in unutilized long-term transportation commitments, all of which could have an adverse effect on the Corporations revenues, profitability and cash flows.
Crude oil prices are determined by international supply and demand. Factors which affect crude oil prices include the actions of the Organization of Petroleum Exporting Countries, world economic conditions, government regulation, political stability in the Middle East and elsewhere, the foreign supply of crude oil, the price of foreign imports, the availability of alternate fuel sources and weather conditions. NGLs prices are generally determined with reference to crude oil prices.
EnCana conducts an annual assessment of the carrying value of its assets in accordance with Canadian GAAP. If natural gas and liquids prices decline, the carrying value of EnCanas assets could be subject to financial downward revisions, and the Corporations earnings could be adversely affected.
EnCanas ability to operate and complete projects is dependent on factors outside of its control.
The Corporations ability to operate, generate sufficient cash flows, and complete projects depends upon numerous factors beyond the Corporations control. In addition to commodity prices and continued market demand for its products, these non-controllable factors include general business and market conditions, economic recessions and financial market turmoil, the ability to secure and maintain cost effective financing for its commitments, environmental and regulatory matters, unexpected cost increases, royalties, taxes, the availability of drilling and other equipment, the ability to access lands, weather, the availability of processing capacity, the availability and proximity of pipeline capacity, technology failures, accidents, the availability of skilled labour, and reservoir quality.
The tentative recovery from the global recession is creating ongoing fiscal challenges for the world economy. These conditions impact EnCanas customers and suppliers and may alter the Corporations spending and operating plans. There may be unexpected business impacts from this market uncertainty, including volatile
EnCana Corporation |
|
Annual Information Form |
changes in currency exchange rates, inflation, interest rates, and general levels of investing and consuming activity.
The Corporation undertakes a variety of projects including exploration and development projects and the construction or expansion of facilities and pipelines. Project delays may delay expected revenues and project cost overruns could make projects uneconomic.
All of EnCanas operations are subject to regulation and intervention by governments that can affect or prohibit the drilling, completion and tie-in of wells, production, the construction or expansion of facilities and the operation and abandonment of fields. Contract rights can be cancelled or expropriated. Changes to government regulation could impact the Corporations existing and planned projects.
The Corporations business is subject to environmental legislation in all jurisdictions in which it operates and any changes in such legislation could negatively affect its results of operations.
All phases of the natural gas and liquids businesses are subject to environmental regulation pursuant to a variety of Canadian, U.S. and other federal, provincial, territorial, state and municipal laws and regulations (collectively, environmental legislation).
Environmental legislation imposes, among other things, restrictions, liabilities and obligations in connection with the use, generation, handling, storage, transportation, treatment and disposal of chemicals, hazardous substances and waste associated with the finding, production, transmission and storage of the Corporations products including the hydraulic fracturing of wells, the decommissioning of facilities and in connection with spills, releases and emissions of various substances to the environment. It also imposes restrictions, liabilities and obligations in connection with the management of fresh or potable water sources that are being used, or whose use is contemplated, in connection with natural gas and crude oil operations. Environmental legislation also requires that wells, facility sites and other properties associated with EnCanas operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, certain types of operations, including exploration and development projects and changes to certain existing projects, may require the submission and approval of environmental impact assessments or permit applications. Compliance with environmental legislation can require significant expenditures, including expenditures for clean up costs and damages arising out of contaminated properties and failure to comply with environmental legislation may result in the imposition of fines and penalties. Although it is not expected that the costs of complying with environmental legislation will have a material adverse effect on EnCanas financial condition or results of operations, no assurance can be made that the costs of complying with environmental legislation in the future will not have such an effect.
A number of federal, provincial and state governments have announced intentions to regulate greenhouse gases and other air pollutants. These governments are currently developing the regulatory and policy frameworks to deliver on their announcements. In most cases there are few technical details regarding the implementation and coordination of these plans to regulate emissions. Additionally, it is anticipated that other federal, provincial and state announcements and regulatory frameworks to address emissions will continue to emerge.
As these federal and regional programs are under development, EnCana is unable to predict the total impact of the potential regulations upon its business. Therefore, it is possible that the Corporation could face increases in operating costs in order to comply with emissions legislation.
If EnCana fails to acquire or find additional reserves, the Corporations reserves and production will decline materially from their current levels.
EnCanas future natural gas and liquids reserves and production, and therefore its cash flows, are highly dependent upon its success in exploiting its current reserves base and acquiring, discovering or developing additional reserves. Without reserves additions through exploration, acquisition or development activities, the Corporations reserves and production will decline over time as reserves are depleted. The business of exploring for, developing or acquiring reserves is capital intensive. To the extent cash flows from operations are insufficient and external sources of capital become limited, EnCanas ability to make the necessary capital investments to maintain and expand its natural gas and liquids reserves will be impaired. In addition, there can be no certainty
EnCana Corporation |
|
Annual Information Form |
that EnCana will be able to find and develop or acquire additional reserves to replace production at acceptable costs.
EnCanas reserves data and future net revenue estimates are uncertain.
There are numerous uncertainties inherent in estimating quantities of natural gas and liquids reserves, including many factors beyond the Corporations control. The reserves data in this annual information form represents estimates only. In general, estimates of economically recoverable natural gas and liquids reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as product prices, future operating and capital costs, historical production from the properties and the assumed effects of regulation by governmental agencies, including with respect to royalty payments, all of which may vary considerably from actual results. All such estimates are to some degree uncertain, and classifications of reserves are only attempts to define the degree of uncertainty involved. For those reasons, estimates of the economically recoverable natural gas and liquids reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. EnCanas actual production, revenues, taxes and development and operating expenditures with respect to its reserves may vary from such estimates, and such variances could be material.
Estimates with respect to reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. Estimates based on these methods generally are less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be material, in the estimated reserves.
EnCanas hedging activities could result in realized and unrealized losses.
The nature of the Corporations operations results in exposure to fluctuations in commodity prices and interest rates. The Corporation monitors its exposure to such fluctuations and, where the Corporation deems it appropriate, utilizes derivative financial instruments and physical delivery contracts to mitigate the potential impact of declines in natural gas and liquids prices and changes in interest rates. Under Canadian GAAP, derivative instruments that do not qualify as hedges for accounting purposes, or are not designated as hedges, are fair valued with the resulting changes recognized in current period net earnings. The utilization of derivative financial instruments may therefore introduce significant volatility into the Corporations reported net earnings.
The terms of the Corporations various hedging agreements may limit the benefit to the Corporation of commodity price increases or changes in interest rates. The Corporation may also suffer financial loss because of hedging arrangements if the Corporation is unable to produce natural gas or liquids to fulfill delivery obligations, the Corporation is required to pay royalties based on market or reference prices that are higher than hedged prices, or counterparties to the Corporations hedging agreements fail to fulfill their obligations under the hedging agreements.
EnCanas operations are subject to the risk of business interruption and casualty losses.
The Corporations business is subject to all of the operating risks normally associated with the exploration for, development of and production of natural gas and liquids and the operation of midstream facilities. These risks include blowouts, explosions, fire, gaseous leaks, migration of harmful substances and liquid spills, acts of vandalism and terrorism, any of which could cause personal injury, result in damage to, or destruction of, natural gas and crude oil wells or formations or production facilities and other property, equipment and the environment, as well as interrupt operations. In addition, all of EnCanas operations will be subject to all of the risks normally incident to the transportation, processing, storing and marketing of natural gas, liquids, and other related products, drilling and completion of natural gas and crude oil wells, and the operation and development of natural gas and crude oil properties, including encountering unexpected formations or pressures, premature declines of reservoir pressure or productivity, blowouts, equipment failures and other accidents, sour gas releases, uncontrollable flows of natural gas, crude oil or well fluids, adverse weather conditions, pollution and other environmental risks.
EnCana Corporation |
|
Annual Information Form |
The occurrence of a significant event against which EnCana is not fully insured could have a material adverse effect on the Corporations financial position.
Fluctuations in exchange rates could affect expenses or result in realized and unrealized losses.
Worldwide prices for natural gas and crude oil are set in U.S. dollars. However, many of the Corporations expenses outside of the U.S. are denominated in Canadian dollars. Fluctuations in the exchange rate between the U.S. dollar and the Canadian dollar could impact the Corporations expenses and have an adverse effect on the Corporations financial performance and condition.
In addition, the Corporation has significant U.S. dollar denominated long-term debt. Fluctuations in the exchange rate between the U.S. dollar and the Canadian dollar could result in realized and unrealized losses on U.S. dollar denominated long-term debt.
EnCana does not operate all of its properties and assets.
Other companies operate a portion of the assets in which EnCana has ownership interests. EnCana will have limited ability to exercise influence over operations of these assets or their associated costs. EnCanas dependence on the operator and other working interest owners for these properties and assets, and its limited ability to influence operations and associated costs could materially adversely affect the Corporations financial performance. The success and timing of EnCanas activities on assets operated by others therefore will depend upon a number of factors that are outside of the Corporations control, including timing and amount of capital expenditures, timing and amount of operating and maintenance expenditures, the operators expertise and financial resources, approval of other participants, selection of technology, and risk management practices.
EnCana has certain indemnification obligations to Cenovus Energy Inc.
In relation to the Split Transaction, EnCana and Cenovus have each agreed to indemnify the other for certain liabilities and obligations associated with, among other things, in the case of EnCanas indemnity, the business and assets retained by EnCana, and in the case of Cenovuss indemnity, the business and assets transferred to Cenovus. EnCana cannot determine whether it will be required to indemnify Cenovus for any substantial obligations. EnCana also cannot be assured that, if Cenovus is required to indemnify EnCana and its affiliates for any substantial obligations, Cenovus will be able to satisfy such obligations. Any indemnification claim against EnCana pursuant to the provisions of the Split Transaction agreements could have a material adverse effect upon EnCana.
EnCana is exposed to counterparty risk.
EnCana is exposed to the risks associated with counterparty performance including credit risk and performance risk. EnCana may experience material financial losses in the event of customer payment default for commodity sales and financial derivative transactions. EnCana may be impacted by partner defaults with respect to the funding of partner obligations for capital projects. Performance risk can impact EnCanas operations by the non-delivery of contracted products or services by counterparties, which could impact on project timelines or operational efficiency.
The Corporations foreign operations will expose it to risks from abroad which could negatively affect its results of operations.
Some of EnCanas operations and related assets may be located, from time to time, in countries outside North America, some of which may be considered to be politically and economically unstable. Exploration or development activities in such countries may require protracted negotiations with host governments, national oil companies and third parties and are frequently subject to economic and political considerations, such as taxation, nationalization, expropriation, inflation, currency fluctuations, increased regulation and approval requirements, governmental regulation and the risk of actions by terrorist or insurgent groups, any of which could adversely affect the economics of exploration or development projects.
EnCana Corporation |
Annual Information Form |
In Canada: |
In the United States: |
CIBC Mellon Trust Company |
BNY Mellon Shareholder Services |
P.O. Box 7010 |
480 Washington Blvd. |
Adelaide Street Postal Station |
Jersey City, NJ |
Toronto, ON M5C 2W9 |
07310 |
In order to respond to EnCana shareholder inquiries, the Corporations transfer agent has set-up a dedicated answer line. Shareholder inquiries should be directed to the following:
Shareholders residing in Canada or the United States, please call 1-866-580-7145
Shareholders residing outside of North America, please call 1-416-643-5990
Shareholders can also send requests via the transfer agents web site at www.cibcmellon.com/investorinquiry.
The Corporations independent auditors are PricewaterhouseCoopers LLP, Chartered Accountants, who have issued an independent auditors report dated February 17, 2010 in respect of the Corporations consolidated financial statements as at December 31, 2009 and December 31, 2008 and for each of the years in the three year period ended December 31, 2009 and the Corporations internal control over financial reporting as at December 31, 2009. PricewaterhouseCoopers LLP has advised that they are independent with respect to the Corporation within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta and the rules of the SEC.
Information relating to reserves in this annual information form was calculated by GLJ Petroleum Consultants Ltd., McDaniel & Associates Consultants Ltd., Netherland, Sewell & Associates, Inc. and DeGolyer and MacNaughton, each of which is an independent qualified reserves evaluator.
The principals of each of GLJ Petroleum Consultants Ltd., McDaniel & Associates Consultants Ltd., Netherland, Sewell & Associates, Inc. and DeGolyer and MacNaughton, in each case, as a group own beneficially, directly or indirectly, less than 1 percent of any class of EnCanas securities.
Additional information relating to EnCana is available via the System for Electronic Document Analysis and Retrieval (SEDAR) at www.sedar.com.
Additional information, including directors and officers remuneration, principal holders of EnCanas securities, and options to purchase securities, is contained in the Information Circular for EnCanas most recent annual meeting of shareholders that involved the election of directors. Additional financial information is contained in EnCanas audited consolidated financial statements and Managements Discussion and Analysis for the year ended December 31, 2009.
The Arrangement Agreement and Separation and Transition Agreement, described under General Development of the Business Split Transaction are material contracts of EnCana and are available on SEDAR.
EnCana Corporation |
Annual Information Form |
This annual information form contains certain forward-looking statements or information (collectively referred to in this note as forward-looking statements) within the meaning of applicable securities legislation. Forward-looking statements are typically identified by words such as projected, anticipate, believe, expect, plan, intend or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking statements in this annual information form include, but are not limited to, statements with respect to: achieving its strategy to be a natural gas pure-play company focused on development of unconventional resources, drilling and development plans and the timing and location thereof, production and processing capacities and levels and the timing of achieving such capacities and levels, the anticipated date of production for the Deep Panuke natural gas project, expansion of gathering and processing plants and other facilities, reserves estimates, including reserves estimates under different price cases, the level of expenditures for compliance with environmental regulations, including estimates of potential costs of carbon, site restoration costs including abandonment and reclamation costs, pending litigation, exploration plans, acquisition and divestiture plans and net cash flows.
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 things contemplated by the forward-looking statements will not occur. 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. Some of the assumptions, risks and other factors which could cause results to differ materially from those expressed in the forward-looking statements contained in this annual information form include, but are not limited to: volatility of and assumptions regarding natural gas and liquids prices, assumptions based upon EnCanas current guidance, fluctuations in currency and interest rates, product supply and demand, market competition, risks inherent in EnCanas North American and foreign natural gas and liquids and market optimization operations, risks of war, hostilities, civil insurrection and instability affecting countries in which EnCana and its subsidiaries operate and terrorist threats, risks inherent in EnCanas and its subsidiaries marketing operations, including credit risk, imprecision of reserves estimates and estimates of recoverable quantities of natural gas and liquids from resource plays and other sources not currently classified as proved reserves, EnCanas and its subsidiaries ability to replace and expand natural gas and liquids reserves, 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 processing facilities, risks associated with technology, EnCanas ability to generate sufficient cash flow from operations to meet its current and future obligations, EnCanas ability to access external sources of debt and equity capital, general economic and business conditions, EnCanas ability to enter into or renew leases, the timing and costs of construction of gas storage facilities, wells and pipelines, EnCanas ability to make capital investments and the amounts of capital investments, imprecision in estimating the timing, costs and levels of production and drilling, the results of exploration, development and drilling, imprecision in estimates of future production capacity, EnCanas and its subsidiaries ability to secure adequate product transportation, uncertainty in the amounts and timing of royalty payments, imprecision in estimates of product sales, changes in royalty, tax, environmental and other laws or regulations or the interpretations of such laws or regulations, risks associated with existing and potential future lawsuits and regulatory actions against EnCana and its subsidiaries, political and economic conditions in the countries in which EnCana and its subsidiaries operate, difficulty in obtaining necessary regulatory approvals and such other assumptions, risks and uncertainties described from time to time in EnCanas reports and filings with the Canadian securities authorities and the U.S. SEC. Statements relating to reserves are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated, and can be profitably produced in the future. Readers are cautioned that the foregoing list of important factors is not exhaustive. Assumptions relating to forward-looking statements generally include EnCanas current expectations and projections made by the Corporation in light of, and generally consistent with, its historical experience and its perception of historical trends, as well as expectations regarding rates of advancement and innovation, generally consistent with and informed by its past experience, all of which are subject to the risk factors identified elsewhere in this document.
The forward-looking statements contained in this annual information form are made as of the date hereof and,
EnCana Corporation |
Annual Information Form |
except as required by law, EnCana undertakes no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this annual information form are expressly qualified by this cautionary statement.
National Instrument 51-101 (NI 51-101) of the Canadian Securities Administrators imposes oil and gas disclosure standards for Canadian public companies engaged in oil and gas activities. EnCana has obtained an exemption from Canadian securities regulatory authorities to permit it to provide disclosure in accordance with the relevant legal requirements of the SEC. This facilitates comparability of oil and gas disclosure with that provided by the U.S. and other international issuers, given that EnCana is active in the U.S. capital markets. Accordingly, the reserves data and other oil and gas information included or incorporated by reference in this annual information form is disclosed in accordance with U.S. disclosure requirements and practices. Such information, as well as the information that EnCana discloses in the future in reliance on the exemption, may differ from the corresponding information prepared in accordance with NI 51-101 standards.
The primary differences between the U.S. requirements and the NI 51-101 requirements are that (i) the U.S. standards require disclosure only of proved reserves, whereas NI 51-101 requires disclosure of proved and probable reserves, and (ii) the U.S. standards require that the reserves and related future net revenue be estimated using a historic constant price, whereas NI 51-101 requires disclosure of reserves and related future net revenue using forecast prices.
EnCana has disclosed proved reserves quantities using the standards contained in SEC Regulation S-K, and the standardized measure of discounted future net cash flows relating to proved oil and gas reserves determined in accordance with FASB standards.
Under U.S. disclosure standards, reserves and production information is disclosed on a net basis (after royalties). The reserves and production information contained in this annual information form is shown on that basis.
EnCana Corporation |
Annual Information Form |
The tables in this Appendix set forth oil and gas information prepared by EnCana in accordance with FASB standards.
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein
In calculating the standardized measure of discounted future net cash flows, constant price and cost assumptions were applied to EnCanas annual future production from proved reserves to determine cash inflows. Future production and development costs assume the continuation of existing economic, operating and regulatory conditions. Future income taxes are calculated by applying statutory income tax rates to future pre-tax cash flows after provision for the tax cost of the oil and natural gas properties based upon existing laws and regulations. The discount was computed by application of a 10 percent discount factor to the future net cash flows. The calculation of the standardized measure of discounted future net cash flows is based upon the discounted future net cash flows prepared by EnCanas independent qualified reserves evaluators in relation to the reserves they respectively evaluated, and adjusted to the extent provided by contractual arrangements such as price risk management activities, in existence at year-end and to account for asset retirement obligations and future income taxes.
EnCana cautions that the discounted future net cash flows relating to proved oil and gas reserves are an indication of neither the fair market value of EnCanas oil and gas properties, nor the future net cash flows expected to be generated from such properties. The discounted future net cash flows do not include the fair market value of exploratory properties and probable or possible oil and gas reserves, nor is consideration given to the effect of anticipated future changes in crude oil and natural gas prices, development, asset retirement and production costs and possible changes to tax and royalty regulations. The prescribed discount rate of 10 percent may not appropriately reflect future interest rates. The computation also excludes values attributable to EnCanas Market Optimization interests.
EnCana Corporation |
Annual Information Form |
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
|
|
Canada (1,2) |
|
|
United States (1) |
|
||||||||
($ millions) |
|
2009 |
|
2008 |
|
2007 |
|
|
2009 |
|
2008 |
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows |
|
19,321 |
|
64,308 |
|
95,778 |
|
|
18,573 |
|
26,620 |
|
38,398 |
|
Less future: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs |
|
6,296 |
|
23,017 |
|
25,089 |
|
|
4,862 |
|
6,079 |
|
5,869 |
|
Development costs |
|
4,065 |
|
9,800 |
|
10,171 |
|
|
4,429 |
|
5,227 |
|
6,943 |
|
Asset retirement obligation payments |
|
1,508 |
|
2,995 |
|
3,320 |
|
|
640 |
|
488 |
|
532 |
|
Income taxes |
|
659 |
|
5,746 |
|
12,871 |
|
|
707 |
|
2,961 |
|
7,375 |
|
Future net cash flows |
|
6,793 |
|
22,750 |
|
44,327 |
|
|
7,935 |
|
11,865 |
|
17,679 |
|
Less 10% annual discount for estimated timing of cash flows |
|
2,704 |
|
10,036 |
|
21,663 |
|
|
3,592 |
|
5,218 |
|
8,196 |
|
Discounted future net cash flows |
|
4,089 |
|
12,714 |
|
22,664 |
|
|
4,343 |
|
6,647 |
|
9,483 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (1) |
|
||||
($ millions) |
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows |
|
|
|
|
|
|
|
|
37,894 |
|
90,928 |
|
134,176 |
|
Less future: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs |
|
|
|
|
|
|
|
|
11,158 |
|
29,096 |
|
30,958 |
|
Development costs |
|
|
|
|
|
|
|
|
8,494 |
|
15,027 |
|
17,114 |
|
Asset retirement obligation payments |
|
|
|
|
|
|
|
|
2,148 |
|
3,483 |
|
3,852 |
|
Income taxes |
|
|
|
|
|
|
|
|
1,366 |
|
8,707 |
|
20,246 |
|
Future net cash flows |
|
|
|
|
|
|
|
|
14,728 |
|
34,615 |
|
62,006 |
|
Less 10% annual discount for estimated timing of cash flows |
|
|
|
|
|
|
|
|
6,296 |
|
15,254 |
|
29,859 |
|
Discounted future net cash flows |
|
|
|
|
|
|
|
|
8,432 |
|
19,361 |
|
32,147 |
|
Notes:
(1) 2009 future net cash flows have been calculated using 12-month average prices of: natural gas AECO C$3.77/MMbtu and Henry Hub $3.87/MMbtu; crude oil WTI $61.18/bbl and Edmonton Light C$65.64/bbl. Future net cash flows would have been $18,453 million (Canada - $8,508 million; United States - $9,945) using the following single day December 31, 2009 prices: natural gas AECO C$5.63/MMbtu and Henry Hub $5.78/MMbtu; crude oil WTI $79.36/bbl and Edmonton Light C$82.69/bbl. In 2008 and 2007, future net cash flows were calculated using the year-end price for the respective years.
(2) 2008 and 2007 estimates of future net cash flows included the cash flows from Canada Other (former Canadian Plains and former Integrated Oil Canada assets). These operations were transferred to Cenovus as part of the Split Transaction.
EnCana Corporation |
Annual Information Form |
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Oil and Gas Reserves
|
|
Canada (1) |
|
|
United States |
|
|||||||||
($ millions) |
|
2009 |
|
2008 |
|
2007 |
|
|
2009 |
|
2008 |
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, beginning of year |
|
12,714 |
|
22,664 |
|
16,596 |
|
|
6,647 |
|
9,483 |
|
6,454 |
|
|
Changes resulting from: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of oil and gas produced during the period |
|
(5,609 |
) |
(7,346 |
) |
(6,055 |
) |
|
(3,442 |
) |
(4,125 |
) |
(3,281 |
) |
|
Discoveries and extensions, net of related costs |
|
1,294 |
|
2,031 |
|
3,632 |
|
|
629 |
|
904 |
|
1,591 |
|
|
Purchases of proved reserves in place |
|
16 |
|
58 |
|
120 |
|
|
- |
|
14 |
|
372 |
|
|
Sales and transfers of proved reserves in place |
|
(6,492 |
) |
(321 |
) |
(1,283 |
) |
|
(62 |
) |
(197 |
) |
(15 |
) |
|
Net change in prices and production costs |
|
(1,825 |
) |
(14,632 |
) |
9,671 |
|
|
(1,446 |
) |
(4,204 |
) |
4,818 |
|
|
Revisions to quantity estimates |
|
(1,242 |
) |
1,736 |
|
603 |
|
|
(1,567 |
) |
667 |
|
830 |
|
|
Accretion of discount |
|
1,572 |
|
2,905 |
|
2,087 |
|
|
827 |
|
1,346 |
|
924 |
|
|
Previously estimated development costs incurred net of change in future development costs |
|
737 |
|
1,923 |
|
(259 |
) |
|
1,474 |
|
315 |
|
(907 |
) |
|
Other |
|
150 |
|
321 |
|
(341 |
) |
|
(26 |
) |
88 |
|
(113 |
) |
|
Net change in income taxes |
|
2,774 |
|
3,375 |
|
(2,107 |
) |
|
1,309 |
|
2,356 |
|
(1,190 |
) |
|
Balance, end of year |
|
4,089 |
|
12,714 |
|
22,664 |
|
|
4,343 |
|
6,647 |
|
9,483 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|
Total |
|
|||||||
($ millions) |
|
|
|
|
|
|
2009 |
|
2008 |
|
2007 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Balance, beginning of year |
|
|
|
|
|
|
19,361 |
|
32,147 |
|
23,050 |
|
|||
Changes resulting from: |
|
|
|
|
|
|
|
|
|
|
|
|
|||
Sales of oil and gas produced during the period |
|
|
|
|
|
|
(9,051 |
) |
(11,471 |
) |
(9,336 |
) |
|||
Discoveries and extensions, net of related costs |
|
|
|
|
|
|
1,923 |
|
2,935 |
|
5,223 |
|
|||
Purchases of proved reserves in place |
|
|
|
|
|
|
16 |
|
72 |
|
492 |
|
|||
Sales and transfers of proved reserves in place |
|
|
|
|
|
|
(6,554 |
) |
(518 |
) |
(1,298 |
) |
|||
Net change in prices and production costs |
|
|
|
|
|
|
(3,271 |
) |
(18,836 |
) |
14,489 |
|
|||
Revisions to quantity estimates |
|
|
|
|
|
|
(2,809 |
) |
2,403 |
|
1,433 |
|
|||
Accretion of discount |
|
|
|
|
|
|
2,399 |
|
4,251 |
|
3,011 |
|
|||
Previously estimated development costs incurred net of change in future development costs |
|
|
|
|
|
|
2,211 |
|
2,238 |
|
(1,166 |
) |
|||
Other |
|
|
|
|
|
|
124 |
|
409 |
|
(454 |
) |
|||
Net change in income taxes |
|
|
|
|
|
|
4,083 |
|
5,731 |
|
(3,297 |
) |
|||
Balance, end of year |
|
|
|
|
|
|
8,432 |
|
19,361 |
|
32,147 |
|
|||
Note:
(1) Results prior to November 30, 2009 include reserves from Canada Other (former Canadian Plains and former Integrated Oil Canada operations). These operations were transferred to Cenovus as part of the Split Transaction.
EnCana Corporation |
Annual Information Form |
Results of Operations
|
|
Canada (1) |
|
|
United States |
|
||||||||
($ millions) |
|
2009 |
|
2008 |
|
2007 |
|
|
2009 |
|
2008 |
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas revenues, net of royalties, transportation and selling costs |
|
6,835 |
|
8,848 |
|
7,361 |
|
|
4,007 |
|
5,127 |
|
4,065 |
|
Less: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs, production and mineral taxes, and accretion of asset retirement obligations |
|
1,226 |
|
1,502 |
|
1,306 |
|
|
565 |
|
1,002 |
|
784 |
|
Depreciation, depletion and amortization |
|
1,980 |
|
2,198 |
|
2,298 |
|
|
1,561 |
|
1,691 |
|
1,181 |
|
Operating income (loss) |
|
3,629 |
|
5,148 |
|
3,757 |
|
|
1,881 |
|
2,434 |
|
2,100 |
|
Income taxes |
|
1,059 |
|
1,502 |
|
1,114 |
|
|
698 |
|
937 |
|
809 |
|
Results of operations |
|
2,570 |
|
3,646 |
|
2,643 |
|
|
1,183 |
|
1,497 |
|
1,291 |
|
|
|
Other |
|
|
Total |
|
||||||||
($ millions) |
|
2009 |
|
2008 |
|
2007 |
|
|
2009 |
|
2008 |
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas revenues, net of royalties, transportation and selling costs |
|
- |
|
2 |
|
- |
|
|
10,842 |
|
13,977 |
|
11,426 |
|
Less: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs, production and mineral taxes, and accretion of asset retirement obligations |
|
- |
|
(2 |
) |
19 |
|
|
1,791 |
|
2,502 |
|
2,109 |
|
Depreciation, depletion and amortization |
|
28 |
|
39 |
|
69 |
|
|
3,569 |
|
3,928 |
|
3,548 |
|
Operating income (loss) |
|
(28 |
) |
(35 |
) |
(88 |
) |
|
5,482 |
|
7,547 |
|
5,769 |
|
Income taxes |
|
- |
|
- |
|
- |
|
|
1,757 |
|
2,439 |
|
1,923 |
|
Results of operations |
|
(28 |
) |
(35 |
) |
(88 |
) |
|
3,725 |
|
5,108 |
|
3,846 |
|
Note:
(1) Results of Operations prior to November 30, 2009 include Canada Other (former Canadian Plains and former Integrated Oil Canada operations). These operations were transferred to Cenovus as part of the Split Transaction.
Capitalized Costs
|
|
Canada (1) |
|
|
United States |
|
||||||||
($ millions) |
|
2009 |
|
2008 |
|
2007 |
|
|
2009 |
|
2008 |
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved oil and gas properties |
|
21,459 |
|
33,466 |
|
37,120 |
|
|
19,843 |
|
15,755 |
|
13,773 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unproved oil and gas properties |
|
728 |
|
870 |
|
1,380 |
|
|
1,178 |
|
3,399 |
|
1,852 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital cost |
|
22,187 |
|
34,336 |
|
38,500 |
|
|
21,021 |
|
19,154 |
|
15,625 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated DD&A |
|
11,586 |
|
17,348 |
|
19,286 |
|
|
7,092 |
|
5,511 |
|
3,783 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net capitalized costs |
|
10,601 |
|
16,988 |
|
19,214 |
|
|
13,929 |
|
13,643 |
|
11,842 |
|
|
|
Other |
|
|
Total |
|
||||||||
($ millions) |
|
2009 |
|
2008 |
|
2007 |
|
|
2009 |
|
2008 |
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved oil and gas properties |
|
- |
|
- |
|
- |
|
|
41,302 |
|
49,221 |
|
50,893 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unproved oil and gas properties |
|
157 |
|
122 |
|
305 |
|
|
2,063 |
|
4,391 |
|
3,537 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital cost |
|
157 |
|
122 |
|
305 |
|
|
43,365 |
|
53,612 |
|
54,430 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated DD&A |
|
147 |
|
112 |
|
160 |
|
|
18,825 |
|
22,971 |
|
23,229 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net capitalized costs |
|
10 |
|
10 |
|
145 |
|
|
24,540 |
|
30,641 |
|
31,201 |
|
Note:
(1) Results prior to November 30, 2009 include capitalized costs from Canada Other (former Canadian Plains and former Integrated Oil Canada operations). These operations were transferred to Cenovus as part of the Split Transaction.
EnCana Corporation |
Annual Information Form |
Costs Incurred
|
|
Canada (1) |
|
|
United States |
|
||||||||
($ millions) |
|
2009 |
|
2008 |
|
2007 |
|
|
2009 |
|
2008 |
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unproved |
|
46 |
|
32 |
|
28 |
|
|
46 |
|
1,006 |
|
1,048 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
|
178 |
|
119 |
|
61 |
|
|
- |
|
17 |
|
1,565 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total acquisitions |
|
224 |
|
151 |
|
89 |
|
|
46 |
|
1,023 |
|
2,613 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration costs |
|
129 |
|
474 |
|
427 |
|
|
133 |
|
197 |
|
48 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development costs |
|
2,588 |
|
3,485 |
|
3,214 |
|
|
1,688 |
|
2,485 |
|
1,887 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred |
|
2,941 |
|
4,110 |
|
3,730 |
|
|
1,867 |
|
3,705 |
|
4,548 |
|
|
|
Other |
|
|
Total |
|
||||||||
($ millions) |
|
2009 |
|
2008 |
|
2007 |
|
|
2009 |
|
2008 |
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unproved |
|
- |
|
- |
|
- |
|
|
92 |
|
1,038 |
|
1,076 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
|
- |
|
- |
|
- |
|
|
178 |
|
136 |
|
1,626 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total acquisitions |
|
- |
|
- |
|
- |
|
|
270 |
|
1,174 |
|
2,702 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration costs |
|
2 |
|
14 |
|
60 |
|
|
264 |
|
685 |
|
535 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development costs |
|
- |
|
- |
|
- |
|
|
4,276 |
|
5,970 |
|
5,101 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred |
|
2 |
|
14 |
|
60 |
|
|
4,810 |
|
7,829 |
|
8,338 |
|
Note:
(1) Results prior to November 30, 2009 include costs incurred from Canada Other (former Canadian Plains and former Integrated Oil Canada operations). These operations were transferred to Cenovus as part of the Split Transaction.
EnCana Corporation |
Annual Information Form |
To the Board of Directors of EnCana Corporation (the Corporation):
1. We have evaluated the Corporations reserves data as at December 31, 2009. The reserves data consists of the following:
(a) estimated proved oil and gas reserves quantities as at December 31, 2009 using constant prices and costs; and
(b) the related estimates of discounted future net cash flows under the standardized measure calculation for proved oil and gas reserves quantities.
2. The reserves data are the responsibility of the Corporations management. Our responsibility is to express an opinion on the reserves data based on our evaluation.
We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the COGE Handbook) prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society) with the necessary modifications to reflect definitions and standards under the U.S. Financial Accounting Standards Board policies (the FASB Standards) and the legal requirements of the U.S. Securities and Exchange Commission (SEC Requirements).
3. Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with the principles and definitions outlined above.
4. The following table sets forth both the estimated proved reserves quantities (after royalties) and related estimates of future net cash flows (before deduction of income taxes) assuming constant prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Corporation evaluated by us for the year ended December 31, 2009:
|
|
|
|
Estimated Proved |
|
Related Estimates |
|
||
|
|
|
|
Reserves Quantities |
|
of Future Net |
|
||
|
|
|
|
After Royalty |
|
Cash Flow Before Tax, |
|
||
Evaluator and Preparation Date of Report |
|
Reserves Location |
|
Gas |
|
Liquids |
|
10% discount rate |
|
|
|
|
|
(Bcf) |
|
(MMbbl) |
|
(US$MM) |
|
McDaniel & Associates Consultants Ltd. January 11, 2010 |
|
Canada |
|
1,351 |
|
9 |
|
1,156 |
|
GLJ Petroleum Consultants Ltd. January 12, 2010 |
|
Canada |
|
3,998 |
|
27 |
|
3,018 |
|
Netherland, Sewell & Associates, Inc. January 11, 2010 |
|
United States |
|
3,639 |
|
38 |
|
3,529 |
|
DeGolyer and MacNaughton January 20, 2010 |
|
United States |
|
2,074 |
|
3 |
|
1,022 |
|
Totals |
|
|
|
11,062 |
|
77 |
|
8,725 |
|
5. In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook as modified by the FASB Standards and SEC Requirements.
6. We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates.
EnCana Corporation |
Annual Information Form |
7. Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material. However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery.
Executed as to our report referred to above:
(signed) McDaniel & Associates Consultants Ltd. |
(signed) GLJ Petroleum Consultants Ltd. |
Calgary, Alberta, Canada |
Calgary, Alberta, Canada |
|
|
|
|
|
|
(signed) Netherland, Sewell & Associates, Inc. |
(signed) DeGolyer and MacNaughton |
Dallas, Texas, U.S.A. |
Dallas, Texas, U.S.A. |
February 9, 2010
EnCana Corporation |
Annual Information Form |
Management and directors of EnCana Corporation (the Corporation) are responsible for the preparation and disclosure of information with respect to the Corporations oil and gas activities in accordance with securities regulatory requirements. In the case of the Corporation, the regulatory requirements are covered under NI 51-101 as amended by a decision document dated September 29, 2008 (the Decision), and require disclosure of information contemplated by, and consistent with, US Disclosure Requirements (as defined in the Decision). Required information includes reserves data, which consists of the following:
(a) proved oil and gas reserves quantities estimated as at December 31, 2009 using constant prices and costs; and
(b) the related estimates of discounted future net cash flows under the standardized measure calculation for proved oil and gas reserves quantities.
Independent qualified reserves evaluators have evaluated the Corporations reserves data. A report from the independent qualified reserves evaluators dated February 9, 2010 (the IQRE Report), highlighting the standards they followed and their results, accompanies this Report.
The Reserves Committee of the board of directors of the Corporation, which is comprised exclusively of non-management and unrelated directors, has:
(a) reviewed the Corporations procedures for providing information to the independent qualified reserves evaluators;
(b) met with the independent qualified reserves evaluators to determine whether any restrictions placed by management affected the ability of the independent qualified reserves evaluators to report without reservation; and
(c) reviewed the reserves data as outlined in the IQRE Report with management and each of the independent qualified reserves evaluators.
The board of directors of the Corporation (the Board of Directors) has reviewed the standardized measure calculation with respect to the Corporations proved oil and gas reserves quantities. The Board of Directors has reviewed the Corporations procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The Board of Directors has approved:
(a) the content and filing with securities regulatory authorities of the proved oil and gas reserves quantities, related standardized measure calculation and other oil and gas activity information, contained in the annual information form of the Corporation accompanying this Report;
(b) the filing of the IQRE Report; and
(c) the content and filing of this Report.
EnCana Corporation |
Annual Information Form |
Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material. However, any variations should be consistent with the fact that reserves are categorized according to their probability of recovery.
(signed) Randall K. Eresman |
(signed) Robert A. Grant |
President & Chief Executive Officer |
Executive Vice-President, |
|
Corporate Development, EH&S and Reserves |
|
|
|
|
|
|
(signed) David P. OBrien |
(signed) Claire S. Farley |
Director and Chairman of the Board |
Director and Chair of the Reserves Committee |
February 10, 2010
EnCana Corporation |
Annual Information Form |
Last updated December 8, 2009
I. PURPOSE
The Audit Committee (the Committee) is appointed by the Board of Directors of EnCana Corporation (the Corporation) to assist the Board in fulfilling its oversight responsibilities.
The Committees primary duties and responsibilities are to:
· Review managements identification of principal financial risks and monitor the process to manage such risks.
· Oversee and monitor the Corporations compliance with legal and regulatory requirements.
· Receive and review the reports of the Audit Committee of any subsidiary with public securities.
· Oversee and monitor the integrity of the Corporations accounting and financial reporting processes, financial statements and system of internal controls regarding accounting and financial reporting and accounting compliance.
· Oversee audits of the Corporations financial statements.
· Oversee and monitor the qualifications, independence and performance of the Corporations external auditors and internal auditing department.
· Provide an avenue of communication among the external auditors, management, the internal auditing department, and the Board of Directors.
· Report to the Board of Directors regularly.
The Committee has the authority to conduct any review or investigation appropriate to fulfilling its responsibilities. The Committee shall have unrestricted access to personnel and information, and any resources necessary to carry out its responsibility. In this regard, the Committee may direct internal audit personnel to particular areas of examination.
II. COMPOSITION AND MEETINGS
Committee Members Duties in addition to those of a Director
The duties and responsibilities of a member of the Committee are in addition to those duties set out for a member of the Board of Directors.
Composition
The Committee shall consist of not less than three and not more than five directors as determined by the Board, all of whom shall qualify as independent directors pursuant to National Instrument 52-110 Audit Committees (as implemented by the Canadian Securities Administrators and as amended from time to time) (NI 52-110).
All members of the Committee shall be financially literate, as defined in NI 52-110, and at least one member shall have accounting or related financial managerial expertise. In particular, at least one member shall have, through (i) education and experience as a principal financial officer, principal accounting officer, controller, public accountant or auditor or experience in one or more positions that involve the performance of similar functions; (ii) experience actively supervising a principal financial officer, principal accounting officer, controller, public accountant, auditor or person performing similar functions; (iii) experience overseeing or assessing the performance of companies or public accountants with respect to the preparation, auditing or evaluation of financial statements; or (iv) other relevant experience:
· An understanding of generally accepted accounting principles and financial statements;
EnCana Corporation |
Annual Information Form |
· The ability to assess the general application of such principles in connection with the accounting for estimates, accruals and reserves;
· Experience preparing, auditing, analyzing or evaluating financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues that can reasonably be expected to be raised by the Corporations financial statements, or experience actively supervising one or more persons engaged in such activities;
· An understanding of internal controls and procedures for financial reporting; and
· An understanding of audit committee functions.
Committee members may not, other than in their respective capacities as members of the Committee, the Board or any other committee of the Board, accept directly or indirectly any consulting, advisory or other compensatory fee from the Corporation or any subsidiary of the Corporation, or be an affiliated person (as such term is defined in the United States Securities Exchange Act of 1934, as amended (the Exchange Act), and the rules adopted by the U.S. Securities and Exchange Commission (SEC) thereunder) of the Corporation or any subsidiary of the Corporation. For greater certainty, directors fees and fixed amounts of compensation under a retirement plan (including deferred compensation) for prior service with the Corporation that are not contingent on continued service should be the only compensation an audit committee member receives from the Corporation.
At least one member shall have experience in the oil and gas industry.
Committee members shall not simultaneously serve on the audit committees of more than two other public companies, unless the Board first determines that such simultaneous service will not impair the ability of the relevant members to effectively serve on the Committee, and required public disclosure is made.
The non-executive Board Chairman shall be a non-voting member of the Committee. See Quorum for further details.
Appointment of Members
Committee members shall be appointed at a meeting of the Board, effective after the election of directors at the annual meeting of shareholders, provided that any member may be removed or replaced at any time by the Board and shall, in any event, cease to be a member of the Committee upon ceasing to be a member of the Board.
The Nominating and Corporate Governance Committee will recommend for approval to the Board an unrelated
Director to act as Chairman of the Committee. The Board shall appoint the Chairman of the Committee.
If the Chairman of the Committee is unavailable or unable to attend a meeting of the Committee, the Chair shall ask another member to chair the meeting, failing which a member of the Committee present at the meeting shall be chosen to preside over the meeting by a majority of the members of the Committee present at such meeting.
The Chairman of the Committee presiding at any meeting of the Committee shall not have a casting vote.
The items pertaining to the Chairman in this section should be read in conjunction with the Committee Chair section of the Chair of the Board of Directors and Committee Chair General Guidelines.
Where a vacancy occurs at any time in the membership of the Committee, it may be filled by the Board.
The Corporate Secretary or one of the Assistant Corporate Secretaries of the Corporation or such other person as the Corporate Secretary of the Corporation shall designate from time to time shall be the Secretary of the Committee and shall keep minutes of the meetings of the Committee.
Meetings
Committee meetings may, by agreement of the Chairman of the Committee, be held in person, by video conference, by means of telephone or by a combination of any of the foregoing.
EnCana Corporation |
Annual Information Form |
The Committee shall meet at least quarterly. The Chairman of the Committee may call additional meetings as required. In addition, a meeting may be called by the non-executive Board Chairman, the President & Chief Executive Officer, or any member of the Committee or by the external auditors.
The Committee shall have the right to determine who shall, and who shall not, be present at any time during a meeting of the Committee.
Directors, who are not members of the Committee, may attend Committee meetings, on an ad hoc basis, upon prior consultation and approval by the Committee Chairman or by a majority of the members of the Committee.
The Committee may, by specific invitation, have other resource persons in attendance.
The President & Chief Executive Officer, the Executive Vice-President & Chief Financial Officer, the Executive Vice-President & Chief Accounting Officer and the Vice-President, Financial Compliance & Audit are expected to be available to attend the Committees meetings or portions thereof.
Notice of Meeting
Notice of the time and place of each Committee meeting may be given orally, or in writing, or by facsimile, or by electronic means to each member of the Committee at least 48 hours prior to the time fixed for such meeting. Notice of each meeting shall also be given to the external auditors of the Corporation.
A member and the external auditors may, in any manner, waive notice of the Committee meeting. Attendance of a member at a meeting shall constitute waiver of notice of the meeting except where a member attends a meeting for the express purpose of objecting to the transaction of any business on the grounds that the meeting was not lawfully called.
Quorum
A majority of Committee members, present in person, by video conference, by telephone, or by a combination thereof, shall constitute a quorum. In addition, if an ex officio, non-voting members presence is required to attain a quorum of the Committee, then the said member shall be allowed to cast a vote at the meeting.
Minutes
Minutes of each Committee meeting should be succinct yet comprehensive in describing substantive issues discussed by the Committee. However, they should clearly identify those items of responsibilities scheduled by the Committee for the meeting that have been discharged by the Committee and those items of responsibilities that are outstanding.
Minutes of Committee meetings shall be sent to all Committee members and to the external auditors.
The full Board of Directors shall be kept informed of the Committees activities by a report following each Committee meeting.
III. RESPONSIBILITIES
Review Procedures
Review and update the Committees mandate annually, or sooner, where the Committee deems it appropriate to do so. Provide a summary of the Committees composition and responsibilities in the Corporations annual report or other public disclosure documentation.
Provide a summary of all approvals by the Committee of the provision of audit, audit-related, tax and other services by the external auditors for inclusion in the Corporations annual report filed with the SEC.
EnCana Corporation |
Annual Information Form |
Annual Financial Statements
1. Discuss and review with management and the external auditors the Corporations and any subsidiary with public securities annual audited financial statements and related documents prior to their filing or distribution. Such review to include:
a. The annual financial statements and related footnotes including significant issues regarding accounting principles, practices and significant management estimates and judgments, including any significant changes in the Corporations selection or application of accounting principles, any major issues as to the adequacy of the Corporations internal controls and any special steps adopted in light of material control deficiencies.
b. Managements Discussion and Analysis.
c. A review of the use of off-balance sheet financing including managements risk assessment and adequacy of disclosure.
d. A review of the external auditors audit examination of the financial statements and their report thereon.
e. Review of any significant changes required in the external auditors audit plan.
f. A review of any serious difficulties or disputes with management encountered during the course of the audit, including any restrictions on the scope of the external auditors work or access to required information.
g. A review of other matters related to the conduct of the audit, which are to be communicated to the Committee under generally accepted auditing standards.
2. Review and formally recommend approval to the Board of the Corporations:
a. Year-end audited financial statements. Such review shall include discussions with management and the external auditors as to:
(i) The accounting policies of the Corporation and any changes thereto.
(ii) The effect of significant judgements, accruals and estimates.
(iii) The manner of presentation of significant accounting items.
(iv) The consistency of disclosure.
b. Managements Discussion and Analysis.
c. Annual Information Form as to financial information.
d. All prospectuses and information circulars as to financial information.
The review shall include a report from the external auditors about the quality of the most critical accounting principles upon which the Corporations financial status depends, and which involve the most complex, subjective or significant judgemental decisions or assessments.
Quarterly Financial Statements
3. Review with management and the external auditors and either approve (such approval to include the authorization for public release) or formally recommend for approval to the Board the Corporations:
a. Quarterly unaudited financial statements and related documents, including Managements Discussion and Analysis.
b. Any significant changes to the Corporations accounting principles.
EnCana Corporation |
Annual Information Form |
Review quarterly unaudited financial statements of any subsidiary of the Corporation with public securities prior to their distribution.
Other Financial Filings and Public Documents
4. Review and discuss with management financial information, including earnings press releases, the use of pro forma or non-GAAP financial information and earnings guidance, contained in any filings with the securities regulators or news releases related thereto (or provided to analysts or rating agencies) and consider whether the information is consistent with the information contained in the financial statements of the Corporation or any subsidiary with public securities. Such discussion may be done generally (consisting of discussing the types of information to be disclosed and the types of presentations to be made).
Internal Control Environment
5. Ensure that management, the external auditors, and the internal auditors provide to the Committee an annual report on the Corporations control environment as it pertains to the Corporations financial reporting process and controls.
6. Review and discuss significant financial risks or exposures and assess the steps management has taken to monitor, control, report and mitigate such risk to the Corporation.
7. Review significant findings prepared by the external auditors and the internal auditing department together with managements responses.
8. Review in consultation with the internal auditors and the external auditors the degree of coordination in the audit plans of the internal auditors and the external auditors and enquire as to the extent the planned scope can be relied upon to detect weaknesses in internal controls, fraud, or other illegal acts. The Committee will assess the coordination of audit effort to assure completeness of coverage and the effective use of audit resources. Any significant recommendations made by the auditors for the strengthening of internal controls shall be reviewed and discussed with management.
Other Review Items
9. Review policies and procedures with respect to officers and directors expense accounts and perquisites, including their use of corporate assets, and consider the results of any review of these areas by the internal auditor or the external auditors.
10. Review all related party transactions between the Corporation and any officers or directors, including affiliations of any officers or directors.
11. Review with the General Counsel, the head of internal audit and the external auditors the results of their review of the Corporations monitoring compliance with each of the Corporations published codes of business conduct and applicable legal requirements.
12. Review legal and regulatory matters, including correspondence with regulators and governmental agencies, that may have a material impact on the interim or annual financial statements, related corporation compliance policies, and programs and reports received from regulators or governmental agencies. Members from the Legal and Tax departments should be at the meeting in person to deliver their reports.
13. Review policies and practices with respect to off-balance sheet transactions and trading and hedging activities, and consider the results of any review of these areas by the internal auditors or the external auditors.
14. Ensure that the Corporations presentations on net proved reserves have been reviewed with the Reserves Committee of the Board.
EnCana Corporation |
Annual Information Form |
15. Review managements processes in place to prevent and detect fraud.
16. Review procedures for the receipt, retention and treatment of complaints received by the Corporation, including confidential, anonymous submissions by employees of the Corporation, regarding accounting, internal accounting controls, or auditing matters.
17. Review with the President & Chief Executive Officer, the Executive Vice-President & Chief Financial Officer of the Corporation and the external auditors: (i) all significant deficiencies and material weaknesses in the design or operation of the Corporations internal controls and procedures for financial reporting which could adversely affect the Corporations ability to record, process, summarize and report financial information required to be disclosed by the Corporation in the reports that it files or submits under the Exchange Act or applicable Canadian federal and provincial legislation and regulations within the required time periods, and (ii) any fraud, whether or not material, that involves management of the Corporation or other employees who have a significant role in the Corporations internal controls and procedures for financial reporting.
18. Meet on a periodic basis separately with management.
External Auditors
19. Be directly responsible, in the Committees capacity as a committee of the Board and subject to the rights of shareholders and applicable law, for the appointment, compensation, retention and oversight of the work of the external auditors (including resolution of disagreements between management and the external auditors regarding financial reporting) for the purpose of preparing or issuing an audit report, or performing other audit, review or attest services for the Corporation. The external auditors shall report directly to the Committee.
20. Meet on a regular basis with the external auditors (without management present) and have the external auditors be available to attend Committee meetings or portions thereof at the request of the Chairman of the Committee or by a majority of the members of the Committee.
21. Review and discuss a report from the external auditors at least quarterly regarding:
a. All critical accounting policies and practices to be used;
b. All alternative treatments within generally accepted accounting principles for policies and practices related to material items that have been discussed with management, including the ramifications of the use of such alternative disclosures and treatments, and the treatment preferred by the external auditors; and
c. Other material written communications between the external auditors and management, such as any management letter or schedule of unadjusted differences.
22. Obtain and review a report from the external auditors at least annually regarding:
a. The external auditors internal quality-control procedures.
b. Any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, respecting one or more independent audits carried out by the external auditors, and any steps taken to deal with those issues.
c. To the extent contemplated in the following paragraph, all relationships between the external auditors and the Corporation.
23. Review and discuss with the external auditors all relationships that the external auditors and their affiliates have with the Corporation and its affiliates in order to determine the external auditors independence, including, without limitation, (i) receiving and reviewing, as part of the report described in the preceding paragraph, a formal written statement from the external auditors delineating all relationships that may
EnCana Corporation |
Annual Information Form |
reasonably be thought to bear on the independence of the external auditors with respect to the Corporation and its affiliates, (ii) discussing with the external auditors any disclosed relationships or services that the external auditors believe may affect the objectivity and independence of the external auditors, and (iii) recommending that the Board take appropriate action in response to the external auditors report to satisfy itself of the external auditors independence.
24. Review and evaluate:
a. The external auditors and the lead partner of the external auditors teams performance, and make a recommendation to the Board of Directors regarding the reappointment of the external auditors at the annual meeting of the Corporations shareholders or regarding the discharge of such external auditors.
b. The terms of engagement of the external auditors together with their proposed fees.
c. External audit plans and results.
d. Any other related audit engagement matters.
e. The engagement of the external auditors to perform non-audit services, together with the fees therefor, and the impact thereof, on the independence of the external auditors.
25. Upon reviewing and discussing the information provided to the Committee in accordance with paragraphs 21 through 24, evaluate the external auditors qualifications, performance and independence, including whether or not the external auditors quality controls are adequate and the provision of permitted non-audit services is compatible with maintaining auditor independence, taking into account the opinions of management and the head of internal audit. The Committee shall present its conclusions with respect to the external auditors to the Board.
26. Ensure the rotation of partners on the audit engagement team in accordance with applicable law. Consider whether, in order to assure continuing external auditor independence, it is appropriate to adopt a policy of rotating the external auditing firm on a regular basis.
27. Set clear hiring policies for the Corporations hiring of employees or former employees of the external auditors.
28. Consider with management and the external auditors the rationale for employing audit firms other than the principal external auditors.
29. Consider and review with the external auditors, management and the head of internal audit:
a. Significant findings during the year and managements responses and follow-up thereto.
b. Any difficulties encountered in the course of their audits, including any restrictions on the scope of their work or access to required information, and managements response.
c. Any significant disagreements between the external auditors or internal auditors and management.
d. Any changes required in the planned scope of their audit plan.
e. The resources, budget, reporting relationships, responsibilities and planned activities of the internal auditors.
f. The internal audit department mandate.
g. Internal audits compliance with the Institute of Internal Auditors standards.
Internal Audit Department and Independence
30. Meet on a periodic basis separately with the head of internal audit.
EnCana Corporation |
Annual Information Form |
31. Review and concur in the appointment, compensation, replacement, reassignment, or dismissal of the head of internal audit.
32. Confirm and assure, annually, the independence of the internal audit department and the external auditors.
Approval of Audit and Non-Audit Services
33. Review and, where appropriate, approve the provision of all permitted non-audit services (including the fees and terms thereof) in advance of the provision of those services by the external auditors (subject to the de minimus exception for non-audit services described in the Exchange Act or applicable Canadian federal and provincial legislation and regulations which are approved by the Committee prior to the completion of the audit).
34. Review and, where appropriate and permitted, approve the provision of all audit services (including the fees and terms thereof) in advance of the provision of those services by the external auditors.
35. If the pre-approvals contemplated in paragraphs 33 and 34 are not obtained, approve, where appropriate and permitted, the provision of all audit and non-audit services promptly after the Committee or a member of the Committee to whom authority is delegated becomes aware of the provision of those services.
36. Delegate, if the Committee deems necessary or desirable, to subcommittees consisting of one or more members of the Committee, the authority to grant the pre-approvals and approvals described in paragraphs 33 through 35. The decision of any such subcommittee to grant pre-approval shall be presented to the full Committee at the next scheduled Committee meeting.
37. The Committee may establish policies and procedures for the pre-approvals described in paragraphs 33 and 34, so long as such policies and procedures are detailed as to the particular service, the Committee is informed of each service and such policies and procedures do not include delegation of the Committees responsibilities under the Exchange Act or applicable Canadian federal and provincial legislation and regulations to management.
Other Matters
38. Review and concur in the appointment, replacement, reassignment, or dismissal of the Chief Financial Officer.
39. Upon a majority vote of the Committee outside resources may be engaged where and if deemed advisable.
40. Report Committee actions to the Board of Directors with such recommendations, as the Committee may deem appropriate.
41. Conduct or authorize investigations into any matters within the Committees scope of responsibilities. The Committee shall be empowered to retain, obtain advice or otherwise receive assistance from independent counsel, accountants, or others to assist it in the conduct of any investigation as it deems necessary and the carrying out of its duties.
42. The Corporation shall provide for appropriate funding, as determined by the Committee in its capacity as a committee of the Board, for payment (i) of compensation to the external auditors for the purpose of preparing or issuing an audit report or performing other audit, review or attest services for the Corporation, (ii) of compensation to any advisors employed by the Committee and (iii) of ordinary administrative expenses of the Committee that are necessary or appropriate in carrying out its duties.
43. Obtain assurance from the external auditors that disclosure to the Committee is not required pursuant to the provisions of the Exchange Act regarding the discovery of illegal acts by the external auditors.
EnCana Corporation |
Annual Information Form |
44. The Committee shall review and reassess the adequacy of this Mandate annually and recommend any proposed changes to the Board for approval.
45. The Committees performance shall be evaluated annually by the Nominating and Corporate Governance Committee of the Board of Directors.
46. Perform such other functions as required by law, the Corporations mandate or bylaws, or the Board of Directors.
47. Consider any other matters referred to it by the Board of Directors.
EnCana Corporation |
Annual Information Form |
EnCana Corporation
Managements Discussion and Analysis
For the year ended December 31, 2009
(U.S. Dollars)
Managements Discussion and Analysis
This Managements Discussion and Analysis (MD&A) for EnCana Corporation (EnCana or the Company) should be read with the audited Consolidated Financial Statements for the year ended December 31, 2009, the audited Consolidated Financial Statements and MD&A for the year ended December 31, 2008, the unaudited Pro Forma Consolidated Financial Information for the year ended December 31, 2009 presented in EnCanas Supplemental Information, the unaudited Pro Forma Consolidated Financial Statements for the period ended September 30, 2009, as well as EnCanas Information Circular Relating to an Arrangement Involving Cenovus Energy Inc. dated October 20, 2009.
The Consolidated Financial Statements and comparative information have been prepared in United States (U.S.) dollars, except where another currency has been indicated, and in accordance with Canadian Generally Accepted Accounting Principles (GAAP). Production volumes are presented on an after royalties basis consistent with U.S. oil and gas disclosures reporting. This document is dated February 17, 2010.
Readers should also read the Advisory section located at the end of this document, which provides information on Forward-Looking Statements, Oil and Gas Information and Currency, Pro Forma Information, Non-GAAP Measures and References to EnCana.
EnCanas Strategic Objectives
EnCana is one of North Americas leading natural gas producers, focusing on the development of unconventional natural gas resources across North America. EnCana holds a diversified portfolio of prolific shale and other gas resource plays in key basins stretching from northeast British Columbia to Louisiana.
EnCana continues to focus on strong, sustainable production growth from unconventional natural gas plays in major North American basins. EnCanas Corporate Guidance is available on the Companys website at www.encana.com.
EnCana remains highly focused on key business objectives of maintaining financial strength, optimizing capital investments and continuing to pay a stable dividend to shareholders attained through a disciplined approach to capital spending, a flexible investment program and financial stewardship. EnCana has been consistently among the lowest cost companies in the natural gas industry and has a history of entering resource plays early and leveraging technology to unlock unconventional resources.
EnCana has a strong balance sheet and continues to employ a conservative capital structure and market risk mitigation strategy. EnCana targets a Debt to Capitalization ratio of less than 40 percent and a Debt to Adjusted EBITDA of less than 2.0 times. At December 31, 2009, the Companys Debt to Capitalization ratio was 32 percent and consolidated Debt to Adjusted EBITDA was 1.3 times. In addition, the Company had approximately $4.3 billion in cash and short-term investments primarily as a result of a corporate reorganization more fully described in EnCanas Business section of this MD&A. As of January 31, 2010, EnCana has hedged approximately 2.0 billion cubic feet (Bcf) per day (Bcf/d) of expected 2010 gas production using NYMEX fixed price contracts at an average price of $6.04 per thousand cubic feet (Mcf). In addition, EnCana has hedged approximately 935 MMcf/d of expected 2011 gas production at an average price of $6.52 per Mcf, and approximately 870 MMcf/d of expected 2012 gas production at an average price of $6.47 per Mcf. During 2009, EnCana benefited from its commodity price hedging program, which resulted in consolidated realized after-tax hedging gains of $2.9 billion.
EnCanas Business
On November 30, 2009, EnCana completed a corporate reorganization (the Split Transaction) to split into two independent publicly traded energy companies EnCana Corporation, a natural gas company, and Cenovus Energy Inc. (Cenovus), an integrated oil company.
The Split Transaction was initially proposed in May 2008 and was designed to enhance long-term value for shareholders by creating two independent and sustainable companies, each with the ability to pursue and achieve greater success by employing operational strategies best suited to its unique assets and business plan. In October 2008, due to an unusually high level of uncertainty and volatility in the global debt and equity markets, EnCana delayed seeking shareholder and court approval for the Split Transaction until there were clear signs that the global financial markets had stabilized. In September 2009, EnCana announced plans to proceed with the split.
EnCana Corporation 2009 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Under the Split Transaction, EnCana shareholders received one new EnCana Common Share and one Cenovus Common Share for each EnCana Common Share previously held. As at December 31, 2009, EnCana had 751.3 million Common Shares outstanding (2008 750.4 million; 2007 750.2 million).
EnCanas operating and reportable segments are as follows:
· Canada includes the Companys exploration for, and development and production of natural gas, crude oil and natural gas liquids (NGLs) and other related activities within the Canadian cost centre.
· USA includes the Companys exploration for, and development and production of natural gas, NGLs and other related activities within the United States cost centre.
· Market Optimization is primarily responsible for the sale of the Companys 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 sells substantially all of the Companys upstream production to third-party customers. Transactions between segments are based on market values and eliminated on consolidation. Financial information is presented on an after eliminations basis.
EnCanas operations are currently divided into two operating divisions:
· Canadian Division, formerly the Canadian Foothills Division, which includes natural gas development and production assets located in British Columbia and Alberta, and the Deep Panuke natural gas project offshore Nova Scotia. Four key resource plays are located in the Division: (i) Greater Sierra in northeast British Columbia, including the Horn River shale play; (ii) Cutbank Ridge on the Alberta and British Columbia border, including the Montney formation; (iii) Bighorn in west central Alberta; and (iv) Coalbed Methane (CBM) in southern Alberta.
· USA Division, which includes the natural gas development and production assets located in the U.S. Four key resource plays are located in the Division: (i) Jonah in southwest Wyoming; (ii) Piceance in northwest Colorado; (iii) East Texas in Texas; and (iv) Fort Worth in Texas. The USA Division is also focused on the development of the Haynesville shale play located in Louisiana and Texas and the recent entrance into the Marcellus shale play located in Pennsylvania.
In conjunction with the Split Transaction, the upstream assets formerly included in EnCanas Canadian Plains Division and Integrated Oil Division were transferred to Cenovus. As a result, EnCana has updated its reporting, and the Canadian Plains and Integrated Oil Canada are now presented as Canada Other. Canada Other results are reported as continuing operations. The U.S. Downstream Refining assets were also transferred to Cenovus. U.S. Downstream Refining results prior to the November 30, 2009 Split Transaction are reported in Discontinued Operations. Prior periods have been restated to reflect the new presentation.
Pro Forma and Consolidated Reporting
This MD&A presents the financial and operating results of EnCana on both a pro forma and consolidated basis.
EnCanas pro forma results exclude the results of operations from assets transferred to Cenovus as part of the Split Transaction and reflect expected changes to EnCanas historical results that would arise from the Split Transaction, including income tax, depreciation, depletion and amortization (DD&A) and transaction costs. This information is presented to assist in understanding EnCanas historical financial results associated with the assets remaining in EnCana as a result of the Split Transaction.
EnCanas 2009 consolidated results include 12 months of EnCana operations and 11 months of Cenovus operations. Consolidated results for 2008 and 2007 include 12 months of EnCana and Cenovus operations.
EnCana Corporation 2009 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Non-GAAP Measures
This MD&A contains certain non-GAAP measures commonly used in the oil and gas industry and by EnCana to provide shareholders and potential investors with additional information regarding the Companys liquidity and its ability to generate funds to finance its operations. Further information can be found in the Reconciliations of Non-GAAP Measures section of this MD&A.
Cash Flow is a non-GAAP measure defined as cash from operating activities excluding net change in other assets and liabilities, net change in non-cash working capital and net change in non-cash working capital from Discontinued Operations. Cash Flow is commonly used in the oil and gas industry and by EnCana to assist Management and investors in measuring the Companys ability to finance capital programs and meet financial obligations.
Operating Earnings is a non-GAAP measure that adjusts Net Earnings by non-operating items that Management believes reduces the comparability of the Companys underlying financial performance between periods. Operating Earnings is commonly used in the oil and gas industry and by EnCana to provide investors with information that is more comparable between periods.
2009 Pro Forma Overview
In 2009, EnCana reported pro forma:
· Cash Flow of $5,021 million;
· Operating Earnings of $1,767 million;
· Net Earnings of $749 million;
· Total production of 3,003 million cubic feet equivalent (MMcfe) per day (MMcfe/d);
· Realized financial natural gas, crude oil and other commodity hedging gains of $2,250 million after-tax;
· Capital investment of $3,755 million; and
· Average natural gas prices, excluding financial hedges, of $3.73 per Mcf and average liquids prices, excluding financial hedges, of $48.15 per barrel (bbl).
2009 Consolidated Overview
In 2009, EnCana reported:
· Completion of its plan to split into two independent publicly traded energy companies on November 30, 2009;
· Cash Flow of $6,779 million;
· Operating Earnings of $3,495 million;
· Net Earnings of $1,862 million;
· Total production of 4,365 MMcfe/d;
· Realized financial natural gas, crude oil and other commodity hedging gains of $2,935 million after-tax;
· Capital investment of $5,454 million; and
· Average natural gas prices, excluding financial hedges, of $3.69 per Mcf and average liquids prices, excluding financial hedges, of $49.65 per bbl.
Business Environment
EnCanas financial results were significantly influenced by fluctuations in commodity prices, which included price differentials, and the U.S./Canadian dollar exchange rate. EnCana has taken steps to reduce pricing risk through a commodity price hedging program. Further information regarding this program can be found in the Risk Management section of this MD&A and Note 20 to the Consolidated Financial Statements. The following table shows benchmark information on a quarterly basis to assist in understanding quarterly volatility in prices and foreign exchange rates that have impacted EnCanas financial results.
EnCana Corporation 2009 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Quarterly Market Benchmark Prices and Foreign Exchange Rates
(Average for the period) |
|
|
2009 |
|
Q4 |
|
Q3 |
|
Q2 |
|
Q1 |
|
2008 |
|
Q4 |
|
Q3 |
|
Q2 |
|
Q1 |
|
2007 |
|
|||||||||||
Natural Gas Price Benchmarks |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
AECO (C$/Mcf) |
|
|
$ |
4.14 |
|
$ |
4.23 |
|
$ |
3.02 |
|
$ |
3.66 |
|
$ |
5.63 |
|
$ |
8.13 |
|
$ |
6.79 |
|
$ |
9.24 |
|
$ |
9.35 |
|
$ |
7.13 |
|
$ |
6.61 |
|
NYMEX ($/MMBtu) |
|
|
3.99 |
|
4.17 |
|
3.39 |
|
3.50 |
|
4.89 |
|
9.04 |
|
6.94 |
|
10.24 |
|
10.93 |
|
8.03 |
|
6.86 |
|
|||||||||||
Rockies (Opal) ($/MMBtu) |
|
|
3.09 |
|
3.97 |
|
2.69 |
|
2.37 |
|
3.31 |
|
6.25 |
|
3.53 |
|
5.88 |
|
8.56 |
|
7.02 |
|
3.95 |
|
|||||||||||
Texas (HSC) ($/MMBtu) |
|
|
3.78 |
|
4.16 |
|
3.31 |
|
3.44 |
|
4.21 |
|
8.67 |
|
6.37 |
|
9.98 |
|
10.58 |
|
7.73 |
|
6.58 |
|
|||||||||||
Basis Differential ($/MMBtu) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
AECO/NYMEX |
|
|
0.40 |
|
0.19 |
|
0.67 |
|
0.39 |
|
0.35 |
|
1.23 |
|
1.10 |
|
1.28 |
|
1.71 |
|
0.84 |
|
0.75 |
|
|||||||||||
Rockies/NYMEX |
|
|
0.90 |
|
0.20 |
|
0.70 |
|
1.13 |
|
1.58 |
|
2.79 |
|
3.41 |
|
4.36 |
|
2.37 |
|
1.01 |
|
2.91 |
|
|||||||||||
Texas/NYMEX |
|
|
0.21 |
|
0.01 |
|
0.08 |
|
0.06 |
|
0.68 |
|
0.37 |
|
0.58 |
|
0.26 |
|
0.35 |
|
0.30 |
|
0.28 |
|
|||||||||||
Crude Oil Price Benchmarks |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
West Texas Intermediate (WTI) ($/bbl) |
|
|
62.09 |
|
76.13 |
|
68.24 |
|
59.79 |
|
43.31 |
|
99.75 |
|
59.08 |
|
118.22 |
|
123.80 |
|
97.82 |
|
72.41 |
|
|||||||||||
Western Canadian Select (WCS) ($/bbl) |
|
|
52.43 |
|
64.01 |
|
58.06 |
|
52.37 |
|
34.38 |
|
79.70 |
|
39.95 |
|
100.22 |
|
102.18 |
|
76.37 |
|
49.50 |
|
|||||||||||
Differential WTI/WCS ($/bbl) |
|
|
9.66 |
|
12.12 |
|
10.18 |
|
7.42 |
|
8.93 |
|
20.05 |
|
19.13 |
|
18.00 |
|
21.62 |
|
21.45 |
|
22.91 |
|
|||||||||||
Foreign Exchange |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
U.S./Canadian Dollar Exchange Rate |
|
|
0.876 |
|
0.947 |
|
0.911 |
|
0.857 |
|
0.803 |
|
0.938 |
|
0.825 |
|
0.961 |
|
0.990 |
|
0.996 |
|
0.930 |
|
|||||||||||
Pro Forma Financial Results
The following table presents selected historical pro forma financial information related to EnCanas ongoing operations only and should be read with the unaudited Pro Forma Consolidated Financial Information for the year ended December 31, 2009 presented in EnCanas Supplemental Information, the unaudited Pro Forma Consolidated Financial Statements for the period ended September 30, 2009, as well as the unaudited Pro Forma Consolidated Financial Statements for the period ended June 30, 2009 and year ended December 31, 2008 presented in EnCanas Information Circular Relating to an Arrangement Involving Cenovus Energy Inc. dated October 20, 2009. The information excludes the results of operations from assets transferred to Cenovus as part of the Split Transaction and reflects expected changes to EnCanas historical results that would arise from the Split Transaction, including income tax, DD&A and transaction costs. This information is presented to assist in understanding EnCanas historical financial results associated with the assets remaining in EnCana as a result of the Split Transaction.
($ millions, except per share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
amounts) |
|
|
2009 |
|
Q4 |
|
Q3 |
|
Q2 |
|
Q1 |
|
2008 |
|
Q4 |
|
Q3 |
|
Q2 |
|
Q1 |
|||||||||||
Pro Forma Cash Flow (1) |
|
|
$ |
5,021 |
|
$ |
930 |
|
$ |
1,274 |
|
$ |
1,430 |
|
$ |
1,387 |
|
$ |
6,354 |
|
$ |
1,502 |
|
$ |
1,734 |
|
$ |
1,661 |
|
$ |
1,457 |
|
per share diluted |
|
|
6.68 |
|
1.24 |
|
1.70 |
|
1.90 |
|
1.85 |
|
8.45 |
|
2.00 |
|
2.31 |
|
2.21 |
|
1.93 |
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Pro Forma Operating Earnings (2) |
|
|
1,767 |
|
373 |
|
378 |
|
472 |
|
544 |
|
2,605 |
|
546 |
|
805 |
|
703 |
|
551 |
|
||||||||||
per share diluted |
|
|
2.35 |
|
0.50 |
|
0.50 |
|
0.63 |
|
0.72 |
|
3.47 |
|
0.73 |
|
1.07 |
|
0.94 |
|
0.73 |
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Pro Forma Net Earnings |
|
|
749 |
|
233 |
|
(53) |
|
92 |
|
477 |
|
3,405 |
|
671 |
|
2,228 |
|
643 |
|
(137 |
) |
||||||||||
per share diluted |
|
|
1.00 |
|
0.31 |
|
(0.07) |
|
0.12 |
|
0.63 |
|
4.53 |
|
0.89 |
|
2.97 |
|
0.86 |
|
(0.18 |
) |
||||||||||
(1) Pro Forma Cash Flow is a non-GAAP measure. See Reconciliations of Non-GAAP Measures section of this MD&A. |
(2) Pro Forma Operating Earnings is a non-GAAP measure. See Reconciliations of Non-GAAP Measures section of this MD&A. |
Pro Forma Cash Flow
2009 versus 2008
Pro Forma Cash Flow of $5,021 million decreased $1,333 million as a result of:
· Average total natural gas prices, excluding financial hedges, decreased to $3.73 per Mcf in 2009 compared to $7.99 per Mcf in 2008;
· Average total liquids prices, excluding financial hedges, decreased to $48.15 per bbl in 2009 compared to $84.38 per bbl in 2008; and
· Natural gas production volumes in 2009 decreased to 2,840 million cubic feet (MMcf) per day (MMcf/d) from 2,933 MMcf/d in 2008. The decrease was primarily a result of shut-in and curtailed production as well as delayed well completions and tie-ins due to the low price environment, partially offset by lower royalties;
EnCana Corporation 2009 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
partially offset by:
· Realized financial natural gas, crude oil and other commodity hedging gains of $2,250 million after-tax in 2009 compared to losses of $6 million after-tax in 2008; and
· Lower production and mineral taxes, operating expenses and transportation and selling costs primarily due to the lower U.S./Canadian dollar exchange rate and cost savings measures.
EnCana reported 2009 Pro Forma Cash Flow of $5,021 million compared to $4,200 million in its Corporate Guidance dated November 12, 2009. Actual pro forma results were higher than Corporate Guidance primarily due to the inclusion, in Corporate Guidance, of current tax related to the wind-up of the Canadian oil and gas partnership and transaction costs related to the Split Transaction as disclosed in the document.
Q4 2009 versus Q4 2008
Pro Forma Cash Flow of $930 million decreased $572 million as a result of:
· Average total natural gas prices, excluding financial hedges, decreased to $4.47 per Mcf in 2009 compared to $5.39 per Mcf in 2008; and
· Natural gas production volumes in 2009 decreased to 2,687 MMcf/d from 2,979 MMcf/d in 2008. The decrease was primarily a result of shut-in and curtailed production as well as delayed well completions and tie-ins due to the low price environment, partially offset by lower royalties.
Pro Forma Operating Earnings
Summary of Pro Forma Operating Earnings
|
|
2009 |
|
|
2008 |
|||||||||
($ millions, except per share amounts) |
|
|
Per share(1) |
|
|
|
|
Per share(1) |
|
|||||
Pro Forma Net Earnings, as reported |
|
$ |
749 |
|
$ |
1.00 |
|
|
$ |
3,405 |
|
$ |
4.53 |
|
Add back (losses) and deduct gains: |
|
|
|
|
|
|
|
|
|
|
||||
Unrealized mark-to-market accounting gain (loss), after-tax |
|
(1,352 |
) |
(1.80 |
) |
|
1,299 |
|
1.73 |
|
||||
Non-operating foreign exchange gain (loss), after-tax |
|
334 |
|
0.45 |
|
|
(598 |
) |
(0.80 |
) |
||||
Gain (loss) on discontinuance, after-tax |
|
- |
|
- |
|
|
99 |
|
0.13 |
|
||||
Pro Forma Operating Earnings |
|
$ |
1,767 |
|
$ |
2.35 |
|
|
$ |
2,605 |
|
$ |
3.47 |
|
(1) Per Common Share diluted.
2009 versus 2008
Pro Forma Operating Earnings of $1,767 million decreased $838 million. In addition to the items affecting Pro Forma Cash Flow described previously, a significant item affecting Pro Forma Operating Earnings was:
· Lower DD&A of $326 million primarily due to lower production volumes and the lower U.S./Canadian dollar exchange rate.
Pro Forma Net Earnings
2009 versus 2008
Pro Forma Net Earnings of $749 million decreased $2,656 million. Significant items affecting Pro Forma Net Earnings were:
· Lower average total natural gas and total liquids prices, excluding financial hedges, as well as lower natural gas production volumes as discussed in the Pro Forma Cash Flow section of this MD&A; and
· The net impact of realized and unrealized hedging, after-tax, which resulted in an $898 million increase to Pro Forma Net Earnings in 2009 compared to a $1,293 million increase to Pro Forma Net Earnings in 2008;
partially offset by:
· Non-operating foreign exchange gains of $334 million after-tax in 2009 compared to losses of $598 million after-tax in 2008;
· Lower costs of operations as discussed in the Pro Forma Cash Flow section of this MD&A; and
· Lower DD&A of $326 million primarily due to lower production volumes and the lower U.S./Canadian dollar exchange rate.
EnCana Corporation 2009 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Q4 2009 versus Q4 2008
Pro Forma Net Earnings of $233 million decreased $438 million. Significant items affecting Pro Forma Net Earnings were:
· Lower average total natural gas prices, excluding financial hedges, as well as lower natural gas production volumes as discussed in the Pro Forma Cash Flow section of this MD&A; and
· The net impact of realized and unrealized hedging, after-tax, which resulted in a $193 million increase to Pro Forma Net Earnings in 2009 compared to an $818 million increase to Pro Forma Net Earnings in 2008;
partially offset by:
· Non-operating foreign exchange losses of $5 million after-tax in 2009 compared to losses of $350 million after-tax in 2008.
Summary of Hedging Impacts on Pro Forma Net Earnings
($ millions) |
|
2009 |
|
2008 |
|
|
Q4 2009 |
|
Q4 2008 |
|
|||
Unrealized Mark-to-Market Gains (Losses), after-tax(1) |
$ |
(1,352 |
) |
$ |
1,299 |
|
|
$ |
(135 |
) |
$ |
475 |
|
Realized Hedging Gains (Losses), after-tax (2) |
|
2,250 |
|
|
(6 |
) |
|
|
328 |
|
|
343 |
|
Hedging Impacts on Net Earnings |
$ |
898 |
|
$ |
1,293 |
|
|
$ |
193 |
|
$ |
818 |
|
(1) Included in Corporate and Other financial results. Further detail on unrealized mark-to-market gains (losses) can be found in the Corporate and Other section of this MD&A.
(2) Included in Divisional financial results.
Consolidated Financial Results
($ millions, except per share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
amounts) |
|
2009 |
|
Q4 |
|
Q3 |
|
Q2 |
|
Q1 |
|
|
2008 |
|
Q4 |
|
Q3 |
|
Q2 |
|
Q1 |
|
|
2007 |
|
Cash Flow (1) |
$ |
6,779 |
$ |
603 |
$ |
2,079 |
$ |
2,153 |
$ |
1,944 |
|
$ |
9,386 |
$ |
1,299 |
$ |
2,809 |
$ |
2,889 |
$ |
2,389 |
|
$ |
8,453 |
|
per share diluted |
|
9.02 |
|
0.80 |
|
2.77 |
|
2.87 |
|
2.59 |
|
|
12.48 |
|
1.73 |
|
3.74 |
|
3.85 |
|
3.17 |
|
|
11.06 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Earnings (2) |
|
3,495 |
|
855 |
|
775 |
|
917 |
|
948 |
|
|
4,405 |
|
449 |
|
1,442 |
|
1,469 |
|
1,045 |
|
|
4,100 |
|
per share diluted |
|
4.65 |
|
1.14 |
|
1.03 |
|
1.22 |
|
1.26 |
|
|
5.86 |
|
0.60 |
|
1.92 |
|
1.96 |
|
1.39 |
|
|
5.36 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings |
|
1,862 |
|
636 |
|
25 |
|
239 |
|
962 |
|
|
5,944 |
|
1,077 |
|
3,553 |
|
1,221 |
|
93 |
|
|
3,959 |
|
per share diluted |
|
2.48 |
|
0.85 |
|
0.03 |
|
0.32 |
|
1.28 |
|
|
7.91 |
|
1.43 |
|
4.73 |
|
1.63 |
|
0.12 |
|
|
5.18 |
|
(1) Cash Flow is a non-GAAP measure. See Reconciliations of Non-GAAP Measures section of this MD&A.
(2) Operating Earnings is a non-GAAP measure. See Reconciliations of Non-GAAP Measures section of this MD&A.
Consolidated Cash Flow
2009 versus 2008
Cash Flow of $6,779 million decreased $2,607 million as a result of:
· Average total natural gas prices, excluding financial hedges, decreased to $3.69 per Mcf in 2009 compared to $7.94 per Mcf in 2008;
· Average total liquids prices, excluding financial hedges, decreased to $49.65 per bbl in 2009 compared to $76.58 per bbl in 2008; and
· Natural gas production volumes in 2009 decreased to 3,602 MMcf/d from 3,838 MMcf/d in 2008. The decrease was primarily a result of shut-in and curtailed production as well as delayed well completions and tie-ins due to the low price environment and one month less of volumes associated with Cenovus operations;
partially offset by:
· Realized financial natural gas, crude oil and other commodity hedging gains of $2,935 million after-tax in 2009 compared to losses of $219 million after-tax in 2008;
· Lower transportation and selling costs, operating expenses and production and mineral taxes primarily due to one month less of costs associated with Cenovus operations, the lower U.S./Canadian dollar exchange rate and cost savings measures;
· Cash Flow from Discontinued Operations of $149 million in 2009 compared to negative Cash Flow of $441 million in 2008; and
EnCana Corporation 2009 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
· A decrease in current tax, excluding the tax related to realized financial hedges mentioned above, as a result of lower cash flows, partially offset by the incremental current tax expense related to the wind-up of the Canadian oil and gas partnership.
2008 versus 2007
Cash Flow of $9,386 million increased $933 million as a result of:
· Average total natural gas prices, excluding financial hedges, increased to $7.94 per Mcf in 2008 compared to $5.89 per Mcf in 2007;
· Average total liquids prices, excluding financial hedges, increased to $76.58 per bbl in 2008 compared to $50.05 per bbl in 2007;
· Natural gas production volumes in 2008 increased to 3,838 MMcf/d from 3,566 MMcf/d in 2007; and
· A decrease in current tax associated with accelerated write-offs for certain U.S. capital expenditures and increased benefits from international financing, partially offset by a one time tax recovery in 2007 for a Canadian tax legislative change;
partially offset by:
· Negative Cash Flow from Discontinued Operations of $441 million in 2008 compared to Cash Flow of $678 million in 2007;
· Realized financial natural gas, crude oil and other commodity hedging losses of $219 million after-tax in 2008 compared to gains of $1,023 million after-tax in 2007; and
· Higher transportation and selling costs, operating expenses, production and mineral taxes, interest and administrative expenses.
Q4 2009 versus Q4 2008
Cash Flow of $603 million decreased $696 million as a result of:
· Higher current tax primarily related to the wind-up of the Canadian oil and gas partnership;
· Natural gas production volumes in 2009 decreased to 3,204 MMcf/d from 3,858 MMcf/d in 2008. The decrease was primarily a result of one month less of volumes associated with Cenovus operations as well as shut-in and curtailed production as well as delayed well completions and tie-ins due to the low price environment; and
· Average total natural gas prices, excluding financial hedges, decreased to $4.34 per Mcf in 2009 compared to $5.44 per Mcf in 2008;
partially offset by:
· Negative Cash Flow from Discontinued Operations of $13 million in 2009 compared to $593 million in 2008; and
· Average total liquids prices, excluding financial hedges, increased to $62.25 per bbl in 2009 compared to $33.81 per bbl in 2008.
Consolidated Operating Earnings
Summary of Operating Earnings
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
||||||
($ millions, except per share amounts) |
|
|
Per share(1) |
|
|
Per share(1) |
|
|
Per share(1) |
||||||
Net Earnings, as reported |
$ |
1,862 |
$ |
2.48 |
|
$ |
5,944 |
$ |
7.91 |
|
$ |
3,959 |
$ |
5.18 |
|
Add back (losses) and deduct gains: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized mark-to-market accounting gain (loss), after-tax |
|
(1,792 |
) |
(2.38 |
) |
|
1,818 |
|
2.42 |
|
|
(811 |
) |
(1.06 |
) |
Non-operating foreign exchange gain (loss), after-tax |
|
159 |
|
0.21 |
|
|
(378 |
) |
(0.50 |
) |
|
217 |
|
0.28 |
|
Gain (loss) on discontinuance, after-tax |
|
- |
|
- |
|
|
99 |
|
0.13 |
|
|
152 |
|
0.20 |
|
Future tax recovery due to tax rate reductions |
|
- |
|
- |
|
|
- |
|
- |
|
|
301 |
|
0.40 |
|
Operating Earnings |
$ |
3,495 |
$ |
4.65 |
|
$ |
4,405 |
$ |
5.86 |
|
$ |
4,100 |
$ |
5.36 |
|
(1) Per Common Share diluted.
EnCana Corporation 2009 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
2009 versus 2008
Operating Earnings of $3,495 million decreased $910 million. In addition to the items affecting Cash Flow described previously, significant items affecting Operating Earnings were:
· Lower DD&A of $331 million primarily due to lower production volumes and the lower U.S./Canadian dollar exchange rate; and
· Lower future income tax related to the wind-up of the Canadian oil and gas partnership and other items associated with the Split Transaction.
Consolidated Net Earnings
($ millions, except per share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
amounts) |
|
2009 |
|
Q4 |
|
Q3 |
|
Q2 |
|
Q1 |
|
|
2008 |
|
Q4 |
|
Q3 |
|
Q2 |
|
Q1 |
|
|
2007 |
|
Continuing Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings from Continuing Operations |
$ |
1,830 |
$ |
589 |
$ |
39 |
$ |
211 |
$ |
991 |
|
$ |
6,499 |
$ |
1,469 |
$ |
3,833 |
$ |
1,088 |
$ |
109 |
|
$ |
3,447 |
|
per share basic |
|
2.44 |
|
0.78 |
|
0.05 |
|
0.28 |
|
1.32 |
|
|
8.66 |
|
1.96 |
|
5.11 |
|
1.45 |
|
0.15 |
|
|
4.55 |
|
per share diluted |
|
2.44 |
|
0.78 |
|
0.05 |
|
0.28 |
|
1.32 |
|
|
8.64 |
|
1.96 |
|
5.10 |
|
1.45 |
|
0.14 |
|
|
4.51 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings |
|
1,862 |
|
636 |
|
25 |
|
239 |
|
962 |
|
|
5,944 |
|
1,077 |
|
3,553 |
|
1,221 |
|
93 |
|
|
3,959 |
|
per share basic |
|
2.48 |
|
0.85 |
|
0.03 |
|
0.32 |
|
1.28 |
|
|
7.92 |
|
1.44 |
|
4.74 |
|
1.63 |
|
0.12 |
|
|
5.23 |
|
per share diluted |
|
2.48 |
|
0.85 |
|
0.03 |
|
0.32 |
|
1.28 |
|
|
7.91 |
|
1.43 |
|
4.73 |
|
1.63 |
|
0.12 |
|
|
5.18 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets |
|
33,827 |
|
|
|
|
|
|
|
|
|
|
47,247 |
|
|
|
|
|
|
|
|
|
|
46,974 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Long-Term Debt |
|
7,768 |
|
|
|
|
|
|
|
|
|
|
9,005 |
|
|
|
|
|
|
|
|
|
|
9,543 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties |
|
11,114 |
|
2,712 |
|
2,271 |
|
2,449 |
|
3,682 |
|
|
21,053 |
|
4,862 |
|
8,150 |
|
4,653 |
|
3,388 |
|
|
14,385 |
|
Net Earnings from Continuing Operations includes results for Canada Other upstream assets transferred to Cenovus under the November 30, 2009 Split Transaction. Total Consolidated Net Earnings includes results for Downstream Refining assets transferred to Cenovus under the Split Transaction, which are classified as Discontinued Operations.
2009 versus 2008
Net Earnings of $1,862 million decreased $4,082 million. Significant items affecting Net Earnings were:
· Lower average total natural gas and total liquids prices, excluding financial hedges, as well as lower natural gas production volumes as discussed in the Cash Flow section of this MD&A; and
· The net impact of realized and unrealized hedging, after-tax, which resulted in a $1,143 million increase to Net Earnings in 2009 compared to a $1,599 million increase to Net Earnings in 2008;
partially offset by:
· Excluding the tax impacts associated with hedging and non-operating foreign exchange, future income tax expense decreased primarily due to the wind-up of the Canadian oil and gas partnership and other items associated with the Split Transaction;
· Lower costs of operations as discussed in the Cash Flow section of this MD&A;
· Net Earnings from Discontinued Operations of $32 million in 2009 compared to Net Loss of $555 million in 2008; and
· Non-operating foreign exchange gains of $159 million after-tax in 2009 compared to losses of $378 million after-tax in 2008.
2008 versus 2007
Net Earnings of $5,944 million increased $1,985 million. Significant items affecting Net Earnings were:
· Higher average total natural gas and total liquids prices, excluding financial hedges, as well as higher natural gas production volumes as discussed in the Cash Flow section of this MD&A; and
· The net impact of realized and unrealized hedging, after-tax, which resulted in a $1,599 million increase to Net Earnings in 2008 compared to a $212 million increase to Net Earnings in 2007;
EnCana Corporation 2009 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
partially offset by:
· Net Loss from Discontinued Operations of $555 million in 2008 compared to Net Earnings of $512 million in 2007;
· Higher costs of operations as discussed in the Cash Flow section of this MD&A;
· Non-operating foreign exchange losses of $378 million after-tax in 2008 compared to gains of $217 million after-tax in 2007;
· Higher DD&A of $378 million primarily due to the increase in production volumes; and
· Higher future income tax, excluding tax associated with realized hedging and non-operating foreign exchange, as a result of accelerated write-offs for certain U.S. capital expenditures and the effect of the reduction in Canadian federal corporate tax rates reflected in 2007.
Q4 2009 versus Q4 2008
Net Earnings of $636 million decreased $441 million. Significant items affecting Net Earnings were:
· The net impact of realized and unrealized hedging, after-tax, which resulted in a $223 million increase to Net Earnings in 2009 compared to a $1,186 million increase to Net Earnings in 2008; and
· Lower natural gas production volumes and lower average total natural gas prices, excluding financial hedges, as discussed in the Cash Flow section of this MD&A;
partially offset by:
· Excluding the tax impacts associated with hedging and non-operating foreign exchange, future income tax expense decreased primarily due to the wind-up of the Canadian oil and gas partnership and other items associated with the Split Transaction;
· Higher average total liquids prices, excluding financial hedges, as discussed in the Cash Flow section of this MD&A; and
· Non-operating foreign exchange losses of $19 million after-tax in 2009 compared to losses of $119 million after-tax in 2008.
Summary of Hedging Impacts on Net Earnings
($ millions) |
|
2009 |
|
2008 |
|
2007 |
|
|
Q4 2009 |
|
Q4 2008 |
|
|||||
Unrealized Mark-to-Market Gains (Losses), after-tax(1) |
$ |
(1,792 |
) |
$ |
1,818 |
|
$ |
(811 |
) |
|
$ |
(200 |
) |
$ |
747 |
|
|
Realized Hedging Gains (Losses), after-tax (2) |
|
2,935 |
|
|
(219 |
) |
|
1,023 |
|
|
|
423 |
|
|
439 |
|
|
Hedging Impacts on Net Earnings |
$ |
1,143 |
|
$ |
1,599 |
|
$ |
212 |
|
|
$ |
223 |
|
$ |
1,186 |
|
|
(1) Included in Corporate and Other financial results. Further detail on unrealized mark-to-market gains (losses) can be found in the Corporate and Other section of this MD&A.
(2) Included in Divisional financial results.
Net Capital Investment
|
Pro Forma |
|
Consolidated |
|||||||||||||
($ millions) |
|
2009 |
|
2008 |
|
|
2009 |
|
2008 |
|
2007 |
|||||
Canadian Division |
$ |
1,869 |
|
$ |
2,459 |
|
|
$ |
1,869 |
|
$ |
2,459 |
|
$ |
2,403 |
|
USA Division |
|
1,821 |
|
|
2,682 |
|
|
|
1,821 |
|
|
2,682 |
|
|
1,935 |
|
Market Optimization |
|
- |
|
|
1 |
|
|
|
2 |
|
|
17 |
|
|
6 |
|
Corporate & Other |
|
65 |
|
|
113 |
|
|
|
85 |
|
|
165 |
|
|
154 |
|
Canada Other (1) |
|
- |
|
|
- |
|
|
|
848 |
|
|
1,500 |
|
|
1,238 |
|
Discontinued Operations (2) |
|
- |
|
|
- |
|
|
|
829 |
|
|
478 |
|
|
220 |
|
Capital Investment |
|
3,755 |
|
|
5,255 |
|
|
|
5,454 |
|
|
7,301 |
|
|
5,956 |
|
Acquisitions |
|
260 |
|
|
1,174 |
|
|
|
260 |
|
|
1,174 |
|
|
2,688 |
|
Divestitures |
|
(1,075 |
) |
|
(857 |
) |
|
|
(1,161 |
) |
|
(857 |
) |
|
(481 |
) |
Canada Other (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Acquisitions and Divestitures |
|
- |
|
|
- |
|
|
|
(14 |
) |
|
(47 |
) |
|
14 |
|
Net Capital Investment |
$ |
2,940 |
|
$ |
5,572 |
|
|
$ |
4,539 |
|
$ |
7,571 |
|
$ |
8,177 |
|
(1) Canada Other represents operations formerly included in Canadian Plains and Integrated Oil Canada upstream assets that were transferred to Cenovus as a result of the November 30, 2009 Split Transaction.
(2) The former Integrated Oil Division U.S. Downstream Refining operations are included in Discontinued Operations.
EnCana Corporation 2009 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
EnCanas capital investment for 2009, 2008 and 2007 was funded by Cash Flow.
Pro forma capital investment during 2009 was primarily focused on continued development of EnCanas North American key resource plays. Pro forma capital investment of $3,755 million was lower due to reduced upstream activity levels as well as the change in the average U.S./Canadian dollar exchange rate, which decreased capital investment by $131 million in 2009 compared to 2008. Further information regarding the Companys capital investment can be found in the Divisional Results section of this MD&A.
Acquisitions and Divestitures
In 2009, the Company completed the divestiture of mature conventional oil and natural gas assets for proceeds of $1,000 million (2008 $400 million) in the Canadian Division, $73 million (2008 $251 million) in the USA Division and $17 million in Canada Other (2008 $47 million).
On November 3, 2009, the Company completed the sale of Senlac Oil Ltd. for cash consideration of $83 million. The operations are included in Canada Other. In September 2008, the Company completed the sale of its interests in Brazil for net proceeds of $164 million, before closing adjustments, 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.
Acquisitions in 2008 included land purchases of approximately $1,010 million in the Haynesville shale play in Louisiana. Acquisitions in 2007 included the purchase of Deep Bossier natural gas assets and land interests in East Texas for approximately $2.55 billion.
The Company also had some other minor property acquisitions and divestitures in 2009, 2008 and 2007.
Free Cash Flow
|
Pro Forma |
|
Consolidated |
|||||||||||||
($ millions) |
|
2009 |
|
2008 |
|
|
2009 |
|
2008 |
|
2007 |
|||||
Cash Flow (1) |
$ |
5,021 |
|
$ |
6,354 |
|
|
$ |
6,779 |
|
$ |
9,386 |
|
$ |
8,453 |
|
Capital Investment |
|
3,755 |
|
|
5,255 |
|
|
|
5,454 |
|
|
7,301 |
|
|
5,956 |
|
Free Cash Flow (2) |
$ |
1,266 |
|
$ |
1,099 |
|
|
$ |
1,325 |
|
$ |
2,085 |
|
$ |
2,497 |
|
(1) Cash Flow is a non-GAAP measure and is defined under the Reconciliations of Non-GAAP Measures section of this MD&A.
(2) 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 by Management to determine the funds available for other investing activities, dividends and/or other financing activities.
EnCanas 2009 Pro Forma Free Cash Flow of $1,266 million was higher compared to 2008. Reasons for the variances in Pro Forma Cash Flow and Pro Forma Capital Investment are discussed under the Pro Forma Cash Flow and Net Capital Investment sections of this MD&A.
Reserves and Production
Proved Oil and Gas Reserves
Since inception, EnCana has retained independent qualified reserves evaluators (IQREs) to evaluate and prepare reports on 100 percent of the Companys natural gas and liquids reserves annually. The Company has a Reserves Committee of independent Board of Directors members, which reviews the qualifications and appointment of the IQREs. The Committee also reviews the procedures for providing information to the evaluators. All booked reserves are based upon annual evaluations by the IQREs. EnCanas disclosure of reserves data is covered by National Instrument 51-101 of the Canadian Securities Administrators as amended by a Decision dated September 29, 2008 permitting the adoption of U.S. reporting standards, including compliance with the practices and procedures of the U.S. Securities and Exchange Commission (SEC) and U.S. Financial Accounting Standards Board reserves reporting requirements.
As of December 31, 2009, the SEC requires that estimates of oil and gas reserves be determined using an average price based upon the prior 12-month period rather than single day year-end prices.
EnCana Corporation 2009 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Proved Reserves by Country
|
Natural Gas |
|
Liquids(1) |
||||
(Constant Prices After Royalties, |
(billions of cubic feet) |
|
(millions of barrels) |
||||
As at December 31) |
2009 |
2008 |
2007 |
|
2009 |
2008 |
2007 |
Canada(2) |
5,349 |
7,847 |
7,292 |
|
35.5 |
954.0 |
868.9 |
United States |
5,713 |
5,831 |
6,008 |
|
41.2 |
51.6 |
58.3 |
Total |
11,062 |
13,678 |
13,300 |
|
76.7 |
1,005.6 |
927.2 |
(1) Liquids include crude oil, NGLs and condensate.
(2) EnCanas reserves in Canada prior to November 30, 2009 include Canada Other reserves (former Canadian Plains and Integrated Oil Canada reserves) that were transferred to Cenovus as part of the Split Transaction.
Proved Reserves Reconciliation by Country
|
|
Natural Gas |
|
|
Liquids(1) |
|
|
Total(2) |
|
|
||||||||||||
(Constant Prices After Royalties, |
|
(billions of cubic feet) |
|
|
(millions of barrels) |
|
|
(billions of cubic |
|
|
||||||||||||
Year ended December 31, 2009) |
|
Canada(2) |
|
United States |
|
Total |
|
Canada(3) |
|
United States |
|
Total |
|
feet equivalent) |
|
|
||||||
Beginning of year |
|
7,847 |
|
|
5,831 |
|
|
13,678 |
|
|
954.0 |
|
|
51.6 |
|
|
1,005.6 |
|
|
19,712 |
|
|
Revisions and improved recovery |
|
(755 |
) |
|
(845 |
) |
|
(1,600 |
) |
|
(80.3 |
) |
|
(12.6 |
) |
|
(92.9 |
) |
|
(2,157 |
) |
|
Extensions and discoveries |
|
726 |
|
|
1,406 |
|
|
2,132 |
|
|
171.9 |
|
|
6.5 |
|
|
178.4 |
|
|
3,202 |
|
|
Acquisitions |
|
28 |
|
|
- |
|
|
28 |
|
|
0.5 |
|
|
- |
|
|
0.5 |
|
|
31 |
|
|
Sale of reserves in place(4) |
|
(1,772 |
) |
|
(89 |
) |
|
(1,861 |
) |
|
(968.3 |
) |
|
(0.2 |
) |
|
(968.5 |
) |
|
(7,672 |
) |
|
Production |
|
(725 |
) |
|
(590 |
) |
|
(1,315 |
) |
|
(42.3 |
) |
|
(4.1 |
) |
|
(46.4 |
) |
|
(1,593 |
) |
|
End of year |
|
5,349 |
|
|
5,713 |
|
|
11,062 |
|
|
35.5 |
|
|
41.2 |
|
|
76.7 |
|
|
11,523 |
|
|
(1) Liquids include crude oil, NGLs and condensate.
(2) Liquids converted to thousand cubic feet equivalent at 1 barrel = 6 thousand cubic feet.
(3) EnCanas reserves in Canada prior to November 30, 2009 include Canada Other reserves (former Canadian Plains and Integrated Oil Canada reserves) that were transferred to Cenovus as part of the Split Transaction.
(4) Sale of reserves in place include the transfer of EnCanas Canadian Plains Division and Integrated Oil Division upstream assets to Cenovus as a result of the November 30, 2009 Split Transaction.
EnCanas 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 negative revisions were 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. Extensions and discoveries were 2,132 Bcf, of which approximately two-thirds were in the U.S. with the remaining balance in Canada.
In 2009, EnCanas crude oil and NGLs reserves decreased by approximately 77 percent and EnCanas bitumen reserves were divested, substantially all as a result of the Split Transaction.
Canadian Division and USA Division Proved Reserves
|
Natural Gas |
|
Liquids(1) |
||||
|
(billions of cubic feet) |
|
(millions of barrels) |
||||
(As at December 31, 2009) |
2009 |
2008 |
2007 |
|
2009 |
2008 |
2007 |
Canadian Division(2) |
5,349 |
5,992 |
5,273 |
|
35.5 |
45.0 |
41.8 |
USA Division |
5,713 |
5,831 |
6,008 |
|
41.2 |
51.6 |
58.3 |
Total |
11,062 |
11,823 |
11,281 |
|
76.7 |
96.6 |
100.1 |
(1) Liquids include crude oil, NGLs and condensate.
(2) 2008 and 2007 reserves exclude Canada Other.
EnCana Corporation 2009 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Canadian Division and USA Division Proved Reserves Reconciliation
|
|
Natural Gas |
|
|
Liquids(1) |
|
|
|
|
|
||||||||||||
|
|
(billions of cubic feet) |
|
|
(millions of barrels) |
|
|
Total(2) |
|
|
||||||||||||
(Year ended December 31, 2009) |
|
Canadian |
|
USA |
|
Total |
|
Canadian |
|
USA |
|
Total |
|
(billions of cubic |
|
|
||||||
Beginning of year |
|
5,992 |
|
|
5,831 |
|
|
11,823 |
|
|
45.0 |
|
|
51.6 |
|
|
96.6 |
|
|
12,402 |
|
|
Technical revisions |
|
(305 |
) |
|
(98 |
) |
|
(403 |
) |
|
0.2 |
|
|
(8.9 |
) |
|
(8.7 |
) |
|
(455 |
) |
|
Extensions and discoveries |
|
676 |
|
|
1,557 |
|
|
2,233 |
|
|
6.5 |
|
|
6.7 |
|
|
13.2 |
|
|
2,312 |
|
|
Acquisitions |
|
31 |
|
|
- |
|
|
31 |
|
|
0.5 |
|
|
- |
|
|
0.5 |
|
|
34 |
|
|
Sale of reserves in place |
|
(272 |
) |
|
(95 |
) |
|
(367 |
) |
|
(9.2 |
) |
|
(0.2 |
) |
|
(9.4 |
) |
|
(423 |
) |
|
Production |
|
(447 |
) |
|
(590 |
) |
|
(1,037 |
) |
|
(5.8 |
) |
|
(4.1 |
) |
|
(9.9 |
) |
|
(1,096 |
) |
|
End of year |
|
5,675 |
|
|
6,605 |
|
|
12,280 |
|
|
37.2 |
|
|
45.1 |
|
|
82.3 |
|
|
12,774 |
|
|
Price revisions (SEC)(4) |
|
(326 |
) |
|
(892 |
) |
|
(1,218 |
) |
|
(1.7 |
) |
|
(3.9 |
) |
|
(5.6 |
) |
|
(1,251 |
) |
|
End of year (SEC) |
|
5,349 |
|
|
5,713 |
|
|
11,062 |
|
|
35.5 |
|
|
41.2 |
|
|
76.7 |
|
|
11,523 |
|
|
(1) Liquids include crude oil, NGLs and condensate.
(2) Liquids converted to thousand cubic feet equivalent at 1 barrel = 6 thousand cubic feet.
(3) Excludes Canada Other.
(4) The impact of significantly lower prices for U.S.SEC reporting purposes (NYMEXHenry Hub price of $3.87 per MMbtu in 2009 versus $5.71 per MMbtu in 2008) is reflected in the SEC price revisions.
Excluding price revisions for SEC reporting purposes, approximately 169 percent of production associated with EnCanas pro forma operations was replaced by reserves additions before acquisitions and divestitures during 2009. On this basis, natural gas equivalent reserves associated with EnCanas pro forma operations increased approximately 3 percent.
Production Volumes
|
|
|
2009 |
|
Q4 |
|
Q3 |
|
Q2 |
|
Q1 |
|
2008 |
|
Q4 |
|
Q3 |
|
Q2 |
|
Q1 |
|
2007 |
|
Produced Gas (MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Division |
|
|
1,224 |
|
1,071 |
|
1,201 |
|
1,343 |
|
1,281 |
|
1,300 |
|
1,302 |
|
1,351 |
|
1,289 |
|
1,256 |
|
1,255 |
|
USA Division |
|
|
1,616 |
|
1,616 |
|
1,524 |
|
1,581 |
|
1,746 |
|
1,633 |
|
1,677 |
|
1,674 |
|
1,629 |
|
1,552 |
|
1,345 |
|
|
|
|
2,840 |
|
2,687 |
|
2,725 |
|
2,924 |
|
3,027 |
|
2,933 |
|
2,979 |
|
3,025 |
|
2,918 |
|
2,808 |
|
2,600 |
|
Liquids (bbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Division |
|
|
15,880 |
|
12,477 |
|
15,909 |
|
17,624 |
|
17,567 |
|
19,980 |
|
19,702 |
|
19,947 |
|
20,155 |
|
20,123 |
|
18,272 |
|
USA Division |
|
|
11,317 |
|
11,586 |
|
10,325 |
|
11,699 |
|
11,671 |
|
13,350 |
|
12,831 |
|
13,853 |
|
13,482 |
|
13,232 |
|
14,180 |
|
|
|
|
27,197 |
|
24,063 |
|
26,234 |
|
29,323 |
|
29,238 |
|
33,330 |
|
32,533 |
|
33,800 |
|
33,637 |
|
33,355 |
|
32,452 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma Volumes (MMcfe/d) (1) |
|
|
3,003 |
|
2,831 |
|
2,883 |
|
3,100 |
|
3,203 |
|
3,132 |
|
3,174 |
|
3,227 |
|
3,120 |
|
3,008 |
|
2,795 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada Other (MMcfe/d)(1)(2) |
|
|
1,362 |
|
970 |
|
1,504 |
|
1,502 |
|
1,472 |
|
1,507 |
|
1,499 |
|
1,491 |
|
1,487 |
|
1,549 |
|
1,576 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Volumes (MMcfe/d) (1) |
|
|
4,365 |
|
3,801 |
|
4,387 |
|
4,602 |
|
4,675 |
|
4,639 |
|
4,673 |
|
4,718 |
|
4,607 |
|
4,557 |
|
4,371 |
|
(1) Liquids converted to thousand cubic feet equivalent at 1 barrel = 6 thousand cubic feet.
(2) Canada - Other represents operations formerly included in Canadian Plains and Integrated Oil - Canada that were transferred to Cenovus as a result of the November 30, 2009 Split Transaction.
Total production volumes decreased 6 percent or 274 MMcfe/d in 2009 compared to 2008 and decreased 4 percent or 129 MMcfe/d on a pro forma basis. Lower pro forma volumes were primarily due to shut-in and curtailed production as well as delayed well completions and tie-ins due to the low price environment, and natural declines in conventional properties. Total production volumes for Canada Other includes all results prior to November 30, 2009 of the oil and gas assets transferred to Cenovus under the Split Transaction. Accordingly, total production volumes for 2009 include 12 months of EnCana operations and 11 months of Cenovus operations.
Total production volumes increased 6 percent or 268 MMcfe/d in 2008 compared to 2007 primarily due to increased production from EnCanas pro forma natural gas key resource plays of 21 percent, partially offset by natural declines in conventional properties and the volume impact of minor property divestitures.
EnCana Corporation 2009 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Divisional Results
As discussed in EnCanas Business section of this MD&A, the Company completed the Split Transaction on November 30, 2009. EnCanas divisions, after the Split Transaction, include the Canadian Division (formerly Canadian Foothills) and the USA Division.
Canadian Division
Financial Results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2007 |
|
|||||||||||||||||||||||||||||||||||
($ millions) |
|
Gas |
|
Liquids |
|
Other |
|
Total |
|
|
Gas |
|
Liquids |
|
Other |
|
Total |
|
|
Gas |
|
Liquids |
|
Other |
|
Total |
|
||||||||||||||
Revenues, Net of Royalties and Hedging |
|
$ |
1,641 |
|
$ |
277 |
|
$ |
44 |
|
$ |
1,962 |
|
|
|
$ |
3,862 |
|
$ |
622 |
|
$ |
57 |
|
$ |
4,541 |
|
|
|
$ |
2,885 |
|
$ |
413 |
|
$ |
57 |
|
$ |
3,355 |
|
Realized Financial Hedging Gain (Loss) |
|
1,400 |
|
- |
|
- |
|
1,400 |
|
|
|
(142) |
|
(44) |
|
- |
|
(186 |
) |
|
|
347 |
|
(23) |
|
- |
|
324 |
|
||||||||||||
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Production and mineral taxes |
|
11 |
|
3 |
|
- |
|
14 |
|
|
|
28 |
|
5 |
|
- |
|
33 |
|
|
|
36 |
|
3 |
|
- |
|
39 |
|
||||||||||||
Transportation and selling |
|
148 |
|
6 |
|
- |
|
154 |
|
|
|
201 |
|
12 |
|
26 |
|
239 |
|
|
|
192 |
|
9 |
|
- |
|
201 |
|
||||||||||||
Operating |
|
501 |
|
21 |
|
14 |
|
536 |
|
|
|
549 |
|
39 |
|
21 |
|
609 |
|
|
|
482 |
|
33 |
|
20 |
|
535 |
|
||||||||||||
Operating Cash Flow |
|
$ |
2,381 |
|
$ |
247 |
|
$ |
30 |
|
$ |
2,658 |
|
|
|
$ |
2,942 |
|
$ |
522 |
|
$ |
10 |
|
$ |
3,474 |
|
|
|
$ |
2,522 |
|
$ |
345 |
|
$ |
37 |
|
$ |
2,904 |
|
Operating Netback Information
|
|
2009 |
|
2008 |
|
2007 |
|
||||||||||||||
|
|
|
Gas |
|
Total |
|
|
Gas |
|
Total |
|
Gas |
|
Total |
|
||||||
|
|
|
($/Mcf |
) |
($/Mcfe |
) |
|
($/Mcf |
) |
($/Mcfe |
) |
($/Mcf |
) |
($/Mcfe |
) |
||||||
Price |
|
|
$ |
3.71 |
|
$ |
4.02 |
|
|
$ |
8.12 |
|
$ |
8.63 |
|
$ |
6.30 |
|
$ |
6.62 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Production and mineral taxes |
|
|
0.03 |
|
0.03 |
|
|
0.06 |
|
0.06 |
|
0.08 |
|
0.08 |
|
||||||
Transportation and selling |
|
|
0.33 |
|
0.32 |
|
|
0.42 |
|
0.41 |
|
0.42 |
|
0.40 |
|
||||||
Operating |
|
|
1.13 |
|
1.09 |
|
|
1.15 |
|
1.13 |
|
1.05 |
|
1.03 |
|
||||||
Netback excluding Realized Financial Hedging |
|
|
2.22 |
|
2.58 |
|
|
6.49 |
|
7.03 |
|
4.75 |
|
5.11 |
|
||||||
Realized Financial Hedging Gain (Loss) |
|
|
3.16 |
|
2.93 |
|
|
(0.30 |
) |
(0.36 |
) |
0.76 |
|
0.65 |
|
||||||
Netback including Realized Financial Hedging |
|
|
$ |
5.38 |
|
$ |
5.51 |
|
|
$ |
6.19 |
|
$ |
6.67 |
|
$ |
5.51 |
|
$ |
5.76 |
|
Production Volumes
|
· |
Natural gas production volumes decreased 6 percent to 1,224 MMcf/d in 2009 compared to 2008. |
|
|
|
· |
Liquids production volumes decreased 21 percent to 15,880 barrels (bbls) per day (bbls/d) in 2009 compared to 2008. |
|
|
|
|
· |
Volumes in 2009 were lower than 2008 primarily as a result of shut-in and curtailed production as well as delayed well completions and tie-ins due to the low price environment (approximately 120 MMcf/d), natural declines at conventional properties and the volume impact of property divestitures in 2008 and 2009, partially offset by the impact of lower royalties. |
Key Resource Plays
|
|
Daily Production |
|
Drilling Activity |
|
||||||||
|
|
2009 |
|
2008 |
|
2007 |
|
2009 |
|
2008 |
|
2007 |
|
Natural Gas (MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Greater Sierra |
|
199 |
|
220 |
|
211 |
|
57 |
|
106 |
|
109 |
|
Cutbank Ridge |
|
310 |
|
296 |
|
258 |
|
71 |
|
82 |
|
93 |
|
Bighorn |
|
159 |
|
167 |
|
126 |
|
69 |
|
64 |
|
62 |
|
CBM |
|
316 |
|
304 |
|
259 |
|
490 |
|
698 |
|
1,079 |
|
Total (MMcf/d) |
|
984 |
|
987 |
|
854 |
|
687 |
|
950 |
|
1,343 |
|
EnCana Corporation 2009 Annual Report |
|
Managements Discussion and Analysis (prepared in US$) |
2009 versus 2008
Operating Cash Flow of $2,658 million decreased $816 million due to:
· A $2,169 million impact resulting from the decrease in commodity prices, excluding the impact of financial hedging, which reflects the changes in benchmark prices and changes in the basis differentials; and
· A $397 million impact resulting from the decrease in natural gas and liquids production volumes;
partially offset by:
· Realized financial hedging gains of $1,400 million in 2009 compared to losses of $186 million in 2008;
· Transportation and selling costs decreased $85 million primarily as a result of reduced volumes transported to the U.S and the lower U.S./Canadian dollar exchange rate; and
· Operating expenses were $73 million lower primarily as a result of the lower U.S./Canadian dollar exchange rate, reduced repairs and maintenance, workover and chemical costs due to lower activity levels, partially offset by higher long-term compensation costs due to the change in the EnCana share price.
2008 versus 2007
Operating Cash Flow of $3,474 million increased $570 million due to:
· A $1,035 million impact resulting from the increase in commodity prices, excluding the impact of financial hedging, which reflects the changes in benchmark prices and changes in the basis differentials; and
· A $151 million impact resulting from the increase in natural gas and liquids production volumes. Volumes were higher primarily due to drilling success as well as increased tie-in and completion activity in the key resource plays of CBM, Bighorn and Cutbank Ridge, partially offset by natural declines for conventional properties;
partially offset by:
· Realized financial hedging losses of $186 million in 2008 compared to gains of $324 million in 2007; and
· Operating expenses were $74 million higher primarily as a result of higher repairs and maintenance due to scheduled plant turnarounds, increased gathering and processing, salaries and benefits, workovers, property tax and lease costs, offset by lower long-term compensation costs due to the change in the EnCana share price.
Capital Investment
2009 versus 2008
Capital investment of $1,869 million during 2009 was primarily focused on the CBM, Cutbank Ridge, Greater Sierra and Bighorn key resource plays and Deep Panuke. The $590 million decrease compared to 2008 was primarily due to lower drilling and completion costs as well as the lower U.S./Canadian dollar exchange rate, partially offset by higher activity in Deep Panuke. The number of net wells drilled in the Canadian Division in 2009 decreased to 699 from 1,064 in 2008.
2008 versus 2007
Capital investment of $2,459 million in 2008 was relatively unchanged compared to 2007. Lower activity levels were offset by increased capital inventory purchases. The number of net wells drilled in the Canadian Division in 2008 decreased to 1,064 from 1,539 in 2007.
USA Division |
Financial Results
|
|
2009 |
|
2008 |
|
2007 |
|
||||||||||||||||||||||||||||||
($ millions) |
|
Gas |
|
Liquids |
|
Other |
|
Total |
|
Gas |
|
Liquids |
|
Other |
|
Total |
|
Gas |
|
Liquids |
|
Other |
|
Total |
|
||||||||||||
Revenues, Net of Royalties and Hedging |
|
$ |
2,210 |
|
$ |
201 |
|
$ |
114 |
|
$ |
2,525 |
|
$ |
4,718 |
|
$ |
407 |
|
$ |
288 |
|
$ |
5,413 |
|
$ |
2,641 |
|
$ |
309 |
|
$ |
298 |
|
$ |
3,248 |
|
Realized Financial Hedging Gain (Loss) |
|
2,012 |
|
- |
|
- |
|
2,012 |
|
216 |
|
- |
|
- |
|
216 |
|
1,124 |
|
- |
|
- |
|
1,124 |
|
||||||||||||
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Production and mineral taxes |
|
100 |
|
18 |
|
- |
|
118 |
|
334 |
|
36 |
|
- |
|
370 |
|
167 |
|
22 |
|
- |
|
189 |
|
||||||||||||
Transportation and selling |
|
530 |
|
- |
|
- |
|
530 |
|
502 |
|
- |
|
- |
|
502 |
|
307 |
|
- |
|
- |
|
307 |
|
||||||||||||
Operating |
|
327 |
|
- |
|
107 |
|
434 |
|
352 |
|
- |
|
266 |
|
618 |
|
323 |
|
- |
|
272 |
|
595 |
|
||||||||||||
Operating Cash Flow |
|
$ |
3,265 |
|
$ |
183 |
|
$ |
7 |
|
$ |
3,455 |
|
$ |
3,746 |
|
$ |
371 |
|
$ |
22 |
|
$ |
4,139 |
|
$ |
2,968 |
|
$ |
287 |
|
$ |
26 |
|
$ |
3,281 |
|
EnCana Corporation 2009 Annual Report |
|
Managements Discussion and Analysis (prepared in US$) |
Operating Netback Information
|
|
|
2009 |
|
|
2008 |
|
2007 |
|
||||||||||||
|
|
|
Gas |
|
Total |
|
|
Gas |
|
Total |
|
Gas |
|
Total |
|
||||||
|
|
|
($/Mcf |
) |
($/Mcfe |
) |
|
($/Mcf |
) |
($/Mcfe |
) |
($/Mcf |
) |
($/Mcfe |
) |
||||||
Price |
|
|
$ |
3.75 |
|
$ |
3.92 |
|
|
$ |
7.89 |
|
$ |
8.17 |
|
$ |
5.38 |
|
$ |
5.65 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Production and mineral taxes |
|
|
0.17 |
|
0.19 |
|
|
0.56 |
|
0.59 |
|
0.34 |
|
0.36 |
|
||||||
Transportation and selling |
|
|
0.90 |
|
0.86 |
|
|
0.84 |
|
0.80 |
|
0.62 |
|
0.59 |
|
||||||
Operating |
|
|
0.55 |
|
0.53 |
|
|
0.59 |
|
0.56 |
|
0.65 |
|
0.62 |
|
||||||
Netback excluding Realized Financial Hedging |
|
|
2.13 |
|
2.34 |
|
|
5.90 |
|
6.22 |
|
3.77 |
|
4.08 |
|
||||||
Realized Financial Hedging Gain (Loss) |
|
|
3.41 |
|
3.27 |
|
|
0.36 |
|
0.34 |
|
2.29 |
|
2.15 |
|
||||||
Netback including Realized Financial Hedging |
|
|
$ |
5.54 |
|
$ |
5.61 |
|
|
$ |
6.26 |
|
$ |
6.56 |
|
$ |
6.06 |
|
$ |
6.23 |
|
Production Volumes
|
· |
Natural gas production volumes decreased 1 percent to 1,616 MMcf/d in 2009 compared to 2008. Drilling and operational success in the Haynesville shale play and East Texas were offset by shut-in and curtailed production as well as delayed well completions and tie-ins due to the low price environment (approximately 200 MMcf/d). |
|
|
|
· |
Liquids production volumes decreased 15 percent to 11,317 bbls/d in 2009 compared to 2008. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Key Resource Plays
|
|
Daily Production |
|
|
Drilling Activity |
|
||||||||||
|
|
2009 |
|
|
2008 |
|
2007 |
|
|
2009 |
|
|
2008 |
|
2007 |
|
Natural Gas (MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jonah |
|
571 |
|
|
603 |
|
557 |
|
|
108 |
|
|
175 |
|
135 |
|
Piceance |
|
362 |
|
|
385 |
|
348 |
|
|
129 |
|
|
328 |
|
286 |
|
East Texas |
|
324 |
|
|
334 |
|
143 |
|
|
38 |
|
|
78 |
|
35 |
|
Fort Worth |
|
136 |
|
|
142 |
|
124 |
|
|
26 |
|
|
83 |
|
75 |
|
Total (MMcf/d) |
|
1,393 |
|
|
1,464 |
|
1,172 |
|
|
301 |
|
|
664 |
|
531 |
|
Natural gas production volumes in the Haynesville shale play, which has not yet been designated a key resource play, averaged 70 MMcf/d in 2009 compared to 9 MMcf/d in 2008, and exited 2009 at approximately 125 MMcf/d.
2009 versus 2008
Operating Cash Flow of $3,455 million decreased $684 million due to:
· A $2,589 million impact resulting from the decrease in commodity prices, excluding the impact of financial hedging, which reflects the changes in benchmark prices and changes in the basis differentials; and
· A $125 million impact resulting from the decrease in natural gas and liquids production volumes;
partially offset by:
· Realized financial hedging gains of $2,012 million in 2009 compared to gains of $216 million in 2008;
· Production and mineral taxes decreased $252 million primarily as a result of lower commodity prices and high cost well tax credits; and
· Operating expenses were $184 million lower as a result of shut-in production and less activity resulting in lower repairs and maintenance, labour, water disposal and workover costs, partially offset by higher long-term compensation costs due to the change in the EnCana share price.
EnCana Corporation 2009 Annual Report |
|
Managements Discussion and Analysis (prepared in US$) |
2008 versus 2007
Operating Cash Flow of $4,139 million increased $858 million due to:
· A $1,618 million impact resulting from the increase in commodity prices, excluding the impact of financial hedging, which reflects the changes in benchmark prices and changes in the basis differentials; and
· A $557 million impact resulting primarily from the increase in natural gas production volumes. Volumes were higher primarily due to drilling and operational success at East Texas, Jonah, Piceance and Fort Worth as well as incremental volumes from the Deep Bossier acquisition and upgrades to the compression and gathering facilities at Jonah. These increases were slightly offset by the impact of shut-in production (approximately 100 MMcf/d) at Piceance and Jonah during the fourth quarter of 2008 due to the low price environment;
partially offset by:
· Realized financial hedging gains of $216 million in 2008 compared to gains of $1,124 million in 2007;
· Production and mineral taxes increased $181 million primarily as a result of higher natural gas prices; and
· Transportation and selling costs increased $195 million primarily as a result of higher unutilized transportation commitments as well as transporting gas greater distances on the Rockies Express Pipeline to improve price realizations.
Capital Investment
2009 versus 2008
Capital investment of $1,821 million during 2009 was primarily focused on the East Texas and Jonah key resource plays, as well as on the emerging Haynesville shale play. The $861 million decrease compared to 2008 was primarily due to lower activity in the Piceance, East Texas, Jonah and Fort Worth key resource plays, partially offset by increased drilling and facility spending in the Haynesville shale play. The number of net wells drilled in the USA Division in 2009 decreased to approximately 390 from 750 in 2008. During 2009, EnCana also established an entry level land position in the Marcellus shale play in Pennsylvania.
2008 versus 2007
Capital investment of $2,682 million in 2008 increased $747 million primarily due to increased drilling and completion activity in the East Texas, Piceance and Jonah key resource plays, including incremental costs from the Deep Bossier acquisition offset slightly by lower capitalized long-term compensation costs. The number of net wells drilled in the USA Division in 2008 increased to 750 from 644 in 2007.
Other Operations
As a result of the November 30, 2009 Split Transaction, upstream assets formerly included in Canadian Plains and Integrated Oil Canada are presented in continuing operations as Canada Other under full cost accounting. Accordingly, 2009 includes 11 months of reported results compared to 12 months in 2008.
CANADA OTHER
Financial Results
|
|
2009 |
|
|
2008 |
|
2007 |
|
||||||||||||||||||||||||||||||
($ millions) |
|
Gas |
|
Liquids |
|
Other |
|
Total |
|
|
Gas |
|
Liquids |
|
Other |
|
Total |
|
Gas |
|
Liquids |
|
Other |
|
Total |
|
||||||||||||
Revenues, Net of Royalties and Hedging |
|
$ |
922 |
|
$ |
2,249 |
|
$ |
68 |
|
$ |
3,239 |
|
|
$ |
2,392 |
|
$ |
3,440 |
|
$ |
185 |
|
$ |
6,017 |
|
$ |
1,946 |
|
$ |
2,321 |
|
$ |
226 |
|
$ |
4,493 |
|
Realized Financial Hedging Gain (Loss) |
|
859 |
|
38 |
|
87 |
|
984 |
|
|
(91) |
|
(217) |
|
(14) |
|
(322) |
|
240 |
|
(130) |
|
26 |
|
136 |
|
||||||||||||
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Production and mineral taxes |
|
15 |
|
23 |
|
1 |
|
39 |
|
|
36 |
|
38 |
|
1 |
|
75 |
|
34 |
|
29 |
|
- |
|
63 |
|
||||||||||||
Transportation and selling |
|
37 |
|
535 |
|
24 |
|
596 |
|
|
71 |
|
847 |
|
45 |
|
963 |
|
82 |
|
629 |
|
35 |
|
746 |
|
||||||||||||
Operating |
|
186 |
|
356 |
|
40 |
|
582 |
|
|
241 |
|
409 |
|
74 |
|
724 |
|
221 |
|
374 |
|
74 |
|
669 |
|
||||||||||||
Purchased Product |
|
- |
|
- |
|
(85) |
|
(85) |
|
|
- |
|
- |
|
(151) |
|
(151) |
|
- |
|
- |
|
(88) |
|
(88) |
|
||||||||||||
Operating Cash Flow |
|
$ |
1,543 |
|
$ |
1,373 |
|
$ |
175 |
|
$ |
3,091 |
|
|
$ |
1,953 |
|
$ |
1,929 |
|
$ |
202 |
|
$ |
4,084 |
|
$ |
1,849 |
|
$ |
1,159 |
|
$ |
231 |
|
$ |
3,239 |
|
EnCana Corporation 2009 Annual Report |
|
Managements Discussion and Analysis (prepared in US$) |
Production Volumes
|
|
2009 |
|
Q4 |
|
Q3 |
|
Q2 |
|
Q1 |
|
2008 |
|
Q4 |
|
Q3 |
|
Q2 |
|
Q1 |
|
2007 |
|
Produced Gas (MMcf/d) |
|
762 |
|
517 |
|
826 |
|
864 |
|
842 |
|
905 |
|
879 |
|
892 |
|
923 |
|
925 |
|
966 |
|
Liquids (bbls/d) |
|
99,900 |
|
75,382 |
|
113,028 |
|
106,330 |
|
105,042 |
|
100,250 |
|
103,317 |
|
99,756 |
|
93,966 |
|
103,933 |
|
101,702 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MMcfe/d) (1) |
|
1,362 |
|
970 |
|
1,504 |
|
1,502 |
|
1,472 |
|
1,507 |
|
1,499 |
|
1,491 |
|
1,487 |
|
1,549 |
|
1,576 |
|
(1) Liquids converted to thousand cubic feet equivalent at 1 barrel = 6 thousand cubic feet.
Operating Cash Flow in 2009 decreased $993 million primarily as a result of the decrease in commodity prices and one month less of reported activity.
Natural gas production volumes in 2009 decreased 16 percent primarily as a result of natural declines and one month less of activity. Liquids production volumes in 2009 were relatively unchanged compared to 2008 as a result of higher volumes from Foster Creek/Christina Lake, offset by one month less of reported activity.
Depreciation, Depletion and Amortization
($ millions) |
|
|
2009 |
|
|
2008 |
|
|
2007 |
|||||
Canada |
|
|
$ |
1,980 |
|
|
$ |
2,198 |
|
|
$ |
2,298 |
||
USA |
|
|
1,561 |
|
|
1,691 |
|
|
1,181 |
|||||
Market Optimization |
|
|
20 |
|
|
15 |
|
|
17 |
|||||
Corporate & Other |
|
|
143 |
|
|
131 |
|
|
161 |
|||||
Total DD&A |
|
|
$ |
3,704 |
|
|
$ |
4,035 |
|
|
$ |
3,657 |
||
Pro Forma DD&A(1) |
|
|
$ |
2,770 |
|
|
$ |
3,096 |
|
|
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
||
(1) |
Pro Forma DD&A expenses exclude the DD&A expenses related to the assets transferred to Cenovus under the Split Transaction and reflect an adjustment arising from a change in the depletion rate calculated for EnCanas Canadian cost centre. |
|||||||||||||
Upstream DD&A
EnCana uses full cost accounting for oil and gas activities and calculates DD&A on a country-by-country cost centre basis.
2009 versus 2008
Upstream DD&A expenses of $3,541 million in 2009 decreased $348 million compared to 2008 due to:
· DD&A expenses in Canada were lower primarily as a result of lower production volumes and the lower U.S./Canadian dollar exchange rate, partially offset by higher DD&A rates resulting from higher future development costs; and
· DD&A expenses in the USA were lower primarily due to lower DD&A rates resulting from lower future development costs and higher proved reserves.
2008 versus 2007
Upstream DD&A expenses of $3,889 million in 2008 increased $410 million compared to 2007 due to:
· Production volumes increased 6 percent; and
· DD&A rates for the USA were higher primarily due to higher capitalized costs, mainly attributable to the Deep Bossier acquisition. DD&A rates in Canada for 2008 were lower than 2007 primarily as a result of the higher proved reserves.
EnCana Corporation 2009 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Market Optimization
Financial Results
|
|
|
|
Consolidated |
|
|
|
|||
($ millions) |
|
2009 |
|
2008 |
|
2007 |
|
|||
Revenues |
|
$ |
1,607 |
|
$ |
2,655 |
|
$ |
2,944 |
|
Expenses |
|
|
|
|
|
|
|
|||
Transportation and selling |
|
- |
|
- |
|
10 |
|
|||
Operating |
|
26 |
|
45 |
|
37 |
|
|||
Purchased product |
|
1,545 |
|
2,577 |
|
2,858 |
|
|||
Operating Cash Flow |
|
36 |
|
33 |
|
39 |
|
|||
DD&A |
|
20 |
|
15 |
|
17 |
|
|||
Segment Income |
|
$ |
16 |
|
$ |
18 |
|
$ |
22 |
|
|
|
|
|
|
|
|
|
Market Optimization revenues and purchased product expenses relate to activities that provide operational flexibility for transportation commitments, product type, delivery points and customer diversification that enhance the sale of EnCanas production.
Revenues and purchased product expenses decreased in 2009 compared to 2008 mainly due to decreased pricing, partially offset by increases in volume required for Market Optimization. The decreases in 2008 compared to 2007 were mainly due to overall volume decreases required for Market Optimization, partially offset by increased pricing.
Corporate and Other
Financial Results
|
|
|
|
Consolidated |
|
|
|
|||
($ millions) |
|
2009 |
|
2008 |
|
2007 |
|
|||
Revenues |
|
$ |
(2,615) |
|
$ |
2,719 |
|
$ |
(1,239) |
|
Expenses |
|
|
|
|
|
|
|
|||
Operating |
|
49 |
|
(13) |
|
14 |
|
|||
DD&A |
|
143 |
|
131 |
|
161 |
|
|||
Segment Income (Loss) |
|
$ |
(2,807) |
|
$ |
2,601 |
|
$ |
(1,414) |
|
Revenues represent primarily unrealized mark-to-market gains or losses related to financial natural gas and liquids hedge contracts.
Operating expenses in 2009 primarily relate to mark-to-market losses on long-term power generation contracts.
DD&A includes provisions for corporate assets, such as computer equipment, office furniture and leasehold improvements. DD&A also includes impairments related to international exploration prospects.
Summary of Unrealized Mark-to-Market Gains (Losses)
|
|
|
|
Consolidated |
|
|
|
|||
($ millions) |
|
2009 |
|
2008 |
|
2007 |
|
|||
Revenues |
|
|
|
|
|
|
|
|||
Natural Gas |
|
$ |
(2,538) |
|
$ |
2,475 |
|
$ |
(1,049) |
|
Crude Oil |
|
(102) |
|
242 |
|
(190) |
|
|||
|
|
(2,640) |
|
2,717 |
|
(1,239) |
|
|||
Expenses |
|
40 |
|
(12) |
|
(4) |
|
|||
|
|
(2,680) |
|
2,729 |
|
(1,235) |
|
|||
Income Tax Expense (Recovery) |
|
(888) |
|
911 |
|
(424) |
|
|||
Unrealized Mark-to-Market Gains (Losses), after-tax |
|
$ |
(1,792) |
|
$ |
1,818 |
|
$ |
(811) |
|
Commodity price volatility impacts net earnings. As a means of managing this commodity price volatility, EnCana enters into various financial instrument agreements. The financial instrument agreements were recorded at the date of the financial statements based on mark-to-market accounting. Changes in the mark-to-market gain or loss reflected in corporate revenues are the result of volatility between periods in the forward curves of commodity prices and changes in the balance of unsettled contracts. Further information regarding financial instrument agreements can be found in Note 20 to the Consolidated Financial Statements.
EnCana Corporation 2009 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Expenses
|
|
Pro Forma |
|
Consolidated |
|
||||||||||||||
($ millions) |
|
2009 |
|
|
2008 |
|
2009 |
|
|
2008 |
|
2007 |
|
||||||
Administrative |
|
$ |
359 |
|
|
$ |
329 |
|
$ |
477 |
|
|
$ |
447 |
|
$ |
356 |
|
|
Interest, net |
|
371 |
|
|
368 |
|
405 |
|
|
402 |
|
234 |
|
||||||
Accretion of asset retirement obligation |
|
37 |
|
|
40 |
|
71 |
|
|
77 |
|
63 |
|
||||||
Foreign exchange (gain) loss, net |
|
(312) |
|
|
673 |
|
(22) |
|
|
423 |
|
(164) |
|
||||||
(Gain) loss on divestitures |
|
2 |
|
|
(143) |
|
2 |
|
|
(141) |
|
(65) |
|
||||||
Total Expenses |
|
$ |
457 |
|
|
$ |
1,267 |
|
$ |
933 |
|
|
$ |
1,208 |
|
$ |
424 |
|
|
(1) |
Pro Forma expenses exclude the expenses related to the oil and gas assets transferred to Cenovus under the Split Transaction and reflect adjustments for compensation costs and transaction costs. |
||||||||||||||||||
2009 versus 2008
Consolidated expenses of $933 million decreased $275 million due to:
· Foreign exchange losses of $95 million and gains of $22 million in the fourth quarter and full year of 2009, respectively, compared to losses of $253 million and $423 million in the fourth quarter and full year of 2008, respectively, were primarily due to the effects of the U.S./Canadian dollar exchange rate on U.S. dollar denominated debt issued from Canada, offset by revaluation of the partnership contribution receivable, settlement of foreign currency denominated intercompany transactions and revaluation of monetary items. Pro forma foreign exchange excludes the impact of foreign exchange on the partnership contribution receivable as it was transferred to Cenovus under the Split Transaction.
· Administrative expenses increased primarily as a result of higher long-term compensation costs, partially offset by the lower U.S./Canadian dollar exchange rate. Fourth quarter 2009 administrative expenses of $145 million were higher than fourth quarter 2008 expenses of $67 million primarily due to higher long-term compensation costs, increased costs related to the Split Transaction and the higher U.S./Canadian dollar exchange rate.
· The gain on divestitures in 2008 relates primarily to the divestiture of interests in Brazil. Additional detail on gains and losses on divestitures can be found in the Acquisitions and Divestitures section of this MD&A.
2008 versus 2007
Consolidated expenses of $1,208 million increased $784 million due to:
· Foreign exchange losses of $253 million and $423 million in the fourth quarter and full year of 2008, respectively, are primarily due to the effects of the U.S./Canadian dollar exchange rate on U.S. dollar denominated debt issued from Canada, offset by revaluation of the partnership contribution receivable.
· Net interest expense increased primarily as a result of higher weighted average outstanding debt. EnCanas 2008 weighted average interest rate on outstanding debt was 5.5 percent compared to 5.6 percent in 2007.
· Administrative expenses increased primarily due to higher staff levels and one time charges for legal settlements, offset by lower long-term compensation costs as a result of the change in the EnCana share price. The proposed corporate reorganization also added costs for work needed to prepare for the transaction. Fourth quarter 2008 administrative expenses of $67 million was lower than fourth quarter 2007 expenses of $96 million primarily due to lower long-term compensation costs and the lower U.S./Canadian dollar exchange rate, partially offset by costs for the proposed corporate reorganization and other related costs due to growth.
Income Tax
|
|
Pro Forma |
|
Consolidated |
|
|||||||||||
|
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
2007 |
|
|||||
Effective Tax Rate |
|
13.0% |
|
35.4% |
|
5.6% |
|
29.5% |
|
16.5% |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||
($ millions) |
|
|
|
|
|
|
|
|
|
|
|
|||||
Current Income Tax |
|
$ |
550 |
|
$ |
568 |
|
$ |
1,908 |
|
$ |
997 |
|
$ |
1,380 |
|
Future Income Tax |
|
(438) |
|
1,297 |
|
(1,799) |
|
1,723 |
|
(698) |
|
|||||
Total Income Tax |
|
$ |
112 |
|
$ |
1,865 |
|
$ |
109 |
|
$ |
2,720 |
|
$ |
682 |
|
EnCana Corporation 2009 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
2009 versus 2008
Consolidated total income tax expense in 2009 was $2,611 million lower than in 2008 primarily due to lower Net Earnings Before Income Tax.
Consolidated current income tax expense in 2009 was $911 million higher than in 2008. This reflects incremental current tax expense related to the wind-up of the Canadian oil and gas partnership and increased realized hedging gains, offset by lower commodity prices and volumes.
Consolidated future income tax expense in 2009 was $3,522 million lower than in 2009 primarily due to the reversal of the unrealized hedging gain and the wind-up of the Canadian oil and gas partnership.
2008 versus 2007
The 2007 effective tax rate was lower primarily due to a one time Canadian federal corporate legislative change and a reduction in the Canadian federal corporate tax rates.
Consolidated current income tax expense in 2008 was $383 million lower than in 2007. This is comprised of $562 million related to the increased benefits from international financing and a U.S. tax legislative change in 2008 that allows an accelerated write-off of certain capital expenditures, offset by a one time tax recovery of $179 million in 2007 for a Canadian tax legislative change.
Consolidated future income tax expense in 2008 was $2,421 million higher than in 2007 primarily due to the increased unrealized mark-to-market hedging gains and the accelerated write-offs for certain U.S. capital expenditures as well as the reduction of the Canadian federal corporate tax rates in 2007.
EnCanas effective rate in any year is a function of the relationship between total tax (current and future) and the amount of net earnings before income taxes for the year. The effective tax rate differs from the statutory tax rate as it takes into consideration permanent differences, adjustment for changes to tax rates and other tax legislation, variation in the estimation of reserves and the estimate to actual differences. Permanent differences are a variety of items, including:
· The non-taxable portion of Canadian capital gains or losses;
· International financing; and
· Foreign exchange (gains) losses not included in net earnings.
Tax interpretations, regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change. As a result, there are usually some tax matters under review. The Company believes that the provision for taxes is adequate.
Capital Investment
Capital investment in 2009, 2008 and 2007 were primarily directed towards business information systems, leasehold improvements and office furniture. On February 9, 2007, EnCana announced that it had entered into a 25-year lease agreement with a third-party developer for The Bow office project. Cost-of-design changes to the building and leasehold improvements are shared by EnCana and Cenovus.
Discontinued Operations
EnCana has rationalized its operations to focus on upstream activities in North America, resulting in divestitures which are accounted for as Discontinued Operations. EnCanas 2009 Net Earnings from Discontinued Operations were $32 million (2008 $555 million loss; 2007 $512 million). Additional information on Discontinued Operations can be found in Note 6 to the Consolidated Financial Statements.
Downstream Refining
As a result of the November 30, 2009 Split Transaction, EnCanas operations are focused on natural gas activities which excludes refining assets, and accordingly, has reported results from Downstream Refining as Discontinued Operations. Downstream Refining focused on the refining of crude oil into petroleum and chemical products at two refineries located in the United States. These refineries were jointly owned with ConocoPhillips.
Midstream
The $75 million gain on discontinuance in 2007 is the result of an expired clause included in the December 2005 sale of the Companys Midstream NGLs processing operations. The clause provided potential market price support for the facilities and was accrued for in 2005.
EnCana Corporation 2009 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Liquidity and Capital Resources
($ millions) |
|
2009 |
|
|
2008 |
|
|
2007 |
|
|||
Net cash from (used in) |
|
|
|
|
|
|
|
|
|
|||
Operating activities |
|
$ |
7,873 |
|
|
$ |
8,986 |
|
|
$ |
8,262 |
|
Investing activities |
|
(4,806) |
|
|
(7,542) |
|
|
(8,179) |
|
|||
Financing activities |
|
835 |
|
|
(1,439) |
|
|
(119) |
|
|||
Foreign exchange gain (loss) on cash and cash equivalents held in foreign currency |
|
19 |
|
|
(33) |
|
|
16 |
|
|||
Increase (decrease) in cash and cash equivalents |
|
$ |
3,921 |
|
|
$ |
(28) |
|
|
$ |
(20) |
|
Pro Forma net cash from Operating activities |
|
$ |
5,041 |
|
|
$ |
6,224 |
|
|
|
|
Operating Activities
Net cash from operating activities decreased $1,113 million in 2009 compared to 2008. Cash Flow was $6,779 million during 2009 compared to $9,386 million in 2008. Reasons for this change are discussed under the Consolidated Cash Flow section of this MD&A. Cash from operating activities were also impacted by net changes in other assets and liabilities, net changes in non-cash working capital and net changes in non-cash working capital from Discontinued Operations.
Excluding the impact of current risk management assets and liabilities, the Company had a working capital surplus of $1,348 million at December 31, 2009 compared to a deficit of $1,067 million at December 31, 2008. EnCana anticipates that it will continue to meet the payment terms of its suppliers.
Investing Activities
Net cash used for investing activities in 2009 decreased $2,736 million compared to 2008.
Capital expenditures, including property acquisitions, decreased $3,109 million in 2009 compared to 2008 and proceeds from divestitures increased $274 million in 2009 compared to 2008. Reasons for these changes are discussed under the Net Capital Investment and Divisional Results sections of this MD&A.
Following the Split Transaction, EnCana received amounts due from Cenovus and invested the net proceeds of approximately $3,750 million in short-term marketable securities (Cenovus Notes).
Financing Activities
In conjunction with the Split Transaction, on September 18, 2009, Cenovus completed a private offering of senior unsecured notes for an aggregate principal amount of $3,500 million. The net proceeds of the private offering were placed into an escrow account to be released to Cenovus upon completion of the Split Transaction. The underwriters deposited $3,468 million and Cenovus contributed $151 million to the escrow account for total funds of $3,619 million. The funds were released to Cenovus upon completion of the Split Transaction. Cenovus used the funds to settle the Cenovus Notes due to EnCana as described above.
Excluding the Cenovus Notes, net repayment of long-term debt in 2009 was $1,606 million compared to net issuance of $6 million in 2008. EnCanas total long-term debt including current portion was $7,768 million at December 31, 2009 compared to $9,005 million at December 31, 2008.
On May 4, 2009, EnCana completed a public offering in the United States of senior unsecured notes in the aggregate principal amount of $500 million. The notes have a coupon rate of 6.5 percent and mature on May 15, 2019. The net proceeds of the offering were used to repay a portion of EnCanas existing bank and commercial paper indebtedness.
EnCana maintains two committed bank credit facilities and a Canadian and a U.S. dollar shelf prospectus.
As at December 31, 2009, EnCana had available unused committed bank credit facilities in the amount of $4.9 billion. EnCana has in place a revolving bank credit facility for C$4.5 billion that remains committed through October 2012. One of EnCanas U.S. subsidiaries has in place a revolving bank credit facility for $565 million that remains committed through February 2013.
EnCana Corporation 2009 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
On May 21, 2009, EnCana renewed a shelf prospectus whereby it may issue from time to time up to C$2.0 billion, or the equivalent in foreign currencies, of debt securities in Canada. At December 31, 2009, C$2.0 billion ($1.9 billion) of the shelf prospectus remained unutilized, the availability of which is dependent upon market conditions. The shelf prospectus expires in June 2011.
EnCana has in place a shelf prospectus whereby it may issue from time to time up to $4.0 billion, or the equivalent in foreign currencies, of debt securities in the United States. At December 31, 2009, $3.5 billion of the shelf prospectus remained unutilized, the availability of which is dependent upon market conditions. The shelf prospectus was renewed in March 2008 and expires in April 2010.
As at December 31, 2009, EnCana had available unused capacity under shelf prospectuses for up to $5.4 billion.
EnCana is currently in compliance with and anticipates that it will continue to be in compliance with all financial covenants under its credit facility agreements and indentures.
EnCana maintains investment grade credit ratings on its senior unsecured debt. On November 30, 2009 following the completion of the Split Transaction, Standard & Poors Ratings Services lowered the rating to BBB+ from A- and changed the outlook to Stable from CreditWatch with negative implications. Moodys Investors Service affirmed the rating of Baa2 with a Stable outlook. DBRS Limited maintained the rating of A (low) and changed the outlook to Stable from Under Review with Developing Implications. These credit ratings remained unchanged at December 31, 2009.
EnCana has obtained regulatory approval under Canadian securities laws to purchase up to approximately 37.5 million Common Shares under a Normal Course Issuer Bid (NCIB), which commenced on December 14, 2009 and expires on December 13, 2010. During 2009, under the NCIB and a prior NCIB, EnCana did not purchase any of its Common Shares compared to 4.8 million Common Shares purchased for total consideration of approximately $326 million in 2008. Shareholders may obtain a copy of the Companys Notice of Intention to make a Normal Course Issuer Bid by contacting investor.relations@encana.com.
EnCana pays quarterly dividends to shareholders at the discretion of the Board of Directors. Dividend payments in 2009 were $1,051 million (2008 $1,199 million; 2007 $603 million) or $1.40 per share (2008 $1.60 per share; 2007 $0.80 per share). From the first quarter of 2008 to the completion of the Split Transaction, EnCana paid a quarterly dividend of $0.40 per share. On December 31, 2009, after the Split Transaction, EnCana paid a quarterly dividend of $0.20 per share. The Board of Directors of Cenovus also declared a dividend of $0.20 per share payable on December 31, 2009 to Cenovus common shareholders. These dividends were funded by Cash Flow.
Debt to Capitalization and Debt to Adjusted EBITDA are two ratios Management uses to steward the Companys overall debt position as measures of the Companys overall financial strength. EnCana targets a Debt to Capitalization ratio of less than 40 percent and a Debt to Adjusted EBITDA of less than 2.0 times. At December 31, 2009, the Companys Debt to Capitalization ratio and consolidated Debt to Adjusted EBITDA were within these targets. The Companys pro forma Debt to Adjusted EBITDA was slightly higher than its target primarily due to the depressed natural gas prices experienced during 2009.
Financial Metrics
|
|
Pro Forma |
|
|
|
Consolidated |
|
|
|
|
|
|
2009 |
|
2009 |
|
2008 |
|
2007 |
|
|
Debt to Capitalization (1)(2) |
|
32% |
|
32% |
|
28% |
|
32% |
|
|
Debt to Adjusted EBITDA (times) (1)(3) |
|
2.1x |
|
1.3x |
|
0.6x |
|
1.2x |
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Debt is defined as Long-Term Debt including current portion. |
|||||||||
(2) |
Capitalization is a non-GAAP measure defined as Long-Term Debt including current portion plus Shareholders Equity. |
|||||||||
(3) |
Trailing 12-month 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. |
|||||||||
EnCana had approximately $4.3 billion in cash and short-term investments primarily as a result of a corporate reorganization more fully described in EnCanas Business section of this MD&A. The Company repaid all of its short-term debt during 2009 and expects to use part of its cash balance to pay its current income tax liability of approximately $1.8 billion in February 2010.
EnCana Corporation 2009 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Contractual Obligations and Contingencies
Contractual Obligations and Commitments (1)
|
|
Expected Payment Date |
|||||||||||||||||||||||||
($ millions) |
|
2010 |
|
2011 to 2012 |
|
2013 to 2014 |
|
2015+ |
|
Total |
|||||||||||||||||
Long-Term Debt (2) |
|
$ |
200 |
|
$ |
978 |
|
$ |
1,500 |
|
$ |
5,116 |
|
$ |
7,794 |
||||||||||||
Asset Retirement Obligation |
|
41 |
|
72 |
|
98 |
|
3,581 |
|
3,792 |
|||||||||||||||||
Pipeline Transportation |
|
438 |
|
991 |
|
998 |
|
1,911 |
|
4,338 |
|||||||||||||||||
Purchase of Goods and Services |
|
377 |
|
640 |
|
422 |
|
684 |
|
2,123 |
|||||||||||||||||
Operating Leases (3) |
|
69 |
|
158 |
|
329 |
|
3,238 |
|
3,794 |
|||||||||||||||||
Capital Commitments |
|
127 |
|
236 |
|
38 |
|
- |
|
401 |
|||||||||||||||||
Other Long-Term Commitments |
|
2 |
|
4 |
|
3 |
|
24 |
|
33 |
|||||||||||||||||
Total |
|
$ |
1,254 |
|
$ |
3,079 |
|
$ |
3,388 |
|
$ |
14,554 |
|
$ |
22,275 |
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
Cenovuss Share of Costs(4) |
|
$ |
90 |
|
$ |
179 |
|
$ |
148 |
|
$ |
1,576 |
|
$ |
1,993 |
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
(1) |
In addition, the Company has made commitments related to its risk management program. See Note 20 to the Consolidated Financial Statements.The Company has an obligation to fund its defined benefit pension and Other Post-Employment Benefit plans as disclosed in Note 19 to the Consolidated Financial Statements. |
||||||||||||||||||||||||||
(2) |
Principal component only. See Note 15 to the Consolidated Financial Statements. |
||||||||||||||||||||||||||
(3) |
Primarily related to office space associated with The Bow. |
||||||||||||||||||||||||||
(4) |
Tenant costs associated with The Bow as well as current office space lease arrangements remain with EnCana. Cenovus and EnCana have entered into an agreement to share in the costs. |
||||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||
EnCana has entered into various commitments primarily related to demand charges for firm transportation, leasing of office space, procurement arrangements for goods and services, as well as other minor spending commitments. EnCana and Cenovus have entered into an arrangement whereby the portion of the commitments related to the Cenovus operations have been transferred to Cenovus as a result of the Split Transaction and are excluded from the table above.
The Company expects its 2010 commitments to be funded from Cash Flow.
Leases
In the normal course of business, EnCana leases office space for personnel who support field operations and for corporate purposes. As a result of the Split Transaction, EnCana has agreed to sub-lease a portion of its corporate office space and obtains rent from Cenovus based on a preset formula. This is included in revenue in the Corporate and Other segment.
Variable Interest Entities (VIEs)
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 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 Haynesville represented an interest in a VIE from September 25, 2008 to March 24, 2009. During this period, EnCana was the primary beneficiary of the VIE and consolidated Brown Haynesville. On March 24, 2009, when the arrangement with Brown Haynesville was completed, the assets were transferred to EnCana.
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 held 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. The relationship with Brown Southwest represented an interest in a VIE from July 23, 2008 to January 19, 2009. During this period, EnCana was the primary beneficiary of the VIE and consolidated Brown Southwest. On January 19, 2009, when the arrangement with Brown Southwest was completed, the assets were transferred to EnCana.
On November 20, 2007, EnCana acquired certain natural gas and land interests in Texas for approximately $2.55 billion before closing adjustments. The purchase was facilitated by an unrelated party, Brown Kilgore Properties LLC (Brown Kilgore), which held the majority of the assets in trust for the Company in anticipation of a qualifying like kind exchange for U.S. tax purposes. The relationship with Brown Kilgore represented an interest in a VIE from November 20, 2007 to May 18, 2008. During this period, EnCana was the primary beneficiary of the VIE and consolidated Brown Kilgore. On May 18, 2008, when the arrangement with Brown Kilgore was completed, the assets were transferred to EnCana.
EnCana Corporation 2009 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Legal Proceedings
EnCana is involved in various legal claims associated with the normal course of operations and 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. All but one of these lawsuits had been settled prior to 2009. Without admitting any liability whatsoever, the remaining lawsuit was settled on October 16, 2009.
Outlook
EnCana plans to focus on growing natural gas production from its diversified portfolio of existing and emerging unconventional resource plays in North America.
EnCana remains highly focused on key business objectives of maintaining financial strength, optimizing capital investments and continuing to pay a stable dividend to shareholders attained through a disciplined approach to capital spending, a flexible investment program and financial stewardship. EnCana has been consistently among the lowest cost companies in the natural gas industry and has a history of entering resource plays early and leveraging technology to unlock unconventional resources.
Natural gas prices are primarily driven by North American supply and demand, with weather being the key factor in the short term. EnCana believes that natural gas represents an abundant, secure, long-term supply of energy to meet North American needs.
EnCanas results are affected by external market and risk factors, such as fluctuations in the prices of crude oil and natural gas, movements in foreign currency exchange rates and inflationary pressures on service costs. Additional detail regarding the impact of these factors on 2010 results is available in the Corporate Guidance on the Companys website at www.encana.com.
Risk Management
EnCanas business, prospects, financial condition, results of operation and cash flows, and in some cases its reputation, are impacted by risks that are categorized as follows:
· financial risks;
· operational risks; and
· safety, environmental and regulatory risks.
Issues affecting, or with the potential to affect, EnCanas reputation are generally of a strategic nature or emerging issues that can be identified early and then managed, but occasionally include unforeseen issues that arise unexpectedly and must be managed on an urgent basis. EnCana takes a proactive approach to the identification and management of issues that affect the Companys reputation and has established consistent and clear policies, procedures, guidelines and responsibilities for identifying and managing these issues.
EnCana has a strong financial position and continues to implement its business model of focusing on developing low-risk and low-cost long-life resource plays, which allows the Company to respond well to market uncertainties. Management adjusts financial and operational risk strategies to proactively respond to changing economic conditions and to mitigate or reduce risk.
Financial Risks
EnCana defines financial risks as the risk of loss or lost opportunity resulting from financial management and market conditions that could have a positive or negative impact on EnCanas business.
EnCana Corporation 2009 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Financial risks include, but are not limited to:
· Market pricing of natural gas;
· Credit and liquidity;
· Foreign exchange; and
· Interest rate.
EnCana partially mitigates its exposure to financial risks through the use of various financial instruments and physical contracts. The use of derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors. All financial derivative and foreign exchange agreements are with major financial institutions in Canada and the United States or with counterparties having investment grade credit ratings.
EnCana has in place policies and procedures with respect to the required documentation and approvals for the use of derivative financial instruments and specifically ties their use, in the case of commodities, to the mitigation of price risk to achieve targeted investment returns and growth objectives, while maintaining prescribed financial metrics.
With respect to transactions involving proprietary production or assets, the financial instruments generally used by EnCana are swaps or options, which are entered into with major financial institutions, integrated energy companies or commodities trading institutions.
To partially mitigate the natural gas commodity price risk, the Company enters into swaps, which fix NYMEX prices. To help protect against varying 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. Further information, including the details of EnCanas financial instrument holdings as of December 31, 2009, is disclosed in Note 20 to the Consolidated Financial Statements.
Counterparty and credit risks are regularly and proactively managed. A substantial portion of EnCanas accounts receivable is with customers in the oil and gas industry. This credit exposure is mitigated through the use of Board-approved credit policies governing the Companys credit portfolio and with credit practices that limit transactions according to counterparties credit quality and transactions that are fully collateralized.
EnCana closely monitors the Companys ability to access cost effective credit and that sufficient cash resources are in place to fund capital expenditures and fund dividend payments. The Company manages liquidity risk through cash and debt management programs, including maintaining a strong balance sheet and significant unused credit facilities. The Company also has access to a wide range of funding alternatives at competitive rates, including commercial paper, capital market debt and bank loans. EnCana maintains investment grade credit ratings on its senior unsecured debt.
As a means of mitigating the exposure to fluctuations in the U.S./Canadian dollar exchange rate, EnCana may enter into foreign exchange contracts. Gains or losses on these contracts are recognized when the difference between the average month spot rate and the rate on the date of settlement is determined. By maintaining U.S. and Canadian operations, EnCana has a natural hedge to some foreign exchange exposure.
EnCana also maintains a mix of both U.S. dollar and Canadian dollar debt, which helps to offset the exposure to the fluctuations in the U.S./Canadian dollar exchange rate. In addition to direct issuance of U.S. dollar denominated debt, the Company may enter into cross currency swaps on a portion of its debt as a means of managing the U.S./Canadian dollar debt mix.
Typically, the Company partially mitigates its exposure to interest rate changes by maintaining a mix of both fixed and floating rate debt. EnCana may enter into interest rate swap transactions from time to time as an additional means of managing the fixed/floating rate debt portfolio mix.
Operational Risks
Operational risks are defined as the risk of loss or lost opportunity resulting from the following:
· Reserve replacement;
· Capital activities; and
· Operating activities.
EnCana Corporation 2009 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
The Companys ability to operate, generate cash flows, complete projects, and value reserves is dependent on financial risks, including commodity prices mentioned above, continued market demand for its products and other risk factors outside of its control, which include: general business and market conditions; economic recessions and financial market turmoil; the ability to secure and maintain cost effective financing for its commitments; environmental and regulatory matters; unexpected cost increases; royalties; taxes; the availability of drilling and other equipment; the ability to access lands; weather; the availability of processing capacity; the availability and proximity of pipeline capacity; technology failures; accidents; the availability of skilled labour; and reservoir quality.
If EnCana fails to acquire or find additional natural gas reserves, its reserves and production will decline materially from their current levels and, therefore, its cash flows are highly dependent upon successfully exploiting current reserves and acquiring, discovering or developing additional reserves.
To mitigate these risks, as part of the capital approval process, the Companys projects are evaluated on a fully risked basis, including geological risk and engineering risk. In addition, the asset teams undertake a thorough review of its previous capital program to identify key learnings, which often include operational issues that positively and negatively impacted the projects results. Mitigation plans are developed for the operational issues that had a negative impact on results. These mitigation plans are then incorporated into the current year plan for the project. On an annual basis, these results are analyzed for EnCanas capital program with the results and identified learnings shared across the Company.
A peer review process is used to ensure that capital projects are appropriately risked and that knowledge is shared across the Company. Peer reviews are undertaken primarily for exploration projects and early stage resource plays, although they may occur for any type of project.
When making operating and investing decisions, EnCanas business model allows flexibility in capital allocation to optimize investments focused on project returns, long-term value creation, and risk mitigation. EnCana also mitigates operational risks through a number of other policies, systems and processes as well as by maintaining a comprehensive insurance program.
Safety, Environmental and Regulatory Risks
The Corporations business is subject to all of the operating risks normally associated with the exploration for, development of and production of natural gas and liquids and the operation of midstream facilities. The Company is committed to safety in its operations and has high regard for the environment and stakeholders, including regulators. These risks are managed by executing policies and standards that are designed to comply with or exceed government regulations and industry standards. In addition, EnCana maintains a system that identifies, assesses and controls safety, security and environmental risk and requires regular reporting to Senior Management and the Board of Directors. The Corporate Responsibility, Environment, Health & Safety Committee of EnCanas Board of Directors provides recommended environmental policies for approval by EnCanas Board of Directors and oversees compliance with government laws and regulations. Monitoring and reporting programs for environmental, health and safety performance in day-to-day operations, as well as inspections and audits, are designed to provide assurance that environmental and regulatory standards are met. Contingency plans are in place for a timely response to environmental events and remediation/reclamation strategies are utilized to restore the environment. In addition, security risks are managed through a Security Program designed to protect EnCanas personnel and assets.
EnCana has an Investigations Committee with the mandate to address potential violations of Company policies and practices and an Integrity Hotline that can be used to raise any concerns regarding EnCanas operations, accounting or internal control matters.
EnCanas operations are subject to regulation and intervention by governments that can affect or prohibit the drilling, completion, including hydraulic fracturing and tie-in of wells, production, the construction or expansion of facilities and the operation and abandonment of fields. Contract rights can be cancelled or expropriated. Changes to government regulation could impact the Companys existing and planned projects as well as impose a cost of compliance.
Regulatory and legal risks are identified by the operating divisions and corporate groups. EnCanas compliance with the required laws and regulations is monitored by EnCanas legal group, which stays abreast of new developments and changes in laws and regulations to ensure that EnCana continues to comply with prescribed laws and regulations. Of note in this regard currently is EnCanas approach to changes in regulations relating to climate change and royalty frameworks as discussed below. To partially mitigate resource access risks, keep abreast of regulatory developments and be a responsible operator, EnCana maintains relationships with key stakeholders and conducts other mitigation initiatives mentioned herein.
EnCana Corporation 2009 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Climate Change
A number of federal, provincial and state governments have announced intentions to regulate greenhouse gases (GHG) and other air pollutants. While some jurisdictions have provided details on these regulations, it is anticipated that other jurisdictions will announce emission reduction plans in the future. As these federal and regional programs are under development, EnCana is unable to predict the total impact of the potential regulations upon its business. Therefore, it is possible that the Company could face increases in operating and capital costs in order to comply with GHG emissions legislation. However, EnCana will continue to work with governments to develop an approach to deal with climate change issues that protects the industrys competitiveness, limits the cost and administrative burden of compliance and supports continued investment in the sector.
The Alberta Government has set targets for GHG emissions reductions. In March 2007, regulations were amended to require facilities that emit more than 100,000 tonnes of GHG emissions per year to reduce their emissions intensity by 12 percent from a regulated baseline starting July 1, 2007. To comply, companies can make operating improvements, purchase carbon offsets or make a C$15 per tonne contribution to an Alberta Climate Change and Emissions Management Fund. In Alberta, EnCana has one facility covered under the emissions regulations. The forecast cost of carbon associated with the Alberta regulations is not material to EnCana at this time and is being actively managed.
In British Columbia, effective July 1, 2008, a revenue neutral carbon tax was applied to virtually all fossil fuels, including diesel, natural gas, coal, propane, and home heating fuel. The tax applies to combustion emissions and to the purchase or use of fossil fuels within the province. The rate started at C$10 per tonne of carbon equivalent emissions, is currently C$15 per tonne and rises to C$30 per tonne by 2012. The forecast cost of carbon associated with the British Columbia regulations is not material to EnCana at this time and is being actively managed.
The American Clean Energy and Security Act (ACESA) was passed by the House of Representatives on June 26, 2009. This climate change legislation would establish a GHG cap-and-trade system and provide incentives for the development of renewable energy. The House Act aims to reduce GHG emissions by 17 percent from 2005 levels by 2020, and 83 percent by 2050. The Senate version of the climate bill, however, is still in progress. Once the Senate completes its work, the House and Senate bills will need to be reconciled and submitted to the US Administration for final approval. EnCana will continue to monitor these developments closely during 2010.
EnCana intends to continue its activity to reduce its emissions intensity and improve its energy efficiency. The Companys efforts with respect to emissions management are founded on the following key elements:
· significant production weighting in natural gas;
· focus on energy efficiency and the development of technology to reduce GHG emissions; and
· involvement in the creation of industry best practices.
EnCanas strategy for addressing the implications of emerging carbon regulations is proactive and is composed of three principal elements:
· Manage Existing Costs
When regulations are implemented, a cost is placed on EnCanas emissions (or a portion thereof) and while these are not material at this stage, they are being actively managed to ensure compliance. Factors such as effective emissions tracking and attention to fuel consumption help to support and drive its focus on cost reduction.
· Respond to Price Signals
As regulatory regimes for GHGs develop in the jurisdictions where EnCana works, inevitably price signals begin to emerge. The Company has initiated an Energy Efficiency Initiative in an effort to improve the energy efficiency of its operations. The price of potential carbon reductions plays a role in the economics of the projects that are implemented. In response to the anticipated price of carbon, EnCana is also attempting, where appropriate, to realize the associated value of its reduction projects.
· Anticipate Future Carbon Constrained Scenarios
EnCana continues to work with governments, academics and industry leaders to develop and respond to emerging GHG regulations. By continuing to stay engaged in the debate on the most appropriate means to regulate these emissions, the Company gains useful knowledge that allows it to explore different strategies for managing its emissions and costs. These scenarios influence EnCanas long range planning and its analyses on the implications of regulatory trends.
EnCana incorporates the potential costs of carbon into future planning. Management and the Board review the impact of a variety of carbon constrained scenarios on its strategy, with a current price range from $15 to $65 per tonne of emissions applied to a range of emissions coverage levels. A major benefit of applying a range of carbon prices at the strategic level is that it provides direct guidance
EnCana Corporation 2009 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
to the capital allocation process. EnCana also examines the impact of carbon regulation on its major projects. Although uncertainty remains regarding potential future emissions regulation, EnCanas plan is to continue to assess and evaluate the cost of carbon relative to its investments across a range of scenarios.
EnCana recognizes that there is a cost associated with carbon emissions. EnCana is confident that GHG regulations and the cost of carbon at various price levels have been adequately considered as part of its business planning and scenarios analyses. EnCana believes that the resource play strategy is an effective way to develop the resource, generate shareholder returns and coordinate overall environmental objectives with respect to carbon, air emissions, water and land. EnCana is committed to transparency with its stakeholders and will keep them apprised of how these issues affect operations. Additional detail on EnCanas GHG emissions is available in the Corporate Responsibility Report that is available on the Companys website at www.encana.com.
Accounting Policies and Estimates
New Accounting Standards Adopted
On January 1, 2009, the Company adopted the Canadian Institute of Chartered Accountants (CICA) Handbook Section 3064 Goodwill and Intangible Assets. The adoption of this standard has had no material impact on EnCanas Consolidated Financial Statements. Additional information on the effects of the implementation of the new standard can be found in Note 2 to the Consolidated Financial Statements.
International Financial Reporting Standards (IFRS)
EnCanas IFRS Changeover Plan
In February 2008, the CICAs Accounting Standards Board confirmed that IFRS will replace Canadian GAAP 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 2010 required comparative information.
The key elements of EnCanas 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.
During 2009, EnCana made significant progress on its changeover plan. The Company analyzed accounting policy alternatives and preliminarily drafted its IFRS accounting policies. Process and system changes have been designed for significant areas of impact, with internal control requirements taken into account. Information system changes have been tested. IFRS education sessions have been held with internal stakeholders.
Process and system changes will be implemented in early 2010 to ensure IFRS comparative data is captured. EnCanas IFRS accounting policies are expected to be finalized mid-2010. Quantification of IFRS impacts will then be determined utilizing previously captured data. Communication of impacts to external stakeholders is expected to occur in the latter half of 2010.
EnCana will continue to update its IFRS changeover plan to reflect new and amended accounting standards issued by the International Accounting Standards Board.
Expected Accounting Policy Impacts
EnCanas significant areas of impact continue to include property, plant and equipment (PP&E), asset retirement obligation (ARO), impairment testing, stock-based compensation and income taxes. These areas of impact have the greatest potential impact to the Companys financial statements. The following discussion provides an overview of these areas, as well as the exemptions available under IFRS 1, First-time Adoption of International Financial Reporting Standards. In general, IFRS 1 requires first time adopters to retrospectively apply IFRS, although it does provide optional and mandatory exemptions to these requirements.
EnCana Corporation 2009 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Property, Plant and Equipment
Under Canadian GAAP, EnCana follows the CICAs guideline on full cost accounting in which all costs directly associated with the acquisition of, the exploration for, and the development of natural gas and crude oil reserves are capitalized on a country-by-country cost centre basis. Costs accumulated within each country cost centre are depleted using the unit-of-production method based on proved reserves determined using estimated future prices and costs. Upon transition to IFRS, EnCana will be required to adopt new accounting policies for upstream activities, including pre-exploration costs, exploration and evaluation costs and development costs.
Pre-exploration costs are those expenditures incurred prior to obtaining the legal right to explore and must be expensed under IFRS. Currently, EnCana capitalizes and depletes pre-exploration costs within the country cost centre. In 2008 and 2009, these costs were not material to EnCana.
Exploration and evaluation costs are those expenditures for an area or project for which technical feasibility and commercial viability have not yet been determined. Under IFRS, EnCana will initially capitalize these costs as Exploration and Evaluation assets on the balance sheet. When the area or project is determined to be technically feasible and commercially viable, the costs will be transferred to PP&E. Unrecoverable exploration and evaluation costs associated with an area or project will be expensed.
Development costs include those expenditures for areas or projects where technical feasibility and commercial viability have been determined. Under IFRS, EnCana will continue to capitalize these costs within PP&E on the balance sheet. However, the costs will be depleted on a unit-of-production basis over an area level (unit of account) instead of the country cost centre level currently utilized under Canadian GAAP. EnCana has not finalized the areas or the inputs to be utilized in the unit-of-production depletion calculation.
Under IFRS, upstream divestures will generally result in a gain or loss recognized in net earnings. Under Canadian GAAP, proceeds of divestitures are normally deducted from the full cost pool without recognition of a gain or loss unless the deduction would result in a change to the depletion rate of 20 percent or greater, in which case a gain or loss is recorded.
EnCana expects to adopt the IFRS 1 exemption, which allows the Company to deem its January 1, 2010 IFRS upstream asset costs to be equal to its Canadian GAAP historical upstream net book value. On January 1, 2010, the IFRS exploration and evaluation costs will be equal to the Canadian GAAP unproved properties balance and the IFRS development costs will be equal to the full cost pool balance. EnCana will allocate this upstream full cost pool over reserves to establish the area level depletion units.
Asset Retirement Obligation
Under Canadian GAAP, ARO is measured as the estimated fair value of the retirement and decommissioning expenditures expected to be incurred. Existing liabilities are not re-measured using current discount rates. Under IFRS, ARO is measured as the best estimate of the expenditure to be incurred and requires the use of current discount rates at each re-measurement date. Generally, the change in discount rates results in a balance being added to or deducted from PP&E.
As a result of EnCanas intended use of the IFRS 1 upstream assets exemption, the Company is required to revalue its January 1, 2010 ARO balance and recognize the adjustment in retained earnings.
Impairment
Under Canadian GAAP, EnCana is required to recognize an upstream impairment loss if the carrying amount exceeds the undiscounted cash flows from proved reserves for the country cost centre. If an impairment loss is to be recognized, it is then measured at the amount the carrying value exceeds the sum of the fair value of the proved and probable reserves and the costs of unproved properties.
Under IFRS, EnCana is required to recognize and measure an upstream impairment loss if the carrying value exceeds the recoverable amount for a cash-generating unit. Under IFRS, the recoverable amount is the higher of fair value less cost to sell and value in use. Impairment losses, other than goodwill, are reversed under IFRS when there is an increase in the recoverable amount. EnCana will group its upstream assets into cash-generating units based on the independence of cash inflows from other assets or other groups of assets.
Stock-Based Compensation
Share units issued under EnCanas stock-based compensation plans that are accounted for using the intrinsic value method under Canadian GAAP will be required to be fair valued under IFRS. The intrinsic value of a share unit is the amount by which EnCanas stock price exceeds the exercise price of a share unit. The fair value of a share unit is determined utilizing a model, such as the Black-Scholes-Merton model.
EnCana Corporation 2009 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
EnCana intends to use the IFRS 1 exemption under which share units that vest prior to January 1, 2010 are not required to be retrospectively restated.
Income Taxes
In transitioning to IFRS, the Companys future tax liability will be impacted by the tax effects resulting from the IFRS changes discussed above. EnCana continues to assess the impact that the IFRS income tax principles may have on the Company.
Other IFRS 1 Considerations
As permitted by IFRS 1, EnCanas foreign currency translation adjustment, currently the only balance in EnCanas Accumulated Other Comprehensive Income, will be deemed to be zero and the balance will be reclassified to retained earnings on January 1, 2010. Accordingly, retrospective restatement of foreign currency translation adjustments under IFRS principles will not be performed.
Business combinations and joint ventures entered into prior to January 1, 2010 will not be retrospectively restated using IFRS principles.
With respect to employee benefit plans, cumulative unamortized actuarial gains and losses are expected to be charged to retained earnings on January 1, 2010. As such, they will not be retrospectively recalculated using IFRS principles.
Other Recent Accounting Pronouncements
Business Combinations
As of January 1, 2011, EnCana will be required to adopt CICA Handbook Section 1582 Business Combinations, which replaces the previous business combinations standard. The standard requires assets and liabilities acquired in a business combination, contingent consideration and certain acquired contingencies to be measured at their fair values as of the date of acquisition. In addition, acquisition-related and restructuring costs are to be recognized separately from the business combination and included in the statement of earnings. The adoption of this standard will impact the accounting treatment of future business combinations.
Consolidated Financial Statements
As of January 1, 2011, EnCana will be required to adopt CICA Handbook Section 1601 Consolidated Financial Statements, which together with Section 1602 below, replace the former consolidated financial statements standard. Section 1601 establishes the requirements for the preparation of consolidated financial statements. The adoption of this standard should not have a material impact on EnCanas Consolidated Financial Statements.
Non-controlling Interests
As of January 1, 2011, EnCana will be required to adopt CICA Handbook Section 1602 Non-controlling Interests, which establishes the accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. The standard requires a non-controlling interest in a subsidiary to be classified as a separate component of equity. In addition, net earnings and components of other comprehensive income are attributed to both the parent and non-controlling interest. The adoption of this standard should not have a material impact on EnCanas Consolidated Financial Statements.
Critical Accounting Policies and Estimates
Management is required to make judgments, assumptions and estimates in the application of generally accepted accounting principles that have a significant impact on the financial results of the Company. A summary of EnCanas significant accounting policies can be found in Note 1 to the Consolidated Financial Statements. The following discussion outlines the accounting policies and practices involving the use of estimates that are critical to determining EnCanas financial results.
Full Cost Accounting and Oil and Gas Reserves
As previously described, EnCana follows full cost accounting for oil and gas activities. Reserves estimates can have a significant impact on earnings, as they are a key input to the Companys DD&A calculations and impairment tests. A downward revision in reserves estimate could result in a higher DD&A charge against net earnings. An impairment of upstream assets is recognized when the net capitalized costs exceed the undiscounted cash flows from proved reserves for a country cost centre. If an impairment loss is to be recognized, it is then measured at the amount the carrying value exceeds the sum of the fair value of the proved and probable reserves and the costs of unproved properties. A downward
EnCana Corporation 2009 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
revision in reserves estimates could result in the recognition of an impairment charged against retained earnings. As at December 31, 2009, EnCana has determined that no write-down to its upstream assets is required under Canadian GAAP.
All of EnCanas oil and gas reserves and resources are evaluated and reported on by independent qualified reserves evaluators. The estimation of reserves is a subjective process. Forecasts are based on engineering data, projected future rates of production, estimated commodity price forecasts and the timing of future expenditures, all of which are subject to numerous uncertainties and various interpretations. Reserves estimates can be revised upward or downward based on the results of future drilling, testing, production levels and economics of recovery based on cash flow forecasts. Contingent resources are not classified as reserves due to the absence of a commercial development plan that includes a firm intent to develop within a reasonable time frame. Estimated recovery for leases assigned contingent resources considers detailed reservoir and pilot studies, demonstrated commercial success of analogous commercial projects and drilling density.
Asset Retirement Obligations
Asset retirement obligations are legal obligations associated with the requirement to retire tangible long-lived assets such as producing well sites, offshore production platforms and natural gas processing plants. The fair value of estimated asset retirement obligations is recognized in the Consolidated Balance Sheet when incurred and a reasonable estimate of fair value can be made. The asset retirement cost is capitalized as part of the cost of the related long-lived asset. Changes in the estimated obligation resulting from revisions to estimated timing or amount of undiscounted cash flows are recognized as a change in the asset retirement obligation and the related asset retirement cost. Increases in the asset retirement obligation resulting from the passage of time are recorded as accretion of asset retirement obligation in the Consolidated Statement of Earnings.
The fair value settlement recorded for asset retirement obligations is estimated by discounting the expected future cash flows. The discounted cash flows are based on estimates of reserve lives, retirement costs, the weighted average credit-adjusted risk-free rate and future inflation rate. Actual expenditures incurred are charged against the accumulated obligation. The estimates outlined above will impact earnings through accretion on the asset retirement liability in addition to the depletion of the asset retirement cost included in PP&E.
Goodwill
Goodwill, which represents the excess of purchase price over fair value of net assets acquired, is assessed by EnCana for impairment at least annually. To assess impairment, the fair value of each reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, then a second test is performed to determine the amount of the impairment. The amount of the impairment is determined by deducting the fair value of the reporting units assets and liabilities from the fair value of the reporting unit to determine the implied fair value of goodwill and comparing that amount to the book value of the reporting units goodwill. Any excess of the book value of goodwill over the implied fair value of goodwill is the impairment amount.
The fair value used in the impairment test is based on estimates of discounted future cash flows which involves assumptions on commodity prices, oil and gas reserves, future expenses and discount rates. EnCana has assessed its goodwill for impairment as at December 31, 2009 and has determined that no write-down is required.
Income Taxes
EnCana follows the liability method of accounting for income taxes. Under this method, future income taxes are estimated and recorded for the effect of any difference between the accounting and income tax basis of an asset or liability, using the substantively enacted income tax rates. Accumulated future income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with the adjustment being recognized in net earnings in the period that the change occurs.
Tax interpretations, regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change. As such, income taxes are subject to measurement uncertainty and the interpretations can impact net earnings through the income tax expense and the future income tax assets and liabilities.
Derivative Financial Instruments
As described in the Risk Management section of this MD&A, derivative financial instruments are used by EnCana to manage its exposure to market risks relating to commodity prices, foreign currency exchange rates and interest rates. The Companys policy is to not use derivative financial instruments for speculative purposes.
Derivative instruments that do not qualify or are not designated as hedges are recorded at fair value. Instruments are recorded in the Consolidated Balance Sheet as either an asset or liability with changes in fair value recognized in net earnings. Realized gains or losses related to natural gas and crude oil prices are recognized in natural gas and crude oil revenues as the related sales occur. Unrealized gains and losses are recognized in revenues at the end of each respective
EnCana Corporation 2009 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
reporting period. The estimate of fair value of all derivative instruments is based on quoted market prices or, in their absence, third-party market indications and forecasts. The estimated fair value of financial assets and liabilities is subject to measurement uncertainty.
In 2007 through to 2009, the Company elected not to designate any of its price risk management activities as accounting hedges and, accordingly, fair valued all derivative instruments with the change in fair value recorded in net earnings.
Pro Forma Information
The objective of EnCanas pro forma information is to illustrate the impact of the Split Transaction on the Companys results by adjusting the historical information to assume the Split Transaction occurred on January 1, 2008. EnCanas pro forma results exclude the results of operations from assets transferred to Cenovus as part of the Split Transaction and reflect expected changes to EnCanas historical results that would arise from the Split Transaction, including income tax, DD&A and transaction costs.
EnCanas pro forma financial information is derived from EnCanas pro forma financial statements, which have been prepared using guidance issued by the U.S. SEC and the Canadian Securities Administrators.
Reconciliations of Non-GAAP Measures
Pro Forma
Summary of Pro Forma Cash Flow
($ millions) |
|
2009 |
|
2008 |
|
|||||||
Pro Forma Cash From Operating Activities |
|
$ |
5,041 |
|
$ |
6,224 |
|
|||||
(Add back) deduct: |
|
|
|
|
|
|||||||
Net change in other assets and liabilities |
|
38 |
|
(173) |
|
|||||||
Net change in non-cash working capital from Continuing Operations |
|
(18) |
|
43 |
|
|||||||
Pro Forma Cash Flow |
|
$ |
5,021 |
|
$ |
6,354 |
|
|||||
|
||||||||||||
|
||||||||||||
Reconciliation of Consolidated Cash Flow to Pro Forma Cash Flow |
||||||||||||
|
||||||||||||
($ millions) |
|
2009 |
|
2008 |
|
|||||||
Cash Flow |
|
$ |
6,779 |
|
$ |
9,386 |
|
|||||
Less: Cenovus Carve-out(1) |
|
2,232 |
|
3,088 |
|
|||||||
Add/(Deduct) Pro Forma adjustments |
|
474 |
|
56 |
|
|||||||
Pro Forma Cash Flow |
|
5,021 |
|
6,354 |
|
|||||||
Per share amounts |
|
|
|
|
|
|||||||
Cash Flow |
- Basic |
|
9.03 |
|
12.51 |
|
||||||
|
- Diluted |
|
9.02 |
|
12.48 |
|
||||||
|
|
|
|
|
|
|
||||||
Pro Forma Cash Flow |
- Basic |
|
6.69 |
|
8.47 |
|
||||||
|
- Diluted |
|
6.68 |
|
8.45 |
|
||||||
|
|
|
|
|
|
|
||||||
(1) |
Cenovus Energy was spun-off on November 30, 2009. As a result, year-to-date information is for the 11 months ended November 30, 2009. |
|
||||||||||
EnCana Corporation 2009 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Summary of Pro Forma Operating Earnings
|
|
2009 |
|
2008 |
|
|||||||||
($ millions, except per share amounts) |
|
|
|
Per share(4) |
|
|
|
Per share(4) |
|
|||||
Pro Forma Net Earnings, as reported |
|
$ |
749 |
|
$ |
1.00 |
|
$ |
3,405 |
|
$ |
4.53 |
|
|
Add back (losses) and deduct gains: |
|
|
|
|
|
|
|
|
|
|||||
Unrealized mark-to-market accounting gain (loss), after-tax |
|
(1,352) |
|
(1.80) |
|
1,299 |
|
1.73 |
|
|||||
Non-operating foreign exchange gain (loss), after-tax (2) |
|
334 |
|
0.45 |
|
(598) |
|
(0.80) |
|
|||||
Gain (loss) on discontinuance, after-tax (3) |
|
- |
|
- |
|
99 |
|
0.13 |
|
|||||
Pro Forma Operating Earnings (1) |
|
$ |
1,767 |
|
$ |
2.35 |
|
$ |
2,605 |
|
$ |
3.47 |
|
|
(1) Operating Earnings is a non-GAAP measure defined as Net Earnings excluding the after-tax gains (losses) on discontinuance, after-tax effect of unrealized mark-to-market accounting gains (losses) on derivative instruments, after-tax gains (losses) on translation of U.S. dollar denominated debt issued from Canada and the partnership contribution receivable, after-tax foreign exchange gains (losses) on settlement of intercompany transactions, future income tax on foreign exchange recognized for tax purposes only related to U.S. dollar intercompany debt and the effect of changes in statutory income tax rates. The Companys calculation of Operating Earnings excludes foreign exchange effects on settlement of significant intercompany transactions to provide information that is more comparable between periods.
(2) After-tax unrealized foreign exchange gains (losses) on translation of U.S. dollar denominated debt issued from Canada, after-tax realized foreign exchange gains (losses) on settlement of intercompany transactions and future income tax on foreign exchange recognized for tax purposes only related to U.S. dollar intercompany debt . The majority of U.S. dollar debt issued from Canada has maturity dates in excess of five years.
(3) For 2008, gain on sale of interests in Brazil.
(4) Per Common Share diluted.
Reconciliation of Consolidated Net Earnings to Pro Forma Net Earnings
($ millions) |
|
|
2009 |
|
2008 |
|
||
Net Earnings |
|
|
$ |
1,862 |
|
$ |
5,944 |
|
Less: Cenovus Carve-out(1) |
|
|
609 |
|
2,368 |
|
||
Add/(Deduct) Pro Forma adjustments |
|
|
(504) |
|
(171) |
|
||
Pro Forma Net Earnings |
|
|
749 |
|
3,405 |
|
||
Per share amounts |
|
|
|
|
|
|
||
Net Earnings |
- Basic |
|
2.48 |
|
7.92 |
|
||
|
- Diluted |
|
2.48 |
|
7.91 |
|
||
|
|
|
|
|
|
|
||
Pro Forma Net Earnings |
- Basic |
|
1.00 |
|
4.54 |
|
||
|
- Diluted |
|
1.00 |
|
4.53 |
|
||
(1) Cenovus Energy was spun-off on November 30, 2009. As a result, year-to-date information is for the 11 months ended November 30, 2009.
Reconciliation of Consolidated Operating Earnings to Pro Forma Operating Earnings
($ millions) |
|
|
2009 |
|
2008 |
|
||
Operating Earnings |
|
|
$ |
3,495 |
|
$ |
4,405 |
|
Less: Cenovus Carve-out(1) |
|
|
1,224 |
|
1,629 |
|
||
Add/(Deduct) Pro Forma adjustments |
|
|
(504) |
|
(171) |
|
||
Pro Forma Operating Earnings |
|
|
1,767 |
|
2,605 |
|
||
Per share amounts |
|
|
|
|
|
|
||
Operating Earnings |
- Diluted |
|
4.65 |
|
5.86 |
|
||
|
|
|
|
|
|
|
||
Pro Forma Operating Earnings |
- Diluted |
|
2.35 |
|
3.47 |
|
||
(1) Cenovus Energy was spun-off on November 30, 2009. As a result, year-to-date information is for the 11 months ended November 30, 2009.
EnCana Corporation 2009 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Consolidated
Summary of Cash Flow
($ millions) |
|
2009 |
|
2008 |
|
2007 |
|
|||
Cash From Operating Activities |
|
$ |
7,873 |
|
$ |
8,986 |
|
$ |
8,262 |
|
(Add back) deduct: |
|
|
|
|
|
|
|
|||
Net change in other assets and liabilities |
|
23 |
|
(257) |
|
(10) |
|
|||
Net change in non-cash working capital from Continuing Operations |
|
(29) |
|
(1,353) |
|
(108) |
|
|||
Net change in non-cash working capital from Discontinued Operations |
|
1,100 |
|
1,210 |
|
(73) |
|
|||
Cash Flow |
|
$ |
6,779 |
|
$ |
9,386 |
|
$ |
8,453 |
|
Summary of Operating Earnings
|
|
2009 |
|
2008 |
|
2007 |
|
||||||||||||
($ millions, except per share amounts) |
|
Per share(4) |
|
Per share(4) |
|
Per share(4) |
|
||||||||||||
Net Earnings, as reported |
|
$ |
1,862 |
|
$ |
2.48 |
|
$ |
5,944 |
|
$ |
7.91 |
|
$ |
3,959 |
|
$ |
5.18 |
|
Add back (losses) and deduct gains: |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Unrealized mark-to-market accounting gain (loss), after-tax |
|
(1,792) |
|
(2.38) |
|
1,818 |
|
2.42 |
|
(811) |
|
(1.06) |
|
||||||
Non-operating foreign exchange gain (loss), after-tax (2) |
|
159 |
|
0.21 |
|
(378) |
|
(0.50) |
|
217 |
|
0.28 |
|
||||||
Gain (loss) on discontinuance, after-tax (3) |
|
- |
|
- |
|
99 |
|
0.13 |
|
152 |
|
0.20 |
|
||||||
Future tax recovery due to tax rate reductions |
|
- |
|
- |
|
- |
|
- |
|
301 |
|
0.40 |
|
||||||
Operating Earnings (1) |
|
$ |
3,495 |
|
$ |
4.65 |
|
$ |
4,405 |
|
$ |
5.86 |
|
$ |
4,100 |
|
$ |
5.36 |
|
(1) |
Operating Earnings is a non-GAAP measure defined as Net Earnings excluding the after-tax gains (losses) on discontinuance, after-tax effect of unrealized mark-to-market accounting gains (losses) on derivative instruments, after-tax gains (losses) on translation of U.S. dollar denominated debt issued from Canada and the partnership contribution receivable, after-tax foreign exchange gains (losses) on settlement of intercompany transactions, future income tax on foreign exchange recognized for tax purposes only related to U.S. dollar intercompany debt and the effect of changes in statutory income tax rates. The Companys calculation of Operating Earnings excludes foreign exchange effects on settlement of significant intercompany transactions to provide information that is more comparable between periods. |
(2) |
After-tax unrealized foreign exchange gains (losses) on translation of U.S. dollar denominated debt issued from Canada and the partnership contribution receivable, after-tax realized foreign exchange gains (losses) on settlement of intercompany transactions and future income tax on foreign exchange recognized for tax purposes only related to U.S. dollar intercompany debt The majority of U.S. dollar debt issued from Canada has maturity dates in excess of five years. |
(3) |
For 2008, gain on sale of interests in Brazil. For 2007, gain on sale of Australia assets and interests in Chad as well as final adjustments on the NGL processing business sold in 2005. |
(4) |
Per Common Share diluted. |
Advisory
Forward-Looking Statements
In the interest of providing EnCana shareholders and potential investors with information regarding the Company and its subsidiaries, including Managements assessment of EnCanas and its subsidiaries future plans and operations, certain statements contained in this document constitute forward-looking statements or information (collectively referred to herein as forward-looking statements) within the meaning of the safe harbour provisions of applicable securities legislation. Forward-looking statements are typically identified by words such as anticipate, believe, expect, plan, intend, forecast, target, project or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking statements in this document include, but are not limited to, statements with respect to: projected natural gas and oil production levels for 2010; projections relating to the adequacy of the Companys provision for taxes; the expected impact of the Alberta Royalty Framework and Transitional Royalty Program; projections with respect to natural gas production from unconventional resource plays; projections relating to the volatility of natural gas prices in 2010 and beyond and the reasons therefor; the Companys projected capital investment levels for 2010, the flexibility of capital spending plans and the source of funding therefor; the effect of the Companys risk management program, including the impact of derivative financial instruments; the impact of the changes and proposed changes in laws and regulations, including greenhouse gas, carbon and climate change initiatives on the Companys operations and operating costs; projections that the Companys Bankers Acceptances and Commercial Paper Program will continue to be fully supported by committed credit facilities and term loan facilities; the Companys continued compliance with financial covenants under its credit facilities; the Companys ability to pay its creditors, suppliers, commitments and fund its 2010 capital program and pay dividends to shareholders; the impact of the current business market conditions, including the recent economic recession and financial market turmoil on the Companys operations and expected results; the effect of the Companys risk mitigation policies, systems, processes and insurance program; the Companys expectations for future Debt to Capitalization and Debt to Adjusted
EnCana Corporation 2009 Annual Report |
|
Managements Discussion and Analysis (prepared in US$) |
EBITDA ratios; the expected impact and timing of various accounting pronouncements, rule changes and standards, including IFRS, on the Company and its Consolidated Financial Statements; and projections that natural gas represents an abundant, secure, long-term supply of energy to meet North American needs. 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 Companys actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. These risks and uncertainties include, among other things: volatility of and assumptions regarding oil and gas prices; assumptions based upon EnCanas current guidance; fluctuations in currency and interest rates; product supply and demand; market competition; risks inherent in the Companys and its subsidiaries 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; the Companys and its subsidiaries ability to replace and expand gas reserves; marketing margins; potential disruption or unexpected technical difficulties in developing new facilities; potential failure of new products to achieve acceptance in the market; unexpected cost increases or technical difficulties in constructing or modifying processing facilities; risks associated with technology and the application thereof to the business of the Company; the Companys ability to generate sufficient cash flow from operations to meet its current and future obligations; the Companys ability to access external sources of debt and equity capital; the timing and the costs of well and pipeline construction; the Companys and its subsidiaries ability to secure adequate product transportation; changes in royalty, tax, environmental, greenhouse gas, carbon accounting and other laws or regulations or the interpretations of such laws or regulations; political and economic conditions in the countries in which the Company and its subsidiaries operate; the risk of war, hostilities, civil insurrection and instability affecting countries in which the Company and its subsidiaries operate and terrorist threats; risks associated with existing and potential future lawsuits and regulatory actions made against the Company and its subsidiaries; and other risks and uncertainties described from time to time in the reports and filings made with securities regulatory authorities by EnCana. Although EnCana believes that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned that the foregoing list of important factors is not exhaustive. Furthermore, the forward-looking statements contained in this document are made as of the date of this document, 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 document are expressly qualified by this cautionary statement.
Forward-looking information respecting anticipated 2010 cash flow, operating cash flow and pre-tax cash flow for EnCana is based upon achieving average production of oil and gas for 2010 of approximately 3.2 to 3.3 billion cubic feet equivalent (Bcfe) per day (Bcfe/d), forward curve estimates for commodity prices and an estimated U.S./Canadian dollar foreign exchange rate of $0.85 to $0.96 and an average number of outstanding shares for EnCana of approximately 750 million. Assumptions relating to forward-looking statements generally include EnCanas current expectations and projections made by the Company in light of, and generally consistent with, its historical experience and its perception of historical trends, as well as expectations regarding rates of advancement and innovation, generally consistent with and informed by its past experience, all of which are subject to the risk factors identified elsewhere in this document.
EnCana is required to disclose events and circumstances that occurred during the period to which this MD&A relates that are reasonably likely to cause actual results to differ materially from material forward-looking statements for a period that is not yet complete that EnCana has previously disclosed to the public and the expected differences thereto. Such disclosure can be found in EnCanas news release dated February 11, 2010, which is available on EnCanas website at www.encana.com and on SEDAR at www.sedar.com.
Oil and Gas Information
EnCanas 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 that 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 NI 51-101. The reserves quantities disclosed by EnCana 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 EnCanas Annual Information Form.
EnCana Corporation 2009 Annual Report |
|
Managements Discussion and Analysis (prepared in US$) |
Reserves Reporting Protocols
Under the amended SEC rules, EnCanas 2009 proved reserves 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. For 2009, this resulted in a Henry Hub natural gas price of $3.87 per MMbtu, compared to a December 31st single-day price of $5.71 per MMbtu for 2008 reporting purposes. Because EnCana does not use prices derived for SEC reporting purposes in the day-to-day operation of its business or for planning purposes, it has highlighted 2009 reserves information in this document as before SEC price revisions attributable to the changes in natural gas pricing assumptions, which EnCana believes is a better reflection of its annual reserves additions performance. For all before SEC price revisions reserves estimates highlighted in this document, EnCana has used Henry Hub forecast prices of $5.50 per MMbtu for 2010 and $6.50 per MMbtu for 2011 and beyond. EnCanas 2009 net proved reserves information as defined under SEC disclosure protocols will be disclosed in the Companys Annual Information Form later this month. This disclosure will reflect the SEC average price and changes due to the Companys Split Transaction.
Natural Gas, Crude Oil and NGLs Conversions
In this document, certain crude oil and NGLs 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), thousands of BOE (MBOE) or millions of BOE (MMBOE) on the same basis. MMcfe, Mcfe, BOE, MBOE and MMBOE 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 necessarily represent value equivalency at the well head.
Resource Play
Resource play is a term used by EnCana to describe an accumulation of hydrocarbons known to exist over a large areal expanse and/or thick vertical section, which when compared to a conventional play typically has a lower geological and/or commercial development risk and lower average decline rate.
Currency, Pro Forma Information, Non-GAAP Measures and References to EnCana
All information included in this document and the Consolidated Financial Statements and comparative information is shown on a U.S. dollar, after royalties basis unless otherwise noted.
Pro Forma Information
On November 30, 2009, EnCana completed a major corporate reorganization a Split Transaction that resulted in the Companys transition into a pure-play natural gas company and the spin off of its Integrated Oil and Canadian Plains assets into Cenovus Energy Inc., an independent, publicly-traded energy company. EnCanas consolidated results include the financial and operating performance of the Cenovus assets for the first 11 months of 2009 and are reflected in EnCanas consolidated fourth quarter and 2009 financial statements. To give investors a clear understanding of post-split EnCana, fourth quarter and 2009 financial and operating results in this document highlight EnCanas results on a pro forma basis, which reflect the Company as if the Split Transaction had been completed for all of 2009 and the previous years presented. In this pro forma presentation, the results associated with the assets and operations transferred to Cenovus are eliminated from EnCanas consolidated results, and adjustments specific to the Split Transaction are reflected.
Non-GAAP Measures
Certain measures in this document do not have any standardized meaning as prescribed by Canadian GAAP such as Cash Flow, Cash Flow per share diluted, Free Cash Flow, Operating Earnings, Operating Earnings per share diluted, Adjusted EBITDA, Debt, Net Debt and Capitalization and, therefore, are considered non-GAAP measures. Therefore, these measures may not be comparable to similar measures presented by other issuers. These measures have been described and presented in this document in order to provide shareholders and potential investors with additional information regarding the Companys liquidity and its ability to generate funds to finance its operations. Managements use of these measures has been disclosed further in this document as these measures are discussed and presented.
References to EnCana
For convenience, references in this document to EnCana, the Company, we, us, our and its may, where applicable, refer only to or include any relevant direct and indirect subsidiary corporations and partnerships (Subsidiaries) of EnCana Corporation, and the assets, activities and initiatives of such Subsidiaries.
Additional Information
Further information regarding EnCana Corporation, including its Annual Information Form, can be accessed under the Companys public filings found at www.sedar.com and on the Companys website at www.encana.com.
EnCana Corporation 2009 Annual Report |
|
Managements Discussion and Analysis (prepared in US$) |
EnCana Corporation
Consolidated Financial Statements
For the Year Ended December 31, 2009
(Prepared in U.S. Dollars)
|
Management Report
Managements Responsibility for Consolidated Financial Statements
The accompanying Consolidated Financial Statements of EnCana Corporation (the Company) are the responsibility of Management. The Consolidated Financial Statements have been prepared by Management in United States dollars in accordance with Canadian generally accepted accounting principles and include certain estimates that reflect Managements best judgments. Financial information contained throughout the annual report is consistent with these financial statements.
The Companys Board of Directors has approved the information contained in the Consolidated Financial Statements. The Board of Directors fulfills its responsibility regarding the financial statements mainly through its Audit Committee, which has a written mandate that complies with the current requirements of Canadian securities legislation and the United States Sarbanes-Oxley Act of 2002 and voluntarily complies, in principle, with the Audit Committee guidelines of the New York Stock Exchange. The Audit Committee meets at least on a quarterly basis.
Managements Assessment of Internal Control over Financial Reporting
Management is also responsible for establishing and maintaining adequate internal control over the Companys financial reporting. The internal control system was designed to provide reasonable assurance to the Companys Management regarding the preparation and presentation of the Consolidated Financial Statements.
Internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management has assessed the design and effectiveness of the Companys internal control over financial reporting as at December 31, 2009. In making its assessment, Management has used the Committee of Sponsoring Organizations of the Treadway Commission (COSO) framework in Internal Control Integrated Framework to evaluate the effectiveness of the Companys internal control over financial reporting. Based on our evaluation, Management has concluded that the Companys internal control over financial reporting was effectively designed and operating effectively as at that date.
PricewaterhouseCoopers LLP, an independent firm of chartered accountants, was appointed by a vote of shareholders at the Companys last annual meeting to audit and provide independent opinions on both the Consolidated Financial Statements and the Companys internal control over financial reporting as at December 31, 2009, as stated in their Auditors Report. PricewaterhouseCoopers LLP has provided such opinions.
/s/ Randall K. Eresman |
/s/ Sherri A. Brillon |
Randall K. Eresman |
Sherri A. Brillon |
President & |
Executive Vice-President & |
Chief Executive Officer |
Chief Financial Officer |
|
|
February 17, 2010 |
|
EnCana Corporation |
|
|
Auditors Report
To the Shareholders of EnCana Corporation
We have completed integrated audits of EnCana Corporations 2009, 2008 and 2007 consolidated financial statements and of its internal control over financial reporting as at December 31, 2009. Our opinions, based on our audits, are presented below.
Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of EnCana Corporation as at December 31, 2009 and December 31, 2008, and the related consolidated statements of earnings, shareholders equity, comprehensive income and cash flows for each of the years in the three year period ended December 31, 2009. These financial statements are the responsibility of the Companys management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits of the Companys financial statements in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. A financial statement audit also includes assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as at December 31, 2009 and December 31, 2008 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2009 in accordance with Canadian generally accepted accounting principles.
Internal Control Over Financial Reporting
We have also audited EnCana Corporations internal control over financial reporting as at December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Companys management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Managements Assessment of Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Companys internal control over financial reporting based on our audit.
We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A companys internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with
EnCana Corporation |
|
|
generally accepted accounting principles. A companys internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the companys assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as at December 31, 2009 based on criteria established in Internal Control - Integrated Framework issued by the COSO.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Chartered Accountants
Calgary, Alberta
Canada
February 17, 2010
EnCana Corporation |
|
|
Consolidated Statement of Earnings
For the years ended December 31 (US$ millions, except per share amounts) |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Revenues, Net of Royalties |
|
(Note 4) |
|
$ |
11,114 |
|
|
$ |
21,053 |
|
|
$ |
14,385 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Expenses |
|
(Note 4) |
|
|
|
|
|
|
|
|
|
|||
Production and mineral taxes |
|
|
|
171 |
|
|
478 |
|
|
291 |
|
|||
Transportation and selling |
|
|
|
1,280 |
|
|
1,704 |
|
|
1,264 |
|
|||
Operating |
|
|
|
1,627 |
|
|
1,983 |
|
|
1,850 |
|
|||
Purchased product |
|
|
|
1,460 |
|
|
2,426 |
|
|
2,770 |
|
|||
Depreciation, depletion and amortization |
|
|
|
3,704 |
|
|
4,035 |
|
|
3,657 |
|
|||
Administrative |
|
|
|
477 |
|
|
447 |
|
|
356 |
|
|||
Interest, net |
|
(Note 8) |
|
405 |
|
|
402 |
|
|
234 |
|
|||
Accretion of asset retirement obligation |
|
(Note 16) |
|
71 |
|
|
77 |
|
|
63 |
|
|||
Foreign exchange (gain) loss, net |
|
(Note 9) |
|
(22 |
) |
|
423 |
|
|
(164 |
) |
|||
(Gain) loss on divestitures |
|
(Note 7) |
|
2 |
|
|
(141 |
) |
|
(65 |
) |
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
|
|
|
|
9,175 |
|
|
11,834 |
|
|
10,256 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Net Earnings Before Income Tax |
|
|
|
1,939 |
|
|
9,219 |
|
|
4,129 |
|
|||
Income tax expense |
|
(Note 10) |
|
109 |
|
|
2,720 |
|
|
682 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Net Earnings From Continuing Operations |
|
|
|
1,830 |
|
|
6,499 |
|
|
3,447 |
|
|||
Net Earnings (Loss) From Discontinued Operations |
|
(Note 6) |
|
32 |
|
|
(555 |
) |
|
512 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Net Earnings |
|
|
|
$ |
1,862 |
|
|
$ |
5,944 |
|
|
$ |
3,959 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Net Earnings From Continuing Operations per Common Share |
|
(Note 17) |
|
|
|
|
|
|
|
|
|
|||
Basic |
|
|
|
$ |
2.44 |
|
|
$ |
8.66 |
|
|
$ |
4.55 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
|
|
$ |
2.44 |
|
|
$ |
8.64 |
|
|
$ |
4.51 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Net Earnings per Common Share |
|
(Note 17) |
|
|
|
|
|
|
|
|
|
|||
Basic |
|
|
|
$ |
2.48 |
|
|
$ |
7.92 |
|
|
$ |
5.23 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
|
|
$ |
2.48 |
|
|
$ |
7.91 |
|
|
$ |
5.18 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated Statement of Comprehensive Income |
|
|||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31 (US$ millions) |
|
|
|
|
2009 |
|
|
|
2008 |
|
|
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings |
|
|
|
$ |
1,862 |
|
|
$ |
5,944 |
|
|
$ |
3,959 |
|
Other Comprehensive Income, Net of Tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign Currency Translation Adjustment |
|
|
|
|
2,018 |
|
|
|
(2,230 |
) |
|
|
1,688 |
|
Comprehensive Income |
|
|
|
$ |
3,880 |
|
|
$ |
3,714 |
|
|
$ |
5,647 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying Notes to Consolidated Financial Statements
EnCana Corporation |
|
Consolidated Financial Statements (prepared in US$) |
Consolidated Balance Sheet
As at December 31 (US$ millions) |
|
|
|
2009 |
|
|
2008 |
|
||
|
|
|
|
|
|
|
|
|
||
Assets |
|
|
|
|
|
|
|
|
||
Current Assets |
|
|
|
|
|
|
|
|
||
Cash and cash equivalents |
|
|
|
$ |
4,275 |
|
|
$ |
354 |
|
Accounts receivable and accrued revenues |
|
|
|
1,180 |
|
|
1,436 |
|
||
Current portion of partnership contribution receivable |
|
(Notes 5, 11) |
|
- |
|
|
313 |
|
||
Risk management |
|
(Note 20) |
|
328 |
|
|
2,818 |
|
||
Inventories |
|
(Note 12) |
|
12 |
|
|
184 |
|
||
Assets of discontinued operations |
|
(Note 6) |
|
- |
|
|
497 |
|
||
|
|
|
|
5,795 |
|
|
5,602 |
|
||
|
|
|
|
|
|
|
|
|
||
Property, Plant and Equipment, net |
|
(Notes 4, 13) |
|
26,173 |
|
|
31,910 |
|
||
Investments and Other Assets |
|
(Note 14) |
|
164 |
|
|
72 |
|
||
Partnership Contribution Receivable |
|
(Notes 5, 11) |
|
- |
|
|
2,834 |
|
||
Risk Management |
|
(Note 20) |
|
32 |
|
|
234 |
|
||
Goodwill |
|
(Note 4) |
|
1,663 |
|
|
2,426 |
|
||
Assets of Discontinued Operations |
|
(Note 6) |
|
- |
|
|
4,169 |
|
||
|
|
(Note 4) |
|
$ |
33,827 |
|
|
$ |
47,247 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
Liabilities and Shareholders Equity |
|
|
|
|
|
|
|
|
||
Current Liabilities |
|
|
|
|
|
|
|
|
||
Accounts payable and accrued liabilities |
|
|
|
$ |
2,143 |
|
|
$ |
2,448 |
|
Income tax payable |
|
|
|
1,776 |
|
|
500 |
|
||
Risk management |
|
(Note 20) |
|
126 |
|
|
43 |
|
||
Current portion of long-term debt |
|
(Note 15) |
|
200 |
|
|
250 |
|
||
Liabilities of discontinued operations |
|
(Note 6) |
|
- |
|
|
653 |
|
||
|
|
|
|
4,245 |
|
|
3,894 |
|
||
|
|
|
|
|
|
|
|
|
||
Long-Term Debt |
|
(Note 15) |
|
7,568 |
|
|
8,755 |
|
||
Other Liabilities |
|
(Note 4) |
|
1,185 |
|
|
576 |
|
||
Risk Management |
|
(Note 20) |
|
42 |
|
|
7 |
|
||
Asset Retirement Obligation |
|
(Note 16) |
|
787 |
|
|
1,230 |
|
||
Future Income Taxes |
|
(Note 10) |
|
3,386 |
|
|
6,917 |
|
||
Liabilities of Discontinued Operations |
|
(Note 6) |
|
- |
|
|
2,894 |
|
||
|
|
|
|
17,213 |
|
|
24,273 |
|
||
Commitments and Contingencies |
|
(Note 22) |
|
|
|
|
|
|
||
|
|
|
|
|
|
|
|
|
||
Shareholders Equity |
|
|
|
|
|
|
|
|
||
Share capital |
|
(Note 17) |
|
2,360 |
|
|
4,557 |
|
||
Paid in surplus |
|
(Note 17) |
|
6 |
|
|
- |
|
||
Retained earnings |
|
|
|
13,493 |
|
|
17,584 |
|
||
Accumulated other comprehensive income |
|
|
|
755 |
|
|
833 |
|
||
Total Shareholders Equity |
|
|
|
16,614 |
|
|
22,974 |
|
||
|
|
|
|
$ |
33,827 |
|
|
$ |
47,247 |
|
See accompanying Notes to Consolidated Financial Statements
Approved by the Board
/s/ David P. OBrien |
|
/s/ Jane L. Peverett |
David P. OBrien |
|
Jane L. Peverett |
Director |
|
Director |
EnCana Corporation |
|
Consolidated Financial Statements (prepared in US$) |
Consolidated Statement of Shareholders Equity
For the years ended December 31 (US$ millions) |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Share Capital |
|
|
|
|
|
|
|
|
|
|
|
|||
Balance, Beginning of Year |
|
|
|
$ |
4,557 |
|
|
$ |
4,479 |
|
|
$ |
4,587 |
|
Common Shares Issued under Option Plans |
|
(Note 17) |
|
5 |
|
|
80 |
|
|
176 |
|
|||
Common Shares Issued from PSU Trust |
|
(Note 17) |
|
19 |
|
|
- |
|
|
- |
|
|||
Stock-Based Compensation |
|
(Note 17) |
|
1 |
|
|
11 |
|
|
17 |
|
|||
Common Shares Purchased |
|
(Note 17) |
|
- |
|
|
(13 |
) |
|
(301 |
) |
|||
Common Shares Cancelled |
|
(Note 3) |
|
(4,582 |
) |
|
- |
|
|
- |
|
|||
New EnCana Common Shares Issued |
|
(Note 3) |
|
2,360 |
|
|
- |
|
|
- |
|
|||
EnCana Special Shares Issued |
|
(Note 3) |
|
2,222 |
|
|
- |
|
|
- |
|
|||
EnCana Special Shares Cancelled |
|
(Note 3) |
|
(2,222 |
) |
|
- |
|
|
- |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Balance, End of Year |
|
|
|
$ |
2,360 |
|
|
$ |
4,557 |
|
|
$ |
4,479 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Paid in Surplus |
|
|
|
|
|
|
|
|
|
|
|
|||
Balance, Beginning of Year |
|
|
|
$ |
- |
|
|
$ |
80 |
|
|
$ |
160 |
|
Common Shares Issued from PSU Trust |
|
(Note 17) |
|
6 |
|
|
- |
|
|
- |
|
|||
Stock-Based Compensation |
|
|
|
- |
|
|
1 |
|
|
43 |
|
|||
Common Shares Distributed under Incentive Compensation Plans |
|
|
|
- |
|
|
(81 |
) |
|
(123 |
) |
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Balance, End of Year |
|
|
|
$ |
6 |
|
|
$ |
- |
|
|
$ |
80 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Retained Earnings |
|
|
|
|
|
|
|
|
|
|
|
|||
Balance, Beginning of Year |
|
|
|
$ |
17,584 |
|
|
$ |
13,082 |
|
|
$ |
11,344 |
|
Net Earnings |
|
|
|
1,862 |
|
|
5,944 |
|
|
3,959 |
|
|||
Dividends on Common Shares |
|
|
|
(1,051 |
) |
|
(1,199 |
) |
|
(603 |
) |
|||
Charges for Normal Course Issuer Bid |
|
(Note 17) |
|
- |
|
|
(243 |
) |
|
(1,618 |
) |
|||
Net Distribution to Cenovus Energy |
|
(Note 3) |
|
(4,902 |
) |
|
- |
|
|
- |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Balance, End of Year |
|
|
|
$ |
13,493 |
|
|
$ |
17,584 |
|
|
$ |
13,082 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Accumulated Other Comprehensive Income |
|
|
|
|
|
|
|
|
|
|
|
|||
Balance, Beginning of Year |
|
|
|
$ |
833 |
|
|
$ |
3,063 |
|
|
$ |
1,375 |
|
Foreign Currency Translation |
|
|
|
2,018 |
|
|
(2,230 |
) |
|
1,688 |
|
|||
Transferred to Cenovus Energy |
|
(Note 3) |
|
(2,096 |
) |
|
- |
|
|
- |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Balance, End of Year |
|
|
|
$ |
755 |
|
|
$ |
833 |
|
|
$ |
3,063 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Total Shareholders Equity |
|
|
|
$ |
16,614 |
|
|
$ |
22,974 |
|
|
$ |
20,704 |
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying Notes to Consolidated Financial Statements
EnCana Corporation |
|
Consolidated Financial Statements (prepared in US$) |
Consolidated Statement of Cash Flows
For the years ended December 31 (US$ millions) |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|||
Net earnings from continuing operations |
|
|
|
$ |
1,830 |
|
|
$ |
6,499 |
|
|
$ |
3,447 |
|
Depreciation, depletion and amortization |
|
|
|
3,704 |
|
|
4,035 |
|
|
3,657 |
|
|||
Future income taxes |
|
(Note 10) |
|
(1,799 |
) |
|
1,723 |
|
|
(698 |
) |
|||
Cash tax on sale of assets |
|
(Note 10) |
|
- |
|
|
25 |
|
|
- |
|
|||
Unrealized (gain) loss on risk management |
|
(Note 20) |
|
2,680 |
|
|
(2,729 |
) |
|
1,235 |
|
|||
Unrealized foreign exchange (gain) loss |
|
|
|
(231 |
) |
|
417 |
|
|
41 |
|
|||
Accretion of asset retirement obligation |
|
(Note 16) |
|
71 |
|
|
77 |
|
|
63 |
|
|||
(Gain) loss on divestitures |
|
(Note 7) |
|
2 |
|
|
(141 |
) |
|
(65 |
) |
|||
Other |
|
|
|
373 |
|
|
(79 |
) |
|
95 |
|
|||
Cash flow from discontinued operations |
|
|
|
149 |
|
|
(441 |
) |
|
678 |
|
|||
Net change in other assets and liabilities |
|
|
|
23 |
|
|
(257 |
) |
|
(10 |
) |
|||
Net change in non-cash working capital from continuing operations |
|
(Note 21) |
|
(29 |
) |
|
(1,353 |
) |
|
(108 |
) |
|||
Net change in non-cash working capital from discontinued operations |
|
|
|
1,100 |
|
|
1,210 |
|
|
(73 |
) |
|||
Cash From Operating Activities |
|
|
|
7,873 |
|
|
8,986 |
|
|
8,262 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|||
Capital expenditures |
|
(Note 4) |
|
(4,864 |
) |
|
(7,997 |
) |
|
(8,438 |
) |
|||
Proceeds from divestitures |
|
(Note 7) |
|
1,178 |
|
|
904 |
|
|
481 |
|
|||
Cash tax on sale of assets |
|
(Note 10) |
|
- |
|
|
(25 |
) |
|
- |
|
|||
Corporate acquisitions |
|
|
|
(24 |
) |
|
- |
|
|
- |
|
|||
Cash transferred on Split Transaction |
|
(Note 3) |
|
(3,996 |
) |
|
- |
|
|
- |
|
|||
Proceeds from notes receivable from Cenovus |
|
(Note 3) |
|
3,750 |
|
|
- |
|
|
- |
|
|||
Net change in investments and other |
|
|
|
337 |
|
|
311 |
|
|
331 |
|
|||
Net change in non-cash working capital from continuing operations |
|
(Note 21) |
|
(50 |
) |
|
34 |
|
|
51 |
|
|||
Discontinued operations |
|
|
|
(1,137 |
) |
|
(769 |
) |
|
(604 |
) |
|||
Cash (Used in) Investing Activities |
|
|
|
(4,806 |
) |
|
(7,542 |
) |
|
(8,179 |
) |
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|||
Net issuance (repayment) of revolving long-term debt |
|
|
|
(1,852 |
) |
|
(53 |
) |
|
181 |
|
|||
Issuance of long-term debt |
|
(Note 15) |
|
496 |
|
|
723 |
|
|
2,409 |
|
|||
Issuance of Cenovus Notes |
|
(Note 3) |
|
3,468 |
|
|
- |
|
|
- |
|
|||
Repayment of long-term debt |
|
(Note 15) |
|
(250 |
) |
|
(664 |
) |
|
(257 |
) |
|||
Issuance of common shares |
|
(Note 17) |
|
24 |
|
|
80 |
|
|
176 |
|
|||
Purchase of common shares |
|
(Note 17) |
|
- |
|
|
(326 |
) |
|
(2,025 |
) |
|||
Dividends on common shares |
|
|
|
(1,051 |
) |
|
(1,199 |
) |
|
(603 |
) |
|||
Cash From (Used in) Financing Activities |
|
|
|
835 |
|
|
(1,439 |
) |
|
(119 |
) |
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Foreign Exchange Gain (Loss) on Cash and Cash |
|
|
|
19 |
|
|
(33 |
) |
|
16 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Increase (Decrease) in Cash and Cash Equivalents |
|
|
|
3,921 |
|
|
(28 |
) |
|
(20 |
) |
|||
Cash and Cash Equivalents, Beginning of Year |
|
|
|
354 |
|
|
382 |
|
|
402 |
|
|||
Cash and Cash Equivalents, End of Year |
|
|
|
$ |
4,275 |
|
|
$ |
354 |
|
|
$ |
382 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Cash (Bank Overdraft), End of Year |
|
|
|
$ |
218 |
|
|
$ |
13 |
|
|
$ |
(19 |
) |
Cash Equivalents, End of Year |
|
|
|
4,057 |
|
|
341 |
|
|
401 |
|
|||
Cash and Cash Equivalents, End of Year |
|
|
|
$ |
4,275 |
|
|
$ |
354 |
|
|
$ |
382 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Supplementary Cash Flow Information |
|
(Note 21) |
|
|
|
|
|
|
|
|
|
See accompanying Notes to Consolidated Financial Statements
EnCana Corporation |
|
Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
Prepared using Canadian Generally Accepted Accounting Principles
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009
1. Summary of Significant Accounting Policies
In these Consolidated Financial Statements, unless otherwise indicated, all dollar amounts are expressed in United States (U.S.) dollars. EnCanas functional currency is Canadian dollars; EnCana has adopted the U.S. dollar as its reporting currency since 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. All references to US$ or to $ are to United States dollars and references to C$ are to Canadian dollars.
EnCanas continuing 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).
A) PRINCIPLES OF CONSOLIDATION
The 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 (GAAP). Information prepared in accordance with GAAP in the United States is included in Note 23.
Investments in jointly controlled partnerships and unincorporated joint ventures carry on EnCanas exploration, development and production and are accounted for using the proportionate consolidation method, whereby EnCanas proportionate share of revenues, expenses, assets and liabilities are included in the accounts.
B) FOREIGN CURRENCY TRANSLATION
The accounts of self-sustaining operations are translated using the current rate method, whereby assets and liabilities are translated at period end exchange rates, while revenues and expenses are translated using average rates over the period. Translation gains and losses relating to the self-sustaining operations are included in Accumulated Other Comprehensive Income (AOCI) as a separate component of Shareholders Equity. As at December 31, 2009, AOCI solely includes foreign currency translation adjustments.
Monetary assets and liabilities of the Company that are denominated in foreign currencies are translated into its functional currency at the rates of exchange in effect at the period end date. Any gains or losses are recorded in the Consolidated Statement of Earnings.
C) MEASUREMENT UNCERTAINTY
The timely preparation of the Consolidated Financial Statements in conformity with Canadian GAAP requires that Management make estimates and assumptions and use judgment regarding the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the period. Such estimates primarily relate to unsettled transactions and events as of the date of the Consolidated Financial Statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur.
Amounts recorded for depreciation, depletion and amortization, asset retirement costs and obligations and amounts used for ceiling test and impairment calculations are based on estimates of natural gas and crude oil reserves and future costs required to develop those reserves. By their nature, these estimates of reserves, including the estimates of future prices, costs and the related future cash flows, are subject to measurement uncertainty. Accordingly, the impact in the Consolidated Financial Statements of future periods could be material.
The estimated fair value of derivative instruments resulting in financial assets and liabilities, by their very nature, are subject to measurement uncertainty.
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
Tax interpretations, regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change. As such, income taxes are subject to measurement uncertainty.
The amount of compensation expense accrued for long-term performance-based compensation arrangements is subject to Managements best estimate of whether or not the performance criteria will be met and what the ultimate payout will be.
The values of pension assets and obligations and the amount of pension costs charged to net earnings depend on certain actuarial and economic assumptions which, by their nature, are subject to measurement uncertainty.
D) REVENUE RECOGNITION
Revenues associated with the sales of EnCanas natural gas, crude oil, NGLs and petroleum and chemical products are recognized when title passes from the Company to its customer. Realized gains and losses from the Companys natural gas and crude oil commodity price risk management activities are recorded in revenue when the product is sold.
Market optimization revenues and purchased product are recorded on a gross basis when EnCana takes title to product and has risks and rewards of ownership. Purchases and sales of products that are entered into in contemplation of each other with the same counterparty are recorded on a net basis. Revenues associated with the services provided where EnCana acts as agent are recorded as the services are provided. Sales of electric power are recognized when power is provided to the customer.
Unrealized gains and losses from the Companys natural gas and crude oil commodity price risk management activities are recorded as revenue based on the related mark-to-market calculations at the end of the respective period.
E) PRODUCTION AND MINERAL TAXES
Costs paid by EnCana to non-mineral interest owners based on production of natural gas, crude oil and NGLs are recognized when the product is produced.
F) TRANSPORTATION AND SELLING COSTS
Costs paid by EnCana for the transportation and selling of natural gas, crude oil and NGLs, including diluent, are recognized when the product is delivered and the services provided.
G) EMPLOYEE BENEFIT PLANS
EnCana accrues for its obligations under its employee benefit plans and the related costs, net of plan assets.
The cost of pensions and other post-employment benefits is actuarially determined using the projected benefit method based on length of service, and reflects Managements best estimate of expected plan investment performance, salary escalation, retirement ages of employees and expected future health care costs. The expected return on plan assets is based on the fair value of those assets. The accrued benefit obligation is discounted using the market interest rate on high-quality corporate debt instruments as at the measurement date.
Pension expense for the defined benefit pension plan includes the cost of pension benefits earned during the current year, the interest cost on pension obligations, the expected return on pension plan assets, the amortization of the net transitional obligation, the amortization of adjustments arising from pension plan amendments and the amortization of the excess of the net actuarial gain or loss over 10 percent of the greater of the benefit obligation and the fair value of plan assets. Amortization is done on a straight-line basis over a period covering the expected average remaining service lives of employees covered by the plans.
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
Pension expense for the defined contribution pension plans is recorded as the benefits are earned by the employees covered by the plans.
H) INCOME TAXES
EnCana follows the liability method of accounting for income taxes. Under this method, future income taxes are recorded for the effect of any difference between the accounting and income tax basis of an asset or liability, using the substantively enacted income tax rates. Accumulated future income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted, with the adjustment being recognized in net earnings in the period that the change occurs.
I) EARNINGS PER SHARE AMOUNTS
Basic net earnings per common share is computed by dividing the net earnings by the weighted average number of common shares outstanding during the period. Diluted net earnings per common share amounts are calculated giving effect to the potential dilution that would occur if stock options, without tandem share appreciation rights attached, were exercised or other contracts to issue common shares were exercised or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options without tandem share appreciation rights attached and other dilutive instruments. The treasury stock method assumes that proceeds received from the exercise of in-the-money stock options without tandem share appreciation rights attached are used to repurchase common shares at the average market price.
J) CASH AND CASH EQUIVALENTS
Cash and cash equivalents include short-term investments, such as money market deposits or similar type instruments, with a maturity of three months or less when purchased.
K) INVENTORIES
Product inventories are valued at the lower of cost and net realizable value on a first-in, first-out or weighted average cost basis.
L) PROPERTY, PLANT AND EQUIPMENT
UPSTREAM
EnCana accounts for natural gas and crude oil properties in accordance with the Canadian Institute of Chartered Accountants (CICA) guideline on full cost accounting in the oil and gas industry. Under this method, all costs, including internal costs and asset retirement costs, directly associated with the acquisition of, the exploration for, and the development of natural gas and crude oil reserves are capitalized on a country-by-country cost centre basis.
Costs accumulated within each cost centre are depleted using the unit-of-production method based on estimated proved reserves determined using estimated future prices and costs. For purposes of this calculation, oil is converted to gas on an energy equivalent basis. Capitalized costs subject to depletion include estimated future costs to be incurred in developing proved reserves. Proceeds from the divestiture of properties are normally deducted from the full cost pool without recognition of gain or loss unless that deduction would result in a change to the rate of depletion of 20 percent or greater, in which case a gain or loss is recorded. Costs of major development projects and costs of acquiring and evaluating significant unproved properties are excluded, on a cost centre basis, from the costs subject to depletion until it is determined whether or not proved reserves are attributable to the properties, or impairment has occurred. Costs that have been impaired are included in the costs subject to depletion.
An impairment loss is recognized in net earnings when the carrying amount of a cost centre is not recoverable. The carrying amount of the cost centre is not recoverable if the carrying amount exceeds the sum of the undiscounted cash
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
flows from proved reserves. If the sum of the cash flows is less than the carrying amount, the impairment loss is measured as the amount by which the carrying amount exceeds the sum of:
i) the fair value of proved and probable reserves; and
ii) the costs of unproved properties that have been subject to a separate impairment test.
DOWNSTREAM REFINING (DISCONTINUED)
The initial acquisition costs of refinery property, plant and equipment are capitalized when incurred. Costs include the cost of constructing or otherwise acquiring the equipment or facilities, the cost of installing the asset and making it ready for its intended use and the associated asset retirement costs. Capitalized costs are not subject to depreciation until the asset is put into use, after which they are depreciated on a straight-line basis over their estimated service lives of approximately 25 years.
An impairment loss is recognized on refinery property, plant and equipment when the carrying amount is not recoverable. The carrying amount is not recoverable if the carrying amount exceeds the sum of the undiscounted cash flows from expected use and eventual disposition. If the carrying amount is not recoverable, an impairment loss is measured as the amount by which the refinery asset exceeds the fair value.
MARKET OPTIMIZATION
Midstream facilities, including power generation facilities, are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets, which range from 20 to 25 years. Capital assets related to pipelines are carried at cost and depreciated using the straight-line method over their economic lives, which range from 20 to 35 years.
CORPORATE
Costs associated with office furniture, fixtures, leasehold improvements, information technology and aircraft are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets, which range from three to 25 years. Assets under construction are not subject to depreciation until put into use. Land is carried at cost.
M) CAPITALIZATION OF COSTS
Expenditures related to renewals or betterments that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and repairs are expensed as incurred.
Interest is capitalized during the construction phase of large capital projects.
N) AMORTIZATION OF OTHER ASSETS
Items included in Investments and Other Assets are amortized, where applicable, on a straight-line basis over the estimated useful lives of the assets.
O) GOODWILL
Goodwill, which represents the excess of purchase price over fair value of net assets acquired, is assessed for impairment at least annually as at December 31 of each year. Goodwill and all other assets and liabilities have been allocated to the country cost centre levels, referred to as reporting units. To assess impairment, the fair value of each reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, then a second test is performed to determine the amount of the impairment. The amount of the impairment is determined by deducting the fair value of the reporting units assets and liabilities from the fair value of the reporting unit to determine the implied fair value of goodwill and comparing that amount to the book value of the reporting units goodwill. Any excess of the book value of goodwill over the implied fair value of goodwill is the impairment amount.
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
P) ASSET RETIREMENT OBLIGATION
The fair value of estimated asset retirement obligations is recognized in the Consolidated Balance Sheet when incurred and a reasonable estimate of fair value can be made.
Asset retirement obligations include those legal obligations where the Company will be required to retire tangible long-lived assets such as producing well sites, offshore production platforms and natural gas processing plants. The asset retirement cost, equal to the initially estimated fair value of the asset retirement obligation, is capitalized as part of the cost of the related long-lived asset. Changes in the estimated obligation resulting from revisions to estimated timing or amount of undiscounted cash flows are recognized as a change in the asset retirement obligation and the related asset retirement cost.
Amortization of asset retirement costs are included in depreciation, depletion and amortization in the Consolidated Statement of Earnings. Increases in the asset retirement obligation resulting from the passage of time are recorded as accretion of asset retirement obligation in the Consolidated Statement of Earnings.
Actual expenditures incurred are charged against the accumulated obligation.
Q) STOCK-BASED COMPENSATION
Obligations for payments, cash or common shares under EnCanas share appreciation rights, stock options with tandem share appreciation rights attached, deferred share and performance share units plans are accrued as compensation expense over the vesting period using the intrinsic value method.
Obligations for payments for share options of Cenovus Energy Inc. (Cenovus) held by EnCana employees are accrued as compensation expense based on the fair value of the financial liability.
Fluctuations in the underlying common share prices change the accrued compensation cost and are recognized when they occur.
R) FINANCIAL INSTRUMENTS
Financial instruments are measured at fair value on initial recognition of the instrument, except for certain related party transactions. Measurement in subsequent periods depends on whether the financial instrument has been classified as held-for-trading, available-for-sale, held-to-maturity, loans and receivables, or other financial liabilities as defined by the accounting standard.
Financial assets and financial liabilities held-for-trading are measured at fair value with changes in those fair values recognized in net earnings. Financial assets available-for-sale are measured at fair value, with changes in those fair values recognized in Other Comprehensive Income (OCI). Financial assets held-to-maturity, loans and receivables and other financial liabilities are measured at amortized cost using the effective interest method of amortization.
Cash and cash equivalents, accounts receivable and accounts payable relating to share options of EnCana held by Cenovus employees, and accounts payable for share options of Cenovus held by EnCana employees are designated as held-for-trading and are measured at fair value.
With the exception of accounts receivable relating to share options of EnCana held by Cenovus employees, accounts receivable and accrued revenues and the partnership contribution receivable are designated as loans and receivables.
With the exception of accounts payable relating to share options of EnCana held by Cenovus employees and accounts payable relating to share options of Cenovus held by EnCana employees, accounts payable and accrued liabilities and long-term debt are designated as other financial liabilities.
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
EnCana capitalizes long-term debt transaction costs, premiums and discounts. These costs are capitalized within long-term debt and amortized using the effective interest method.
RISK MANAGEMENT ASSETS AND LIABILITIES
Risk management assets and liabilities are derivative financial instruments classified as held-for-trading unless designated for hedge accounting. Derivative instruments that do not qualify as hedges, or are not designated as hedges, are recorded at fair value whereby instruments are recorded in the Consolidated Balance Sheet as either an asset or liability with changes in fair value recognized in net earnings. Realized gains or losses from financial derivatives related to natural gas and crude oil commodity prices are recognized in natural gas and crude oil revenues as the related sales occur. Realized gains or losses from financial derivatives related to power commodity prices are recognized in operating costs as the related power costs are incurred. Unrealized gains and losses are recognized at the end of each respective reporting period. The estimated fair value of all derivative instruments is based on quoted market prices or, in their absence, third-party market indications and forecasts.
Derivative financial instruments are used by EnCana to manage economic exposure to market risks relating to commodity prices, foreign currency exchange rates and interest rates. The Companys policy is not to utilize derivative financial instruments for speculative purposes.
EnCana has in place policies and procedures with respect to the required documentation and approvals for the use of derivative financial instruments and specifically ties their use, in the case of commodities, to the mitigation of market price risk associated with cash flows expected to be generated from budgeted capital programs, and in other cases to the mitigation of market price risks for specific assets and obligations. When applicable, the Company identifies relationships between financial instruments and anticipated transactions, as well as its risk management objective and the strategy for undertaking the economic hedge transaction. Where specific financial instruments are executed, the Company assesses, both at the time of purchase and on an ongoing basis, whether the financial instrument used in the particular transaction is effective in offsetting changes in fair values or cash flows of the transaction.
S) RECENT ACCOUNTING PRONOUNCEMENTS
In February 2008, the CICAs Accounting Standards Board confirmed that International Financial Reporting Standards (IFRS) will replace Canadian GAAP 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 impact of IFRS on the Companys Consolidated Financial Statements is not reasonably determinable at this time.
As of January 1, 2011, EnCana will be required to adopt the following CICA Handbook sections:
· Business Combinations, Section 1582, which replaces the previous business combinations standard. The standard requires assets and liabilities acquired in a business combination, contingent consideration and certain acquired contingencies to be measured at their fair values as of the date of acquisition. In addition, acquisition-related and restructuring costs are to be recognized separately from the business combination and included in the statement of earnings. The adoption of this standard will impact the accounting treatment of future business combinations.
· Consolidated Financial Statements, Section 1601, which, together with Section 1602 below, replace the former consolidated financial statements standard. Section 1601 establishes the requirements for the preparation of consolidated financial statements. The adoption of this standard should not have a material impact on EnCanas Consolidated Financial Statements.
· Non-controlling Interests, Section 1602, which establishes the accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. The standard requires a non-controlling interest in a subsidiary to be classified as a separate component of equity. In addition, net earnings and
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
components of other comprehensive income are attributed to both the parent and non-controlling interest. The adoption of this standard should not have a material impact on EnCanas Consolidated Financial Statements.
T) RECLASSIFICATION
Certain information provided for prior years has been reclassified to conform to the presentation adopted in 2009.
2. Changes in Accounting Policies and Practices
On January 1, 2009, the Company adopted the following CICA Handbook section:
· Goodwill and Intangible Assets, Section 3064. The new standard replaces the previous goodwill and intangible asset standard and revises the requirement for recognition, measurement, presentation and disclosure of intangible assets. The adoption of this standard has had no material impact on EnCanas Consolidated Financial Statements.
3. Split Transaction
On November 30, 2009, EnCana completed a corporate reorganization (the Split Transaction) involving the division of EnCana into two independent publicly traded energy companies one, EnCana Corporation, a natural gas company, and the other, an integrated oil company, Cenovus Energy Inc.
The Split Transaction was initially proposed in May 2008. In October 2008, EnCana announced the proposed reorganization would be delayed until the global debt and equity markets regained stability. In September 2009, EnCanas Board of Directors unanimously approved plans to proceed with the split and in November 2009, shareholders approved to proceed with the Split Transaction.
Under the Split Transaction, EnCana shareholders received one new EnCana Common Share and one EnCana Special Share in exchange for each EnCana Common Share previously held. The book value of EnCanas outstanding Common Shares immediately prior to the Split Transaction was attributed to the new EnCana Common Shares and the EnCana Special Shares in direct proportion to the weighted average trading price of the shares on a when issued basis. In accordance with the calculation, the value attributed to the new EnCana Common Shares and the EnCana Special Shares was $2,360 million and $2,222 million, respectively. The EnCana Special Shares were subsequently exchanged by EnCana shareholders for Common Shares of Cenovus, thereby effecting the Split Transaction.
Under the Split Transaction, EnCanas downstream refining operations and certain upstream oil and gas assets were transferred to Cenovus. The historical results associated with the upstream assets transferred are reported as continuing operations in accordance with full cost accounting requirements (See Note 4). The historical results associated with the downstream refining operations have been presented as discontinued operations (See Note 6).
In conjunction with the proposed reorganization, on September 18, 2009, Cenovus completed a private offering of senior unsecured notes for an aggregate principal amount of $3,500 million. The unsecured notes (Cenovus Notes) were transferred under the Split Transaction.
The impact of the Split Transaction on EnCanas Consolidated Balance Sheet is as follows. The net assets were transferred at book value.
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
Net Assets Transferred Under the Split Transaction
|
|
|
|
|
Assets |
|
|
|
|
Cash and restricted cash |
|
$ |
3,996 |
|
Property, plant and equipment, net |
|
|
|
|
Oil and gas |
|
9,329 |
|
|
Downstream refining (See Note 6) |
|
4,710 |
|
|
Partnership contribution receivable, including current portion |
|
2,835 |
|
|
Goodwill |
|
1,083 |
|
|
Other current and non-current assets |
|
2,094 |
|
|
|
|
24,047 |
|
|
|
|
|
|
|
Liabilities |
|
|
|
|
Notes payable to EnCana |
|
3,750 |
|
|
Cenovus notes |
|
3,436 |
|
|
Partnership contribution payable, including current portion |
|
2,857 |
|
|
Future income taxes |
|
2,314 |
|
|
Other current and non-current liabilities |
|
2,470 |
|
|
|
|
14,827 |
|
|
Net Assets Transferred Under the Split Transaction |
|
$ |
9,220 |
|
The Split Transaction reduced Total Shareholders Equity by way of a reduction in Share capital of $2,222 million, a reduction in Retained earnings of $4,902 million and a reduction in Accumulated other comprehensive income of $2,096 million.
Following the Split Transaction, EnCana received amounts due from Cenovus and invested the net proceeds of approximately $3.75 billion in short-term marketable securities.
EnCanas continuing operations include all revenues and expenses prior to November 30, 2009 of the oil and gas assets transferred to Cenovus under the Split Transaction (See Note 4).
4. Segmented Information
The Companys operating and reportable segments are as follows:
· Canada includes the Companys exploration for, and development and production of natural gas, crude oil and NGLs and other related activities within the Canadian cost centre.
· USA includes the Companys exploration for, and development and production of natural gas, NGLs and other related activities within the United States cost centre.
· Market Optimization is primarily responsible for the sale of the Companys proprietary production. These results are included in the Canada and USA segments. Market optimization activities include third-party purchases and sales of product that provide operational flexibility for transportation commitments, product type, delivery points and customer diversification. These activities are reflected in the Market Optimization segment.
· Corporate and Other mainly includes unrealized gains or losses recorded on derivative financial instruments. Once amounts are settled, the realized gains and losses are recorded in the operating segment to which the derivative instrument relates.
Market Optimization markets substantially all of the Companys upstream production to third-party customers. Transactions between segments are based on market values and eliminated on consolidation. The tables in this note present financial information on an after eliminations basis.
In conjunction with the Split Transaction (See Note 3), the assets formerly included in EnCanas Canadian Plains Division and Integrated Oil Division were transferred to Cenovus. As a result, EnCana has updated its
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
segmented reporting to present the Canadian Foothills Division as the Canadian Division. The Canadian Plains Division and Integrated Oil Canada are now presented as Canada Other. Prior periods have been restated to reflect the new presentation.
EnCana has a decentralized decision-making and reporting structure. Accordingly, the Company reports its divisional results as follows:
· Canadian Division, formerly the Canadian Foothills Division, includes natural gas development and production assets located in British Columbia and Alberta, as well as the Companys Canadian offshore assets.
· USA Division includes natural gas exploration, development and production assets located in the United States and forms the USA segment described above.
· Canada Other includes the combined results from the former Canadian Plains Division and Integrated Oil Canada.
Operations that have been discontinued are disclosed in Note 6.
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
Results of Continuing Operations
Segment and Geographic Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
USA |
|
Market Optimization |
|
|||||||||||||||||||||
For the years ended December 31 |
|
2009 |
|
2008 |
|
2007 |
|
2009 |
|
2008 |
|
2007 |
|
2009 |
|
2008 |
|
2007 |
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Revenues, Net of Royalties |
|
$ |
7,585 |
|
$ 10,050 |
|
$ 8,308 |
|
$ |
4,537 |
|
$ |
5,629 |
|
$ |
4,372 |
|
$ |
1,607 |
|
$ |
2,655 |
|
$ |
2,944 |
|
||
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Production and mineral taxes |
|
53 |
|
108 |
|
102 |
|
118 |
|
370 |
|
189 |
|
- |
|
- |
|
- |
|
|||||||||
Transportation and selling |
|
750 |
|
1,202 |
|
947 |
|
530 |
|
502 |
|
307 |
|
- |
|
- |
|
10 |
|
|||||||||
Operating |
|
1,118 |
|
1,333 |
|
1,204 |
|
434 |
|
618 |
|
595 |
|
26 |
|
45 |
|
37 |
|
|||||||||
Purchased product |
|
(85 |
) |
(151 |
) |
(88 |
) |
- |
|
- |
|
- |
|
1,545 |
|
2,577 |
|
2,858 |
|
|||||||||
|
|
5,749 |
|
7,558 |
|
6,143 |
|
3,455 |
|
4,139 |
|
3,281 |
|
36 |
|
33 |
|
39 |
|
|||||||||
Depreciation, depletion and amortization |
|
1,980 |
|
2,198 |
|
2,298 |
|
1,561 |
|
1,691 |
|
1,181 |
|
20 |
|
15 |
|
17 |
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment Income (Loss) |
|
$ |
3,769 |
|
$ 5,360 |
|
$ 3,845 |
|
$ |
1,894 |
|
$ |
2,448 |
|
$ |
2,100 |
|
$ |
16 |
|
$ |
18 |
|
$ |
22 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate & Other |
|
Consolidated |
|
|||||||||||||||||
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2007 |
|
2009 |
|
2008 |
|
2007 |
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Revenues, Net of Royalties |
|
|
|
|
|
|
|
$ |
(2,615 |
) |
$ |
2,719 |
|
$ |
(1,239 |
) |
$ |
11,114 |
|
$ |
21,053 |
|
$ |
14,385 |
|
|||
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Production and mineral taxes |
|
|
|
|
|
|
|
- |
|
- |
|
- |
|
171 |
|
478 |
|
291 |
|
|||||||||
Transportation and selling |
|
|
|
|
|
|
|
- |
|
- |
|
- |
|
1,280 |
|
1,704 |
|
1,264 |
|
|||||||||
Operating |
|
|
|
|
|
|
|
49 |
|
(13 |
) |
14 |
|
1,627 |
|
1,983 |
|
1,850 |
|
|||||||||
Purchased product |
|
|
|
|
|
|
|
- |
|
- |
|
- |
|
1,460 |
|
2,426 |
|
2,770 |
|
|||||||||
|
|
|
|
|
|
|
|
(2,664 |
) |
2,732 |
|
(1,253 |
) |
6,576 |
|
14,462 |
|
8,210 |
|
|||||||||
Depreciation, depletion and amortization |
|
|
|
|
|
143 |
|
131 |
|
161 |
|
3,704 |
|
4,035 |
|
3,657 |
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Segment Income (Loss) |
|
|
|
|
|
|
|
$ |
(2,807 |
) |
$ |
2,601 |
|
$ |
(1,414 |
) |
2,872 |
|
10,427 |
|
4,553 |
|
||||||
Administrative |
|
|
|
|
|
|
|
|
|
|
|
|
|
477 |
|
447 |
|
356 |
|
|||||||||
Interest, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
405 |
|
402 |
|
234 |
|
|||||||||
Accretion of asset retirement obligation |
|
|
|
|
|
|
|
|
|
|
|
|
|
71 |
|
77 |
|
63 |
|
|||||||||
Foreign exchange (gain) loss, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
(22 |
) |
423 |
|
(164 |
) |
|||||||||
(Gain) loss on divestitures |
|
|
|
|
|
|
|
|
|
|
|
|
|
2 |
|
(141 |
) |
(65 |
) |
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
933 |
|
1,208 |
|
424 |
|
|||||||||
Net Earnings Before Income Tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
1,939 |
|
9,219 |
|
4,129 |
|
|||||||||
Income tax expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
109 |
|
2,720 |
|
682 |
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Net Earnings From Continuing Operations |
|
|
|
|
|
|
|
|
|
|
|
$ |
1,830 |
|
$ |
6,499 |
|
$ |
3,447 |
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
Results of Continuing Operations
Product and Divisional Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada Segment |
|
|||||||||||||||||||||||||
|
|
Canadian Division |
|
Canada Other |
|
Total |
|
|||||||||||||||||||||
For the years ended December 31 |
|
2009 |
|
2008 |
|
2007 |
|
2009 |
|
2008 |
|
2007 |
|
2009 |
|
2008 |
|
2007 |
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Revenues, Net of Royalties |
|
$ |
3,362 |
|
$ |
4,355 |
|
$ |
3,679 |
|
$ |
4,223 |
|
$ |
5,695 |
|
$ |
4,629 |
|
$ |
7,585 |
|
$ |
10,050 |
|
$ |
8,308 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Production and mineral taxes |
|
14 |
|
33 |
|
39 |
|
39 |
|
75 |
|
63 |
|
53 |
|
108 |
|
102 |
|
|||||||||
Transportation and selling |
|
154 |
|
239 |
|
201 |
|
596 |
|
963 |
|
746 |
|
750 |
|
1,202 |
|
947 |
|
|||||||||
Operating |
|
536 |
|
609 |
|
535 |
|
582 |
|
724 |
|
669 |
|
1,118 |
|
1,333 |
|
1,204 |
|
|||||||||
Purchased product |
|
- |
|
- |
|
- |
|
(85 |
) |
(151 |
) |
(88 |
) |
(85 |
) |
(151 |
) |
(88 |
) |
|||||||||
Operating Cash Flow |
|
$ |
2,658 |
|
$ |
3,474 |
|
$ |
2,904 |
|
$ |
3,091 |
|
$ |
4,084 |
|
$ |
3,239 |
|
$ |
5,749 |
|
$ |
7,558 |
|
$ |
6,143 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Division* |
|
|||||||||||||||||||||||||
|
|
Gas |
|
Oil & NGLs |
|
Other |
|
|||||||||||||||||||||
For the years ended December 31 |
|
2009 |
|
2008 |
|
2007 |
|
2009 |
|
2008 |
|
2007 |
|
2009 |
|
2008 |
|
2007 |
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Revenues, Net of Royalties |
|
$ |
3,041 |
|
$ |
3,720 |
|
$ |
3,232 |
|
$ |
277 |
|
$ |
578 |
|
$ |
390 |
|
$ |
44 |
|
$ |
57 |
|
$ |
57 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Production and mineral taxes |
|
11 |
|
28 |
|
36 |
|
3 |
|
5 |
|
3 |
|
- |
|
- |
|
- |
|
|||||||||
Transportation and selling |
|
148 |
|
201 |
|
192 |
|
6 |
|
12 |
|
9 |
|
- |
|
26 |
|
- |
|
|||||||||
Operating |
|
501 |
|
549 |
|
482 |
|
21 |
|
39 |
|
33 |
|
14 |
|
21 |
|
20 |
|
|||||||||
Operating Cash Flow |
|
$ |
2,381 |
|
$ |
2,942 |
|
$ |
2,522 |
|
$ |
247 |
|
$ |
522 |
|
$ |
345 |
|
$ |
30 |
|
$ |
10 |
|
$ |
37 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2007 |
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Revenues, Net of Royalties |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
3,362 |
|
$ |
4,355 |
|
$ |
3,679 |
|
||||||
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Production and mineral taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
14 |
|
33 |
|
39 |
|
|||||||||
Transportation and selling |
|
|
|
|
|
|
|
|
|
|
|
|
|
154 |
|
239 |
|
201 |
|
|||||||||
Operating |
|
|
|
|
|
|
|
|
|
|
|
|
|
536 |
|
609 |
|
535 |
|
|||||||||
Operating Cash Flow |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
2,658 |
|
$ |
3,474 |
|
$ |
2,904 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* Formerly known as the Canadian Foothills Division.
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
Results of Continuing Operations
Product and Divisional Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
USA Division |
|
|||||||||||||||||||||||||
|
|
Gas |
|
Oil & NGLs |
|
Other |
|
|||||||||||||||||||||
For the years ended December 31 |
|
2009 |
|
2008 |
|
2007 |
|
2009 |
|
2008 |
|
2007 |
|
2009 |
|
2008 |
|
2007 |
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Revenues, Net of Royalties |
|
$ |
4,222 |
|
$ |
4,934 |
|
$ |
3,765 |
|
$ |
201 |
|
$ |
407 |
|
$ |
309 |
|
$ |
114 |
|
$ |
288 |
|
$ |
298 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Production and mineral taxes |
|
100 |
|
334 |
|
167 |
|
18 |
|
36 |
|
22 |
|
- |
|
- |
|
- |
|
|||||||||
Transportation and selling |
|
530 |
|
502 |
|
307 |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
|||||||||
Operating |
|
327 |
|
352 |
|
323 |
|
- |
|
- |
|
- |
|
107 |
|
266 |
|
272 |
|
|||||||||
Operating Cash Flow |
|
$ |
3,265 |
|
$ |
3,746 |
|
$ |
2,968 |
|
$ |
183 |
|
$ |
371 |
|
$ |
287 |
|
$ |
7 |
|
$ |
22 |
|
$ |
26 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2007 |
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Revenues, Net of Royalties |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
4,537 |
|
$ |
5,629 |
|
$ |
4,372 |
|
||||||
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Production and mineral taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
118 |
|
370 |
|
189 |
|
|||||||||
Transportation and selling |
|
|
|
|
|
|
|
|
|
|
|
|
|
530 |
|
502 |
|
307 |
|
|||||||||
Operating |
|
|
|
|
|
|
|
|
|
|
|
|
|
434 |
|
618 |
|
595 |
|
|||||||||
Operating Cash Flow |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
3,455 |
|
$ |
4,139 |
|
$ |
3,281 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada Other** |
|
|||||||||||||||||||||||||
|
|
Gas |
|
Oil & NGLs |
|
Other |
|
|||||||||||||||||||||
For the years ended December 31 |
|
2009 |
|
2008 |
|
2007 |
|
2009 |
|
2008 |
|
2007 |
|
2009 |
|
2008 |
|
2007 |
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Revenues, Net of Royalties |
|
$ |
1,781 |
|
$ |
2,301 |
|
$ |
2,186 |
|
$ |
2,287 |
|
$ |
3,223 |
|
$ |
2,191 |
|
$ |
155 |
|
$ |
171 |
|
$ |
252 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Production and mineral taxes |
|
15 |
|
36 |
|
34 |
|
23 |
|
38 |
|
29 |
|
1 |
|
1 |
|
- |
|
|||||||||
Transportation and selling |
|
37 |
|
71 |
|
82 |
|
535 |
|
847 |
|
629 |
|
24 |
|
45 |
|
35 |
|
|||||||||
Operating |
|
186 |
|
241 |
|
221 |
|
356 |
|
409 |
|
374 |
|
40 |
|
74 |
|
74 |
|
|||||||||
Purchased product |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
(85 |
) |
(151 |
) |
(88 |
) |
|||||||||
Operating Cash Flow |
|
$ |
1,543 |
|
$ |
1,953 |
|
$ |
1,849 |
|
$ |
1,373 |
|
$ |
1,929 |
|
$ |
1,159 |
|
$ |
175 |
|
$ |
202 |
|
$ |
231 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2007 |
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Revenues, Net of Royalties |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
4,223 |
|
$ |
5,695 |
|
$ |
4,629 |
|
||||||
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Production and mineral taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
39 |
|
75 |
|
63 |
|
|||||||||
Transportation and selling |
|
|
|
|
|
|
|
|
|
|
|
|
|
596 |
|
963 |
|
746 |
|
|||||||||
Operating |
|
|
|
|
|
|
|
|
|
|
|
|
|
582 |
|
724 |
|
669 |
|
|||||||||
Purchased product |
|
|
|
|
|
|
|
|
|
|
|
|
|
(85 |
) |
(151 |
) |
(88 |
) |
|||||||||
Operating Cash Flow |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
3,091 |
|
$ |
4,084 |
|
$ |
3,239 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
** Includes the operations formerly known as the Canadian Plains Division and Integrated Oil Canada.
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
Capital Expenditures (Continuing Operations)
For the years ended December 31 |
|
2009 |
|
2008 |
|
2007 |
|
|||
|
|
|
|
|
|
|
|
|||
Capital |
|
|
|
|
|
|
|
|||
Canadian Division |
|
$ |
1,869 |
|
$ |
2,459 |
|
$ |
2,403 |
|
Canada Other |
|
848 |
|
1,500 |
|
1,238 |
|
|||
Canada |
|
2,717 |
|
3,959 |
|
3,641 |
|
|||
USA |
|
1,821 |
|
2,682 |
|
1,935 |
|
|||
Market Optimization |
|
2 |
|
17 |
|
6 |
|
|||
Corporate & Other |
|
85 |
|
165 |
|
154 |
|
|||
|
|
4,625 |
|
6,823 |
|
5,736 |
|
|||
|
|
|
|
|
|
|
|
|||
Acquisition Capital |
|
|
|
|
|
|
|
|||
Canadian Division |
|
190 |
|
151 |
|
75 |
|
|||
Canada Other |
|
3 |
|
- |
|
14 |
|
|||
Canada |
|
193 |
|
151 |
|
89 |
|
|||
USA |
|
46 |
|
1,023 |
|
2,613 |
|
|||
|
|
239 |
|
1,174 |
|
2,702 |
|
|||
Total |
|
$ |
4,864 |
|
$ |
7,997 |
|
$ |
8,438 |
|
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 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 Haynesville represented an interest in a Variable Interest Entity (VIE) from September 25, 2008 to March 24, 2009. During this period, EnCana was the primary beneficiary of the VIE and consolidated Brown Haynesville. On March 24, 2009, when the arrangement with Brown Haynesville was completed, the assets were transferred to EnCana.
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 held 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. The relationship with Brown Southwest represented an interest in a VIE from July 23, 2008 to January 19, 2009. During this period, EnCana was the primary beneficiary of the VIE and consolidated Brown Southwest. On January 19, 2009, when the arrangement with Brown Southwest was completed, the assets were transferred to EnCana.
On November 20, 2007, EnCana acquired certain natural gas and land interests in Texas for approximately $2.55 billion before closing adjustments. The purchase was facilitated by an unrelated party, Brown Kilgore Properties LLC (Brown Kilgore), which held the majority of the assets in trust for the Company in anticipation of a qualifying like kind exchange for U.S. tax purposes. The relationship with Brown Kilgore represented an interest in a VIE from November 20, 2007 to May 18, 2008. During this period, EnCana was the primary beneficiary of the VIE and consolidated Brown Kilgore. On May 18, 2008, when the arrangement with Brown Kilgore was completed, the assets were transferred to EnCana.
Additions to Goodwill
There were no additions to goodwill during 2009 or 2008.
As a result of the Split Transaction, a portion of goodwill was transferred to Cenovus (See Note 3).
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
Property, Plant and Equipment and Total Assets by Segment
|
|
Property, Plant and Equipment |
|
Total Assets |
|
|||||||||
As at December 31 |
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
|||||
|
|
|
|
|
|
|
|
|
|
|||||
Canada |
|
$ |
11,162 |
|
$ |
17,498 |
|
$ |
12,748 |
|
$ |
23,419 |
|
|
USA |
|
13,929 |
|
13,643 |
|
14,962 |
|
14,635 |
|
|||||
Market Optimization |
|
124 |
|
140 |
|
303 |
|
429 |
|
|||||
Corporate & Other |
|
958 |
|
629 |
|
5,814 |
|
4,098 |
|
|||||
Assets of Discontinued Operations |
(Note 6) |
|
|
|
|
|
- |
|
4,666 |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
26,173 |
|
$ |
31,910 |
|
$ |
33,827 |
|
$ |
47,247 |
|
|
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, 2009, Canada Property, Plant and Equipment and Total Assets include EnCanas accrual to date of $427 million (2008 $199 million) related to this offshore facility as an asset under construction.
On February 9, 2007, EnCana announced that it had entered into a 25-year lease agreement with a third party developer for The Bow office project. As at December 31, 2009, Corporate and Other Property, Plant and Equipment and Total Assets include EnCanas accrual to date of $649 million (2008 $252 million) related to this office project as an asset under construction.
For further information relating to The Bow office project, refer to Note 22.
Corresponding liabilities for these projects are included in Other Liabilities in the Consolidated Balance Sheet. There is no effect on the Companys net earnings or cash flows related to the capitalization of The Bow office project or the Deep Panuke PFC.
Goodwill, Property, Plant and Equipment and Total Assets by Geographic Region
|
|
|
|
|
|
|
|
||||||||||||
|
|
Goodwill |
|
Property, Plant and Equipment |
|
Total Assets |
|
||||||||||||
As at December 31 |
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Canada |
|
$ |
1,190 |
|
$ |
1,953 |
|
$ |
12,181 |
|
$ |
18,206 |
|
$ |
18,682 |
|
$ |
27,726 |
|
United States |
|
473 |
|
473 |
|
13,982 |
|
13,694 |
|
15,099 |
|
19,414 |
|
||||||
Other Countries |
|
- |
|
- |
|
10 |
|
10 |
|
46 |
|
107 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
1,663 |
|
$ |
2,426 |
|
$ |
26,173 |
|
$ |
31,910 |
|
$ |
33,827 |
|
$ |
47,247 |
|
Export Sales
Sales of natural gas, crude oil and NGLs produced or purchased in Canada delivered to customers outside of Canada were $757 million (2008 $1,874 million; 2007 $1,362 million).
Major Customers
In connection with the marketing and sale of EnCanas own and purchased natural gas and crude oil for the year ended December 31, 2009, the Company had one customer (2008 one; 2007 two) which individually accounted for more than 10 percent of EnCanas consolidated revenues, net of royalties. Sales to this customer, which has a high quality investment grade credit rating, were approximately $1,755 million (2008 $2,413 million; 2007 $3,461 million).
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
5. Joint Venture with ConocoPhillips
On January 2, 2007, EnCana became a 50 percent partner in an integrated, North American oil business with ConocoPhillips which consisted of an upstream and a downstream entity. The upstream entity contribution included assets from EnCana, primarily the Foster Creek and Christina Lake properties, with a fair value of $7.5 billion and a note receivable contributed from ConocoPhillips of an equal amount. For the downstream entity, ConocoPhillips contributed its Wood River and Borger refineries, located in Illinois and Texas, respectively, for a fair value of $7.5 billion, and EnCana contributed a note payable of $7.5 billion.
The joint venture arrangement with ConocoPhillips was transferred to Cenovus as part of the Split Transaction (See Note 3). The downstream operations have been disclosed as discontinued operations (See Note 6).
6. Discontinued Operations
DOWNSTREAM REFINING
As a result of the Split Transaction described in Note 3, EnCana transferred its downstream refining operations to Cenovus. Downstream refining focused on the refining of crude oil into petroleum and chemical products at two refineries located in the United States. These refineries were jointly owned with ConocoPhillips.
MIDSTREAM
The $75 million gain on discontinuance in 2007 is the result of an expired clause included in the December 2005 sale of the Companys Midstream natural gas liquids processing operations. The clause provided potential market price support for the facilities and was accrued for in 2005.
CONSOLIDATED STATEMENT OF EARNINGS
The following table presents the effect of the discontinued operations in the Consolidated Statement of Earnings:
|
|
Downstream Refining |
|
|
Midstream |
|
Consolidated Total |
|
|||||||||||||||
For the years ended December 31 |
|
2009 |
|
2008 |
|
2007 |
|
|
2007 |
|
2009 |
|
2008 |
|
2007 |
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Revenues, Net of Royalties |
|
$ |
4,804 |
|
$ |
9,011 |
|
$ |
7,315 |
|
|
$ |
- |
|
$ |
4,804 |
|
$ |
9,011 |
|
$ |
7,315 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Operating |
|
416 |
|
492 |
|
428 |
|
|
- |
|
416 |
|
492 |
|
428 |
|
|||||||
Purchased product |
|
4,070 |
|
8,760 |
|
5,813 |
|
|
- |
|
4,070 |
|
8,760 |
|
5,813 |
|
|||||||
Depreciation, depletion and amortization |
|
173 |
|
188 |
|
159 |
|
|
- |
|
173 |
|
188 |
|
159 |
|
|||||||
Administrative |
|
44 |
|
26 |
|
28 |
|
|
- |
|
44 |
|
26 |
|
28 |
|
|||||||
Interest, net |
|
163 |
|
184 |
|
194 |
|
|
- |
|
163 |
|
184 |
|
194 |
|
|||||||
Accretion of asset retirement obligation |
|
2 |
|
2 |
|
1 |
|
|
- |
|
2 |
|
2 |
|
1 |
|
|||||||
Foreign exchange (gain) loss, net |
|
1 |
|
- |
|
- |
|
|
- |
|
1 |
|
- |
|
- |
|
|||||||
(Gain) loss on divestitures |
|
- |
|
1 |
|
- |
|
|
(75 |
) |
- |
|
1 |
|
(75 |
) |
|||||||
|
|
4,869 |
|
9,653 |
|
6,623 |
|
|
(75 |
) |
4,869 |
|
9,653 |
|
6,548 |
|
|||||||
Net Earnings (Loss) Before Income Tax |
|
(65 |
) |
(642 |
) |
692 |
|
|
75 |
|
(65 |
) |
(642 |
) |
767 |
|
|||||||
Income tax expense (recovery) |
|
(97 |
) |
(87 |
) |
255 |
|
|
- |
|
(97 |
) |
(87 |
) |
255 |
|
|||||||
Net Earnings (Loss) From Discontinued Operations |
|
$ |
32 |
|
$ |
(555 |
) |
$ |
437 |
|
|
$ |
75 |
|
$ |
32 |
|
$ |
(555 |
) |
$ |
512 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Net Earnings (Loss) From Discontinued Operations per Common Share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Basic |
|
|
|
|
|
|
|
|
|
|
$ |
0.04 |
|
$ |
(0.74 |
) |
$ |
0.68 |
|
||||
Diluted |
|
|
|
|
|
|
|
|
|
|
$ |
0.04 |
|
$ |
(0.73 |
) |
$ |
0.67 |
|
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
CONSOLIDATED BALANCE SHEET
The following table presents the effect of the discontinued operations in the Consolidated Balance Sheet:
As at December 31 |
|
2009 |
|
2008 |
|
||
|
|
|
|
|
|
||
Assets |
|
|
|
|
|
||
Current Assets |
|
|
|
|
|
||
Cash and cash equivalents |
|
$ |
- |
|
$ |
29 |
|
Accounts receivable and accrued revenues |
|
- |
|
132 |
|
||
Inventories |
|
- |
|
336 |
|
||
|
|
- |
|
497 |
|
||
|
|
|
|
|
|
||
Property, Plant and Equipment, net |
|
- |
|
4,032 |
|
||
Investments and Other Assets |
|
- |
|
137 |
|
||
|
|
|
|
|
|
||
|
|
$ |
- |
|
$ |
4,666 |
|
|
|
|
|
|
|
||
Liabilities |
|
|
|
|
|
||
Current Liabilities |
|
|
|
|
|
||
Accounts payable and accrued liabilities |
|
$ |
- |
|
$ |
423 |
|
Income tax payable |
|
- |
|
(76 |
) |
||
Current portion of partnership contribution payable |
|
- |
|
306 |
|
||
|
|
- |
|
653 |
|
||
|
|
|
|
|
|
||
Partnership Contribution Payable |
|
- |
|
2,857 |
|
||
Asset Retirement Obligation |
|
- |
|
35 |
|
||
Future Income Taxes |
|
- |
|
2 |
|
||
|
|
- |
|
3,547 |
|
||
|
|
|
|
|
|
||
Net Assets of Discontinued Operations |
|
$ |
- |
|
$ |
1,119 |
|
7. Acquisitions and Divestitures
ACQUISITIONS
On May 5, 2009, the Company acquired the common shares of Kerogen Resources Canada, ULC for net cash consideration of $24 million. The acquisition included $37 million of property, plant and equipment and the assumption of $6 million of current liabilities and $7 million of future income taxes. The operations are included in the Canadian Division.
DIVESTITURES
For the years ended December 31 |
|
2009 |
|
2008 |
|
2007 |
|
|||
|
|
|
|
|
|
|
|
|||
Canadian Division |
|
$ |
1,000 |
|
$ |
400 |
|
$ |
213 |
|
Canada Other |
|
17 |
|
47 |
|
- |
|
|||
Canada |
|
1,017 |
|
447 |
|
213 |
|
|||
USA |
|
73 |
|
251 |
|
10 |
|
|||
Corporate & Other |
|
88 |
|
206 |
|
258 |
|
|||
|
|
$ |
1,178 |
|
$ |
904 |
|
$ |
481 |
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds received on the sale of assets and investments in 2009 were $1,178 million (2008 $904 million; 2007 $481 million). The significant items are described below.
Canada
In 2009, the Company completed the divestiture of mature conventional oil and natural gas assets for proceeds of $1,000 million (2008 $400 million; 2007 $213 million) in the Canadian Division and $17 million (2008 $47 million; 2007 nil) in Canada Other.
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
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 the Canadian Division.
USA
In 2009, the Company completed the divestiture of mature conventional natural gas assets for proceeds of $73 million (2008 $251 million; 2007 $10 million).
Corporate and Other
On November 3, 2009, the Company completed the sale of Senlac Oil Limited for cash consideration of $83 million.
In September 2008, the Company completed the sale of its interests in Brazil for net proceeds of $164 million, before closing adjustments, 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 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, largely representing its investment at the date of sale. Refer to Note 4 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
For the years ended December 31 |
|
2009 |
|
2008 |
|
2007 |
|
|||
|
|
|
|
|
|
|
|
|||
Interest Expense Long-Term Debt |
|
$ |
533 |
|
$ |
556 |
|
$ |
460 |
|
Interest Expense Other |
|
40 |
|
49 |
|
32 |
|
|||
Interest Income* |
|
(168 |
) |
(203 |
) |
(258 |
) |
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
405 |
|
$ |
402 |
|
$ |
234 |
|
|
|
|
|
|
|
|
|
|
|
|
* Interest Income is primarily due to the Partnership Contribution Receivable, which was transferred to Cenovus under the Split Transaction (See Notes 3 and 11).
9. Foreign Exchange (Gain) Loss, Net
For the years ended December 31 |
|
2009 |
|
2008 |
|
2007 |
|
|||
|
|
|
|
|
|
|
|
|||
Unrealized Foreign Exchange (Gain) Loss on: |
|
|
|
|
|
|
|
|||
Translation of U.S. dollar debt issued from Canada |
|
$ |
(978 |
) |
$ |
1,033 |
|
$ |
(683 |
) |
Translation of U.S. dollar partnership contribution receivable issued from Canada * |
|
448 |
|
(608 |
) |
617 |
|
|||
Other Foreign Exchange
(Gain) Loss on: |
|
508 |
|
(2 |
) |
(98 |
) |
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(22 |
) |
$ |
423 |
|
$ |
(164 |
) |
|
|
|
|
|
|
|
|
|
|
|
* The Partnership Contribution Receivable was transferred to Cenovus under the Split Transaction (See Notes 3 and 11).
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
10. Income Taxes
The provision for income taxes is as follows:
For the years ended December 31 |
|
2009 |
|
2008 |
|
2007 |
|
|||
|
|
|
|
|
|
|
|
|||
Current |
|
|
|
|
|
|
|
|||
Canada |
|
$ |
1,623 |
|
$ |
547 |
|
$ |
900 |
|
United States |
|
279 |
|
407 |
|
473 |
|
|||
Other Countries |
|
6 |
|
43 |
|
7 |
|
|||
Total Current Tax |
|
1,908 |
|
997 |
|
1,380 |
|
|||
Future |
|
(1,799 |
) |
1,723 |
|
(397 |
) |
|||
Future Tax Rate Reductions |
|
- |
|
- |
|
(301 |
) |
|||
|
|
|
|
|
|
|
|
|||
Total Future Tax |
|
(1,799 |
) |
1,723 |
|
(698 |
) |
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
109 |
|
$ |
2,720 |
|
$ |
682 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Included in current tax for 2008 is $25 million related to the sale of assets in Brazil (2009 nil; 2007 nil).
The following table reconciles income taxes calculated at the Canadian statutory rate with the actual income taxes: |
||||||||||
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31 |
|
2009 |
|
2008 |
|
2007 |
|
|||
|
|
|
|
|
|
|
|
|||
Net Earnings Before Income Tax |
|
$ |
1,939 |
|
$ |
9,219 |
|
$ |
4,129 |
|
Canadian Statutory Rate |
|
29.2% |
|
29.7% |
|
32.3% |
|
|||
Expected Income Tax |
|
566 |
|
2,734 |
|
1,334 |
|
|||
Effect on Taxes Resulting from: |
|
|
|
|
|
|
|
|||
Statutory and other rate differences |
|
(199 |
) |
167 |
|
41 |
|
|||
Effect of tax rate changes |
|
- |
|
- |
|
(301 |
) |
|||
Effect of legislative changes |
|
- |
|
- |
|
(179 |
) |
|||
International financing |
|
(101 |
) |
(268 |
) |
(62 |
) |
|||
Foreign exchange (gains) losses not included in net earnings |
|
20 |
|
47 |
|
- |
|
|||
Non-taxable capital (gains) losses |
|
(71 |
) |
84 |
|
(124 |
) |
|||
Other |
|
(106 |
) |
(44 |
) |
(27 |
) |
|||
|
|
$ |
109 |
|
$ |
2,720 |
|
$ |
682 |
|
|
|
|
|
|
|
|
|
|||
Effective Tax Rate |
|
5.6% |
|
29.5% |
|
16.5% |
|
|||
|
|
|
|
|
|
|
|
|||
The net future income tax liability consists of: |
||||||||||
|
|
|
|
|
|
|
|
|
|
|
As at December 31 |
|
2009 |
|
2008 |
|
|
|
|||
|
|
|
|
|
|
|
|
|||
Future Tax Liabilities |
|
|
|
|
|
|
|
|||
Property, plant and equipment in excess of tax values |
|
$ |
3,420 |
|
$ |
5,366 |
|
|
|
|
Timing of partnership items |
|
78 |
|
924 |
|
|
|
|||
Risk management |
|
75 |
|
955 |
|
|
|
|||
Future Tax Assets |
|
|
|
|
|
|
|
|||
Non-capital and net capital losses carried forward |
|
(174 |
) |
(46 |
) |
|
|
|||
Other |
|
(13 |
) |
(282 |
) |
|
|
|||
Net Future Income Tax Liability |
|
$ |
3,386 |
|
$ |
6,917 |
|
|
|
|
|
|
|
|
|
|
|
|
|||
The approximate amounts of tax pools available are as follows: |
||||||||||
|
|
|
|
|
|
|
|
|
|
|
As at December 31 |
|
2009 |
|
2008 |
|
|
|
|||
|
|
|
|
|
|
|
|
|||
Canada |
|
$ |
7,393 |
|
$ |
9,029 |
|
|
|
|
United States |
|
7,098 |
|
7,146 |
|
|
|
|||
|
|
$ |
14,491 |
|
$ |
16,175 |
|
|
|
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
Included in the above tax pools are $691 million (2008 $184 million) related to non-capital and net capital losses available for carry forward to reduce taxable income in future years. The non-capital losses expire between 2010 and 2029.
11. Partnership Contribution Receivable
On January 2, 2007, upon the creation of the Integrated Oil joint venture, ConocoPhillips entered into a subscription agreement for a 50 percent interest in the upstream entity in exchange for a promissory note of $7.5 billion. The note bears interest at a rate of 5.3 percent per annum. Equal payments of principal and interest are payable quarterly, with final payment due January 2, 2017. The current and long-term portions of the partnership contribution receivable shown in the 2008 Consolidated Balance Sheet represent EnCanas 50 percent share of this promissory note, net of payments to date. In conjunction with the Split Transaction, the current and long-term portions of the partnership contribution receivable were transferred to Cenovus (See Note 3).
12. Inventories
As at December 31 |
|
2009 |
|
2008 |
|
||
|
|
|
|
|
|
||
Product |
|
|
|
|
|
||
Canada |
|
$ |
4 |
|
$ |
46 |
|
USA |
|
6 |
|
8 |
|
||
Market Optimization |
|
2 |
|
127 |
|
||
Parts and Supplies |
|
- |
|
3 |
|
||
|
|
$ |
12 |
|
$ |
184 |
|
At December 31, 2009, there was no inventory impairment. As a result of a significant decline in commodity prices in the latter half of 2008, EnCana wrote down its product inventory by $57 million from cost to net realizable value. As at December 31, 2009, $47 million of the 2008 write down was reversed.
The total amount of inventories recognized as an expense during the year was $24 million (2008 $140 million).
13. Property, Plant and Equipment, Net
As at December 31 |
|
2009 |
|
2008 |
|
||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
|
|
|
Accumulated |
|
|
|
|
|
Accumulated |
|
|
|
||||||
|
|
Cost |
|
DD&A* |
|
Net |
|
Cost |
|
DD&A* |
|
Net |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Canada |
|
$ |
22,872 |
|
$ |
(11,710 |
) |
$ |
11,162 |
|
$ |
34,905 |
|
$ |
(17,407 |
) |
$ |
17,498 |
|
USA |
|
21,021 |
|
(7,092 |
) |
13,929 |
|
19,154 |
|
(5,511 |
) |
13,643 |
|
||||||
Market Optimization |
|
214 |
|
(90 |
) |
124 |
|
220 |
|
(80 |
) |
140 |
|
||||||
Corporate & Other |
|
1,396 |
|
(438 |
) |
958 |
|
1,245 |
|
(616 |
) |
629 |
|
||||||
|
|
$ |
45,503 |
|
$ |
(19,330 |
) |
$ |
26,173 |
|
$ |
55,524 |
|
$ |
(23,614 |
) |
$ |
31,910 |
|
* Depreciation, depletion and amortization.
Canada and USA property, plant and equipment include internal costs directly related to exploration, development and construction activities of $383 million (2008 $378 million). Costs classified as administrative expenses have not been capitalized as part of the capital expenditures.
Upstream costs in respect of significant unproved properties and major development projects are excluded from the country cost centres depletable base. At the end of the year, these costs were:
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
As at December 31 |
|
2009 |
|
2008 |
|
2007 |
|
|
|
|
|
|
|
|
|
Canada |
|
$ 1,814 |
|
$ 1,286 |
|
$ 1,721 |
|
United States |
|
1,304 |
|
3,501 |
|
1,887 |
|
Other Countries |
|
10 |
|
10 |
|
145 |
|
|
|
$ 3,128 |
|
$ 4,797 |
|
$ 3,753 |
|
The costs excluded from depletable costs in Other Countries represent costs related to unproved properties incurred in cost centres that are considered to be in the pre-production stage. Currently, there are no proved reserves in these cost centres. All costs, net of any associated revenues, in these cost centres have been capitalized. Ultimate recoverability of these costs will be dependent upon the finding of proved oil and natural gas reserves. For the year ended December 31, 2009, the Company completed its impairment review of pre-production cost centres and determined that $26 million of costs should be charged to depreciation, depletion and amortization in the Consolidated Statement of Earnings (2008 $38 million; 2007 $68 million).
The prices used in the ceiling test evaluation of the Companys natural gas and crude oil reserves at December 31, 2009 were:
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative |
|
|
|
|
|
|
|
|
|
|
|
|
|
% Change |
|
|
|
2010 |
|
2011 |
|
2012 |
|
2013 |
|
2014 |
|
to 2020 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas ($/Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
5.10 |
|
5.95 |
|
5.85 |
|
5.68 |
|
5.64 |
|
(1)% |
|
United States |
|
5.37 |
|
6.42 |
|
6.45 |
|
6.48 |
|
6.50 |
|
2% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil ($/barrel) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
65.42 |
|
67.06 |
|
68.30 |
|
67.02 |
|
66.69 |
|
(1)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids ($/barrel) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
67.44 |
|
67.30 |
|
66.43 |
|
68.60 |
|
67.18 |
|
1% |
|
United States |
|
66.69 |
|
66.48 |
|
66.54 |
|
66.71 |
|
66.67 |
|
- |
|
14. |
Investments and Other Assets |
As at December 31 |
|
|
|
|
2009 |
|
|
|
2008 |
|
||
|
|
|
|
|
|
|
|
|
|
|
||
Long-Term Receivable |
|
|
|
|
$ |
81 |
|
|
|
$ |
- |
|
Deferred Pension Plan and Savings Plan |
|
|
|
|
52 |
|
|
|
59 |
|
||
Other |
|
|
|
|
31 |
|
|
|
13 |
|
||
|
|
|
|
|
$ |
164 |
|
|
|
$ |
72 |
|
15. |
Long-Term Debt |
As at December 31 |
|
Note |
|
|
2009 |
|
|
|
2008 |
|
||
|
|
|
|
|
|
|
|
|
|
|
||
Canadian Dollar Denominated Debt |
|
|
|
|
|
|
|
|
|
|
||
Revolving credit and term loan borrowings |
|
B |
|
|
$ |
- |
|
|
|
$ |
1,410 |
|
Unsecured notes |
|
C |
|
|
1,194 |
|
|
|
1,020 |
|
||
|
|
|
|
|
1,194 |
|
|
|
2,430 |
|
||
U.S. Dollar Denominated Debt |
|
|
|
|
|
|
|
|
|
|
||
Revolving credit and term loan borrowings |
|
D |
|
|
- |
|
|
|
247 |
|
||
Unsecured notes |
|
E |
|
|
6,600 |
|
|
|
6,350 |
|
||
|
|
|
|
|
6,600 |
|
|
|
6,597 |
|
||
|
|
|
|
|
|
|
|
|
|
|
||
Increase in Value of Debt Acquired |
|
F |
|
|
52 |
|
|
|
49 |
|
||
Debt Discounts and Financing Costs |
|
G |
|
|
(78 |
) |
|
|
(71 |
) |
||
Current Portion of Long-Term Debt |
|
H |
|
|
(200 |
) |
|
|
(250 |
) |
||
|
|
|
|
|
$ |
7,568 |
|
|
|
$ |
8,755 |
|
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
A) OVERVIEW
REVOLVING CREDIT AND TERM LOAN BORROWINGS
At December 31, 2009, EnCana had in place a revolving credit facility for C$4.5 billion or its equivalent amount in U.S. dollars ($4.3 billion). The facility, which matures in October 2012, is fully revolving up to maturity. The facility is extendible from time to time, but not more than once per year, for a period not longer than five years plus 90 days from the date of the extension request, at the option of the lenders and upon notice from EnCana. The facility is unsecured and bears interest at the lenders rates for Canadian prime, U.S. base rate, Bankers Acceptances rates plus applicable margins, or at LIBOR plus applicable margins.
At December 31, 2009, one of EnCanas subsidiaries had in place a credit facility totalling $565 million. The facility, which matures in February 2013, is guaranteed by EnCana Corporation and is fully revolving up to maturity. The facility is extendible from time to time, but not more than once per year, for a period not longer than five years plus 90 days from the date of the extension request, at the option of the lenders and upon notice from the subsidiary. This facility bears interest at either the lenders U.S. base rate or at LIBOR plus applicable margins.
Standby fees paid in 2009 relating to revolving credit and term loan agreements were approximately $4 million (2008 $4 million; 2007 $4 million).
UNSECURED NOTES
Unsecured notes include medium-term notes and senior notes that are issued from time to time under trust indentures.
EnCana has in place a debt shelf prospectus for Canadian unsecured medium-term notes in the amount of C$2.0 billion. The shelf prospectus provides that debt securities in Canadian dollars or other foreign currencies may be issued from time to time in one or more series. Terms of the notes, including interest at either fixed or floating rates and maturity dates, are determined by reference to market conditions at the date of issue. The shelf prospectus was filed in May 2009 and expires in June 2011. At December 31, 2009, C$2.0 billion ($1.9 billion) of the shelf prospectus remained unutilized, the availability of which is dependent upon market conditions.
EnCana has in place a debt shelf prospectus for U.S. unsecured notes in the amount of $4.0 billion under the multijurisdictional disclosure system (MJDS). The shelf prospectus provides that debt securities in U.S. dollars or other foreign currencies may be issued from time to time in one or more series. Terms of the notes, including interest at either fixed or floating rates and maturity dates, are determined by reference to market conditions at the date of issue. The shelf prospectus was filed in March 2008 and expires in April 2010. At December 31, 2009, $3.5 billion of the shelf prospectus remained unutilized, the availability of which is dependent upon market conditions.
B) CANADIAN REVOLVING CREDIT AND TERM LOAN BORROWINGS
|
|
C$ Principal Amount |
|
2009 |
|
2008 |
|
||||||
|
|
|
|
|
|
|
|
||||||
Bankers Acceptances |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
902 |
|
Commercial Paper |
|
|
- |
|
|
- |
|
|
508 |
|
|||
|
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
1,410 |
|
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
C) CANADIAN UNSECURED NOTES
|
|
C$ Principal Amount |
|
2009 |
|
2008 |
|
||||||
|
|
|
|
|
|
|
|
||||||
4.30% due March 12, 2012 |
|
|
$ |
500 |
|
|
$ |
478 |
|
|
$ |
408 |
|
5.80% due January 18, 2018 |
|
|
750 |
|
|
716 |
|
|
612 |
|
|||
|
|
|
$ |
1,250 |
|
|
$ |
1,194 |
|
|
$ |
1,020 |
|
D) U.S. REVOLVING CREDIT AND TERM LOAN BORROWINGS
|
|
|
|
|
2009 |
|
|
2008 |
|
||
|
|
|
|
|
|
|
|
|
|
||
|
|
|
|
|
$ |
- |
|
|
$ |
184 |
|
LIBOR |
|
|
|
|
- |
|
|
63 |
|
||
Commercial Paper |
|
|
|
|
$ |
- |
|
|
$ |
247 |
|
E) U.S. UNSECURED NOTES
|
|
|
|
|
2009 |
|
|
2008 |
|
||
|
|
|
|
|
|
|
|
|
|
||
4.60% due August 15, 2009 |
|
|
|
|
$ |
- |
|
|
$ |
250 |
|
7.65% due September 15, 2010 |
|
|
|
|
200 |
|
|
200 |
|
||
6.30% due November 1, 2011 |
|
|
|
|
500 |
|
|
500 |
|
||
4.75% due October 15, 2013 |
|
|
|
|
500 |
|
|
500 |
|
||
5.80% due May 1, 2014 |
|
|
|
|
1,000 |
|
|
1,000 |
|
||
5.90% due December 1, 2017 |
|
|
|
|
700 |
|
|
700 |
|
||
6.50% due May 15, 2019 |
|
|
|
|
500 |
|
|
- |
|
||
8.125% due September 15, 2030 |
|
|
|
|
300 |
|
|
300 |
|
||
7.20% due November 1, 2031 |
|
|
|
|
350 |
|
|
350 |
|
||
7.375% due November 1, 2031 |
|
|
|
|
500 |
|
|
500 |
|
||
6.50% due August 15, 2034 |
|
|
|
|
750 |
|
|
750 |
|
||
6.625% due August 15, 2037 |
|
|
|
|
500 |
|
|
500 |
|
||
6.50% due February 1, 2038 |
|
|
|
|
800 |
|
|
800 |
|
||
|
|
|
|
|
$ |
6,600 |
|
|
$ |
6,350 |
|
On May 4, 2009, EnCana completed a public offering in the United States of senior unsecured notes in the aggregate principal amount of US$500 million. The notes have a coupon rate of 6.5 percent and mature on May 15, 2019. The net proceeds of the offering were used to repay a portion of EnCanas bank and commercial paper indebtedness.
The 5.80% note due May 1, 2014 was issued by the Companys indirect wholly owned subsidiary, EnCana Holdings Finance Corp. This note is fully and unconditionally guaranteed by EnCana Corporation.
F) INCREASE IN VALUE OF DEBT ACQUIRED
Certain of the notes and debentures of the Company 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.
G) DEBT DISCOUNTS AND TRANSACTION COSTS
Long-term debt transaction costs, premiums and discounts are capitalized within long-term debt and are being amortized using the effective interest method. During 2009, $4 million (2008 $5 million) in transaction costs and discounts have been capitalized within long-term debt relating to the issuance of Canadian and U.S. unsecured notes.
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
H) CURRENT PORTION OF LONG-TERM DEBT
|
|
|
|
|
2009 |
|
|
2008 |
|
||
|
|
|
|
|
|
|
|
|
|
||
4.60% due August 15, 2009 |
|
|
|
|
$ |
- |
|
|
$ |
250 |
|
7.65% due September 15, 2010 |
|
|
|
|
200 |
|
|
- |
|
||
|
|
|
|
|
$ |
200 |
|
|
$ |
250 |
|
I) MANDATORY DEBT PAYMENTS
|
|
C$ Principal |
|
US$ Principal |
|
Total US$ |
|
||||||
|
|
|
|
|
|
|
|
||||||
2010 |
|
|
$ |
- |
|
|
$ |
200 |
|
|
$ |
200 |
|
2011 |
|
|
- |
|
|
500 |
|
|
500 |
|
|||
2012 |
|
|
500 |
|
|
- |
|
|
478 |
|
|||
2013 |
|
|
- |
|
|
500 |
|
|
500 |
|
|||
2014 |
|
|
- |
|
|
1,000 |
|
|
1,000 |
|
|||
Thereafter |
|
|
750 |
|
|
4,400 |
|
|
5,116 |
|
|||
Total |
|
|
$ |
1,250 |
|
|
$ |
6,600 |
|
|
$ |
7,794 |
|
16. |
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:
As at December 31 |
|
|
|
|
2009 |
|
|
2008 |
|
||
|
|
|
|
|
|
|
|
|
|
||
Asset Retirement Obligation, Beginning of Year |
|
|
|
|
$ |
1,230 |
|
|
$ |
1,437 |
|
Liabilities Incurred |
|
|
|
|
21 |
|
|
54 |
|
||
Liabilities Settled |
|
|
|
|
(52 |
) |
|
(110 |
) |
||
Liabilities Divested |
|
|
|
|
(26 |
) |
|
(38 |
) |
||
Liabilities Transferred to Cenovus |
|
|
|
|
(692 |
) |
|
- |
|
||
Change in Estimated Future Cash Outflows |
|
|
|
|
74 |
|
|
37 |
|
||
Accretion Expense |
|
|
|
|
71 |
|
|
77 |
|
||
Foreign Currency Translation |
|
|
|
|
161 |
|
|
(227 |
) |
||
Asset Retirement Obligation, End of Year |
|
|
|
|
$ |
787 |
|
|
$ |
1,230 |
|
The total undiscounted amount of estimated cash flows required to settle the obligation is $3,792 million (2008 $6,569 million), which has been discounted using a weighted average credit-adjusted risk free rate of 6.38 percent (2008 6.04 percent). Most of these obligations are not expected to be paid for several years, or decades, in the future and will be funded from general Company resources at that time.
17. |
Share Capital |
AUTHORIZED
The Company is authorized to issue an unlimited number of Common Shares, an unlimited number of First Preferred Shares and an unlimited number of Second Preferred Shares.
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
ISSUED AND OUTSTANDING
As at December 31 |
|
2009 |
|
2008 |
|
||||||||
|
|
|
|
|
|
|
|
|
|
||||
|
|
Number |
|
Amount |
|
Number |
|
Amount |
|
||||
|
|
|
|
|
|
|
|
|
|
||||
Common Shares Outstanding, Beginning of Year |
|
750.4 |
|
|
$ |
4,557 |
|
750.2 |
|
$ |
4,479 |
|
|
Common Shares Issued under Option Plans |
|
0.4 |
|
|
5 |
|
3.0 |
|
80 |
|
|||
Common Shares Issued from PSU Trust |
|
0.5 |
|
|
19 |
|
- |
|
- |
|
|||
Stock-Based Compensation |
|
- |
|
|
1 |
|
- |
|
11 |
|
|||
Common Shares Purchased |
|
- |
|
|
- |
|
(2.8 |
) |
(13 |
) |
|||
Common Shares Cancelled |
(Note 3) |
|
(751.3 |
) |
|
(4,582 |
) |
- |
|
- |
|
||
New EnCana Common Shares Issued |
(Note 3) |
|
751.3 |
|
|
2,360 |
|
- |
|
- |
|
||
EnCana Special Shares Issued |
(Note 3) |
|
751.3 |
|
|
2,222 |
|
- |
|
- |
|
||
EnCana Special Shares Cancelled |
(Note 3) |
|
(751.3 |
) |
|
(2,222 |
) |
- |
|
- |
|
||
Common Shares Outstanding, End of Year |
|
|
751.3 |
|
|
$ |
2,360 |
|
750.4 |
|
$ |
4,557 |
|
PERFORMANCE SHARE UNITS
In April 2009, the remaining 0.5 million Common Shares held in trust relating to EnCanas Performance Share Unit (PSU) plan were sold for total consideration of $25 million. Of the amount received, $19 million was credited to Share capital and $6 million to Paid in surplus, representing the excess consideration received over the original price of the Common Shares acquired by the trust. Effective May 15, 2009, the trust agreement was terminated.
NORMAL COURSE ISSUER BID
EnCana has received regulatory approval each year under Canadian securities laws to purchase Common Shares under eight consecutive Normal Course Issuer Bids (Bids). EnCana is entitled to purchase, for cancellation, up to 37.5 million Common Shares under the renewed Bid which commenced on December 14, 2009 and terminates on December 13, 2010. During 2009, there were no purchases under the current or prior Bids.
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 EnCanas Performance Share Unit Plan (See Note 19). For these Common Shares distributed, there was a $54 million adjustment to Retained earnings with a reduction to Paid in surplus of $70 million.
STOCK OPTIONS
EnCana has stock-based compensation plans that allow employees to purchase Common Shares of the Company. Option exercise prices approximate the market price for the Common Shares on the date the options were granted. Options granted under the plans are generally fully exercisable after three years and expire five years after the date granted. Options granted under predecessor and/or related company replacement plans expire up to 10 years from the date the options were granted. All options issued subsequent to December 31, 2003 have an associated Tandem Share Appreciation Right (TSAR) attached to them (See Note 19).
ENCANA PLAN
Pursuant to the terms of a stock option plan, options may be granted to certain key employees to purchase EnCana Common Shares. Options granted are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years, are fully exercisable after three years and expire five years after the date granted. In addition, certain stock options granted since 2007 are performance based. The performance based stock options vest and expire under the same terms and service conditions as the
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
underlying option, and vesting is subject to EnCana attaining prescribed performance relative to pre-determined key measures (See Note 19).
CANADIAN PACIFIC LIMITED REPLACEMENT PLAN
As part of the 2001 reorganization of Canadian Pacific Limited (CPL), EnCanas former parent company, CPL stock options were replaced with stock options granted by the Company in a manner that was consistent with the provisions of the CPL stock option plan. Under CPLs stock option plan, options were granted to certain key employees to purchase Common Shares of CPL at a price not less than the market value of the shares at the grant date. The options expire 10 years after the grant date and are all exercisable.
As at December 31, 2009, EnCana had 0.2 million stock options (2008 - 0.5 million) outstanding and exercisable with a weighted average exercise price of C$6.25 per stock option (2008 - C$11.62). The weighted average remaining contractual life of the stock options is 0.2 years. These stock options do not have TSARs attached.
At December 31, 2009, there were 9.6 million Common Shares reserved for issuance under stock option plans (2008 16.5 million; 2007 12.2 million).
At December 31, 2009, the balance in Paid in surplus relates to stock-based compensation programs.
ENCANA REPLACEMENT SHARE UNITS HELD BY CENOVUS EMPLOYEES
The share units described below include TSARs, Performance TSARs, Share Appreciation Rights ("SARs") and Performance SARs.
As part of the Split Transaction, on November 30, 2009, each holder of EnCana share units disposed of their right in exchange for the grant of EnCana Replacement share units and Cenovus Replacement share units. The terms and conditions of the Replacement share units are similar to the terms and conditions of the original share units.
Refer to Note 19 for information regarding share units and Replacement share units held by EnCana employees.
With respect to EnCana Replacement share units held by Cenovus employees and Cenovus Replacement share units held by EnCana employees, both EnCana and Cenovus have agreed to reimburse each other for share units exercised for cash by their respective employees. Accordingly, for EnCana Replacement share units held by Cenovus employees, EnCana has recorded a payable to Cenovus employees and a receivable due from Cenovus. The payable to Cenovus employees and the receivable due from Cenovus is based on the fair value of the EnCana Replacement share units determined using the Black-Scholes-Merton model (See Note 20). There is no impact on EnCana's net earnings for these share units held by Cenovus employees. No further EnCana Replacement share units will be granted to Cenovus employees.
As Cenovus employees may exercise EnCana Replacement TSARs and EnCana Replacement Performance TSARs in exchange for EnCana Common Shares, the following table is provided as at December 31, 2009.
As at December 31 |
|
2009 |
|
||
|
|
Number of |
|
Weighted |
|
Canadian Dollar Denominated (C$) |
|
|
|
|
|
EnCana Replacement TSARs held by Cenovus Employees |
|
|
|
|
|
Outstanding, End of Year |
|
8.3 |
|
29.36 |
|
Exercisable, End of Year |
|
4.6 |
|
27.22 |
|
|
|
|
|
|
|
EnCana Replacement Performance TSARs held by Cenovus Employees |
|
|
|
|
|
Outstanding, End of Year |
|
8.1 |
|
31.58 |
|
Exercisable, End of Year |
|
1.5 |
|
32.03 |
|
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
PER SHARE AMOUNTS
The following table summarizes the Common Shares used in calculating Net Earnings per Common Share:
For the years ended December 31 (in millions) |
|
2009 |
|
2008 |
|
2007 |
|
|
|
|
|
|
|
|
|
Weighted Average Common Shares Outstanding Basic |
|
751.0 |
|
750.1 |
|
756.8 |
|
Effect of Stock Options and Other Dilutive Securities |
|
0.4 |
|
1.7 |
|
7.8 |
|
Weighted Average Common Shares Outstanding Diluted |
|
751.4 |
|
751.8 |
|
764.6 |
|
18. |
Capital Structure |
The Companys capital structure consists of Shareholders Equity plus Long-Term Debt, defined as the current and long-term portions of long-term debt. The Companys objectives when managing its capital structure are to:
i) |
maintain financial flexibility to preserve EnCanas 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 (Adjusted EBITDA). These metrics are used to steward the Companys overall debt position as measures of the Companys overall financial strength.
EnCana targets a Debt to Capitalization ratio of less than 40 percent. At December 31, 2009, EnCanas Debt to Capitalization ratio was 32 percent (December 31, 2008 28 percent) calculated as follows:
As at December 31 |
|
2009 |
|
|
2008 |
|
||||
|
|
|
|
|
|
|
|
|
||
Debt |
|
|
$ |
7,768 |
|
|
|
$ |
9,005 |
|
Total Shareholders Equity |
|
|
16,614 |
|
|
|
22,974 |
|
||
Total Capitalization |
|
|
$ |
24,382 |
|
|
|
$ |
31,979 |
|
Debt to Capitalization Ratio |
|
|
32% |
|
|
|
28% |
|
EnCana targets a Debt to Adjusted EBITDA of less than 2.0 times. At December 31, 2009, Debt to Adjusted EBITDA was 1.3x (December 31, 2008 0.6x; December 31, 2007 1.2x) calculated on a trailing 12-month basis as follows:
As at December 31 |
|
2009 |
|
2008 |
|
|
2007 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
||||
Debt |
|
|
$ |
7,768 |
|
|
$ |
9,005 |
|
|
|
$ |
9,543 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Net Earnings from Continuing Operations |
|
|
1,830 |
|
|
6,499 |
|
|
|
3,447 |
|
|||
Add (deduct): |
|
|
|
|
|
|
|
|
|
|
|
|||
Interest, net |
|
|
405 |
|
|
402 |
|
|
|
234 |
|
|||
Income tax expense |
|
|
109 |
|
|
2,720 |
|
|
|
682 |
|
|||
Depreciation, depletion and amortization |
|
|
3,704 |
|
|
4,035 |
|
|
|
3,657 |
|
|||
Accretion of asset retirement obligation |
|
|
71 |
|
|
77 |
|
|
|
63 |
|
|||
Foreign exchange (gain) loss, net |
|
|
(22 |
) |
|
423 |
|
|
|
(164 |
) |
|||
(Gain) loss on divestitures |
|
|
2 |
|
|
(141 |
) |
|
|
(65 |
) |
|||
Adjusted EBITDA |
|
|
$ |
6,099 |
|
|
$ |
14,015 |
|
|
|
$ |
7,854 |
|
Debt to Adjusted EBITDA |
|
|
1.3x |
|
|
0.6x |
|
|
|
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
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
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 and definitions have remained unchanged over the periods presented. EnCana is subject to certain financial covenants in its credit facility agreements and is in compliance with all financial covenants.
19. |
Compensation Plans |
As part of the Split Transaction, each holder of EnCana share units disposed of their right in exchange for the grant of EnCana Replacement share units and Cenovus Replacement share units. The terms and conditions of the Replacement share units are similar to the terms and conditions of the original share units. Share units include TSARs, Performance TSARs, SARs and Performance SARs.
The original exercise price of the share units was apportioned to the EnCana and Cenovus Replacement share units based on a valuation methodology that included the weighted average trading price of the New EnCana Common Shares and the weighted average trading price of the Cenovus Common Shares on the Toronto Stock Exchange (TSX) on a "when issued" basis on December 2, 2009.
For EnCana Replacement share units held by EnCana employees, EnCana accrues compensation cost over the vesting period based on the intrinsic method of accounting.
For Cenovus Replacement share units held by EnCana employees, EnCana accrues compensation cost over the vesting period based on the fair value of the Cenovus Replacement share units. The fair value of the Cenovus Replacement share units is determined using the Black-Scholes-Merton model. At December 31, 2009, the fair value was estimated using the following weighted average assumptions: risk free rate of 1.46 percent, dividend yield of 3.16 percent, volatility of 34.18 percent and Cenovus closing market share price of C$26.50 (See Note 20). No further Cenovus Replacement share units will be granted to EnCana employees.
Refer to Note 17 for information regarding EnCana Replacement share units held by Cenovus employees.
A) TANDEM SHARE APPRECIATION RIGHTS
Subsequent to December 31, 2003, all options to purchase Common Shares issued under the share option plans described in Note 17 have an associated TSAR attached to them whereby the option holder has the right to receive a cash payment equal to the excess of the market price of EnCanas Common Shares at the time of exercise over the exercise price of the right in lieu of exercising the option. The TSARs vest and expire under the same terms and conditions as the underlying option.
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
The following table summarizes information related to the TSARs:
As at December 31 |
|
2009 |
|
2008 |
|
||||||
|
|
|
|
|
|
|
|
||||
|
|
|
|
Outstanding |
|
Weighted |
|
Outstanding |
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Dollar Denominated (C$) |
|
|
|
|
|
|
|
|
|
|
|
Outstanding, Beginning of Year |
|
|
|
19,411,939 |
|
53.97 |
|
18,854,141 |
|
48.44 |
|
Granted |
|
|
|
4,030,680 |
|
55.39 |
|
4,420,272 |
|
70.11 |
|
Exercised SARs |
|
|
|
(1,994,556 |
) |
42.65 |
|
(3,173,443 |
) |
43.68 |
|
Exercised Options |
|
|
|
(60,914 |
) |
34.89 |
|
(82,936 |
) |
42.00 |
|
Forfeited |
|
|
|
(452,606 |
) |
60.11 |
|
(606,095 |
) |
55.27 |
|
Exchanged for Replacement TSARs |
|
|
|
(20,934,543 |
) |
55.25 |
|
- |
|
- |
|
Outstanding, End of Year |
|
|
|
- |
|
- |
|
19,411,939 |
|
53.97 |
|
Exercisable, End of Year |
|
|
|
- |
|
- |
|
8,452,111 |
|
46.45 |
|
The following table summarizes information related to the EnCana and Cenovus Replacement TSARs held by EnCana employees at December 31, 2009:
As at December 31, 2009 |
|
EnCana TSARs |
|
Cenovus TSARs |
|
||||||
|
|
|
|
|
|
|
|
||||
|
|
|
|
Outstanding |
|
Weighted |
|
Outstanding |
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Dollar Denominated (C$) |
|
|
|
|
|
|
|
|
|
|
|
Replacement TSARs exchanged November 30, 2009 |
|
|
|
12,556,585 |
|
28.83 |
|
12,556,585 |
|
26.07 |
|
Granted |
|
|
|
12,775 |
|
29.96 |
|
- |
|
- |
|
Exercised SARs |
|
|
|
(54,075 |
) |
21.26 |
|
(29,840 |
) |
18.57 |
|
Exercised Options |
|
|
|
(206 |
) |
22.65 |
|
(1,206 |
) |
16.77 |
|
Forfeited |
|
|
|
(41,865 |
) |
33.46 |
|
(42,845 |
) |
30.17 |
|
Outstanding, End of Year |
|
|
|
12,473,214 |
|
28.85 |
|
12,482,694 |
|
26.08 |
|
Exercisable, End of Year |
|
|
|
7,713,376 |
|
26.94 |
|
7,735,631 |
|
24.35 |
|
As at December 31, 2009 |
|
Outstanding EnCana TSARs |
|
Exercisable EnCana TSARs |
|
||||||
Range of Exercise Price (C$) |
|
Number of |
|
Weighted |
|
Weighted |
|
Number of |
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
|
|
10.00 to 19.99 |
|
8,940 |
|
0.09 |
|
19.35 |
|
8,940 |
|
19.35 |
|
20.00 to 29.99 |
|
9,367,727 |
|
1.89 |
|
26.54 |
|
6,423,436 |
|
25.36 |
|
30.00 to 39.99 |
|
2,929,747 |
|
2.87 |
|
35.34 |
|
1,230,960 |
|
34.53 |
|
40.00 to 49.99 |
|
165,300 |
|
3.39 |
|
44.36 |
|
49,590 |
|
44.36 |
|
50.00 to 59.99 |
|
1,500 |
|
3.39 |
|
50.39 |
|
450 |
|
50.39 |
|
|
|
12,473,214 |
|
2.14 |
|
28.85 |
|
7,713,376 |
|
26.94 |
|
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
As at December 31, 2009 |
|
Outstanding Cenovus TSARs |
|
Exercisable Cenovus TSARs |
|
||||||
Range of Exercise Price (C$) |
|
Number of |
|
Weighted |
|
Weighted |
|
Number of |
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
|
|
10.00 to 19.99 |
|
1,097,538 |
|
0.13 |
|
18.21 |
|
1,097,538 |
|
18.21 |
|
20.00 to 29.99 |
|
8,781,794 |
|
2.11 |
|
24.96 |
|
5,724,948 |
|
24.16 |
|
30.00 to 39.99 |
|
2,521,012 |
|
3.05 |
|
32.85 |
|
888,440 |
|
32.63 |
|
40.00 to 49.99 |
|
82,350 |
|
3.44 |
|
42.82 |
|
24,705 |
|
42.82 |
|
|
|
12,482,694 |
|
2.14 |
|
26.08 |
|
7,735,631 |
|
24.35 |
|
During the year, the Company recorded compensation costs of $5 million related to the outstanding TSARs prior to the Split Transaction, $11 million related to the EnCana Replacement TSARs and $46 million related to the Cenovus Replacement TSARs (2008 reduction of compensation costs of $47 million; 2007 compensation costs of $225 million).
B) PERFORMANCE TANDEM SHARE APPRECIATION RIGHTS
Beginning in 2007, under the terms of the existing Employee Stock Option Plan, EnCana granted Performance Tandem Share Appreciation Rights (Performance TSARs) under which the employee has the right to receive a cash payment equal to the excess of the market price of EnCana Common Shares at the time of exercise over the grant price. Performance TSARs vest and expire under the same terms and service conditions as the underlying option, and vesting is subject to EnCana attaining prescribed performance relative to key predetermined measures. Performance TSARs that do not vest when eligible are forfeited.
The following tables summarize information related to the Performance TSARs:
As at December 31 |
|
2009 |
|
2008 |
|
||||||
|
|
|
|
|
|
|
|
||||
|
|
|
|
Outstanding |
|
Weighted |
|
Outstanding |
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Dollar Denominated (C$) |
|
|
|
|
|
|
|
|
|
|
|
Outstanding, Beginning of Year |
|
|
|
12,979,725 |
|
63.13 |
|
6,930,925 |
|
56.09 |
|
Granted |
|
|
|
7,751,720 |
|
55.31 |
|
7,058,538 |
|
69.40 |
|
Exercised SARs |
|
|
|
(144,707 |
) |
56.09 |
|
(287,299 |
) |
56.09 |
|
Exercised Options |
|
|
|
(980 |
) |
56.09 |
|
(5,123 |
) |
56.09 |
|
Forfeited |
|
|
|
(2,041,565 |
) |
62.64 |
|
(717,316 |
) |
59.65 |
|
Exchanged for Replacement Performance TSARs |
|
|
|
(18,544,193 |
) |
59.97 |
|
- |
|
- |
|
Outstanding, End of Year |
|
|
|
- |
|
- |
|
12,979,725 |
|
63.13 |
|
Exercisable, End of Year |
|
|
|
- |
|
- |
|
1,461,276 |
|
56.09 |
|
As at December 31, 2009 |
|
EnCana Performance TSARs |
|
Cenovus Performance TSARs |
|
||||||
|
|
|
|
|
|
|
|
||||
|
|
|
|
Outstanding |
|
Weighted |
|
Outstanding |
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Dollar Denominated (C$) |
|
|
|
|
|
|
|
|
|
|
|
Replacement Performance TSARs exchanged November 30, 2009 |
|
|
|
10,491,119 |
|
31.42 |
|
10,491,119 |
|
28.42 |
|
Exercised SARs |
|
|
|
(2,070 |
) |
29.45 |
|
- |
|
- |
|
Forfeited |
|
|
|
(27,148 |
) |
31.59 |
|
(28,476 |
) |
28.49 |
|
Outstanding, End of Year |
|
|
|
10,461,901 |
|
31.42 |
|
10,462,643 |
|
28.42 |
|
Exercisable, End of Year |
|
|
|
2,235,899 |
|
31.55 |
|
2,236,641 |
|
28.54 |
|
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
As at December 31, 2009 |
|
Outstanding EnCana Performance |
|
Exercisable EnCana Performance |
|
||||||
|
|
|
|
|
|
||||||
Range of Exercise Price (C$) |
|
Number of |
|
Weighted |
|
Weighted |
|
Number of |
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
|
|
20.00 to 29.99 |
|
7,279,507 |
|
3.24 |
|
29.22 |
|
1,563,005 |
|
29.45 |
|
30.00 to 39.99 |
|
3,182,394 |
|
3.12 |
|
36.44 |
|
672,894 |
|
36.44 |
|
|
|
10,461,901 |
|
3.21 |
|
31.42 |
|
2,235,899 |
|
31.55 |
|
As at December 31, 2009 |
|
Outstanding Cenovus Performance |
|
Exercisable Cenovus Performance |
|
||||||
|
|
|
|
|
|
||||||
Range of Exercise Price (C$) |
|
Number of |
|
Weighted |
|
Weighted |
|
Number of |
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
|
|
20.00 to 29.99 |
|
7,280,249 |
|
3.24 |
|
26.43 |
|
1,563,747 |
|
26.64 |
|
30.00 to 39.99 |
|
3,182,394 |
|
3.12 |
|
32.96 |
|
672,894 |
|
32.96 |
|
|
|
10,462,643 |
|
3.21 |
|
28.42 |
|
2,236,641 |
|
28.54 |
|
During the year, EnCana recorded compensation costs of $4 million related to the outstanding Performance TSARs prior to the Split Transaction, $20 million related to the EnCana Replacement Performance TSARs and $19 million related to the Cenovus Replacement Performance TSARs (2008 a reduction of compensation costs of $6 million; 2007 compensation costs of $21 million).
C) SHARE APPRECIATION RIGHTS
EnCana has a program whereby employees may be granted SARs which entitle the employee to receive a cash payment equal to the excess of the market price of EnCanas Common Shares at the time of exercise over the exercise price of the right. SARs granted during 2009 and 2008 are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years and are fully exercisable after three years and expire five years after the grant date.
The following tables summarize information related to the SARs:
As at December 31 |
|
2009 |
|
2008 |
|
||||||
|
|
|
|
|
|
|
|
||||
|
|
Outstanding |
|
Weighted |
|
Outstanding |
|
Weighted |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Dollar Denominated (C$) |
|
|
|
|
|
|
|
|
|
|
|
Outstanding, Beginning of Year |
|
|
|
1,285,065 |
|
72.13 |
|
- |
|
- |
|
Granted |
|
|
|
1,126,850 |
|
55.48 |
|
1,314,115 |
|
72.07 |
|
Exercised SARs |
|
|
|
(990 |
) |
43.50 |
|
- |
|
- |
|
Forfeited |
|
|
|
(60,365 |
) |
66.64 |
|
(29,050 |
) |
69.42 |
|
Exchanged for Replacement SARs |
|
|
|
(2,350,560 |
) |
64.30 |
|
- |
|
- |
|
Outstanding, End of Year |
|
|
|
- |
|
- |
|
1,285,065 |
|
72.13 |
|
Exercisable, End of Year |
|
|
|
- |
|
- |
|
- |
|
- |
|
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
As at December 31, 2009 |
|
EnCana SARs |
|
Cenovus SARs |
|
||||||||
|
|
|
|
|
|
|
|
|
|
||||
|
|
Outstanding |
|
Weighted |
|
Outstanding |
|
Weighted |
|
||||
|
|
|
|
|
|
|
|
|
|
||||
Canadian Dollar Denominated (C$) |
|
|
|
|
|
|
|
|
|
||||
Replacement SARs exchanged November 30, 2009 |
|
2,329,835 |
|
33.78 |
|
2,329,835 |
|
30.55 |
|
||||
Granted |
|
19,525 |
|
29.87 |
|
- |
|
- |
|
||||
Forfeited |
|
(5,875 |
) |
32.24 |
|
(5,875 |
) |
29.17 |
|
||||
Outstanding, End of Year |
|
2,343,485 |
|
33.75 |
|
2,323,960 |
|
30.55 |
|
||||
Exercisable, End of Year |
|
370,438 |
|
37.93 |
|
370,438 |
|
34.30 |
|
||||
|
|
|
|
|
|
|
|
|
|
||||
|
|
|
|
|
|
|
|
|
|
||||
As at December 31, 2009 |
|
Outstanding EnCana SARs |
|
Exercisable EnCana SARs |
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|
||
Range of Exercise Price (C$) |
|
Number of |
|
Weighted |
|
Weighted |
|
Number of |
|
Weighted |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
||
20.00 to 29.99 |
|
1,099,490 |
|
4.12 |
|
28.96 |
|
7,640 |
|
25.79 |
|
||
30.00 to 39.99 |
|
1,061,795 |
|
3.30 |
|
36.52 |
|
308,138 |
|
36.71 |
|
||
40.00 to 49.99 |
|
177,200 |
|
3.44 |
|
46.39 |
|
53,160 |
|
46.39 |
|
||
50.00 to 59.99 |
|
5,000 |
|
3.46 |
|
50.09 |
|
1,500 |
|
50.09 |
|
||
|
|
2,343,485 |
|
3.70 |
|
33.75 |
|
370,438 |
|
37.93 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|
||
As at December 31, 2009 |
|
Outstanding Cenovus SARs |
|
Exercisable Cenovus SARs |
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||
Range of Exercise Price (C$) |
|
Number of |
|
Weighted |
|
Weighted |
|
Number of |
|
Weighted |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
||
20.00 to 29.99 |
|
1,140,395 |
|
4.11 |
|
26.29 |
|
14,780 |
|
25.62 |
|
||
30.00 to 39.99 |
|
1,048,065 |
|
3.25 |
|
33.53 |
|
315,008 |
|
33.53 |
|
||
40.00 to 49.99 |
|
135,500 |
|
3.44 |
|
43.43 |
|
40,650 |
|
43.43 |
|
||
|
|
2,323,960 |
|
3.69 |
|
30.55 |
|
370,438 |
|
34.30 |
|
||
During the year, the Company recorded compensation costs of $1 million related to the outstanding SARs prior to the Split Transaction, $2 million related to the EnCana Replacement SARs and $5 million related to the Cenovus Replacement SARs (2008 nil; 2007 - nil).
D) PERFORMANCE SHARE APPRECIATION RIGHTS
In 2009 and 2008, EnCana granted Performance Share Appreciation Rights (Performance SARs) to certain employees which entitle the employee to receive a cash payment equal to the excess of the market price of EnCanas Common Shares at the time of exercise over the grant price. Performance SARs vest and expire under the same terms and service conditions as SARs and are also subject to EnCana attaining prescribed performance relative to predetermined key measures. Performance SARs that do not vest when eligible are forfeited.
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
The following tables summarize information related to the Performance SARs:
As at December 31 |
|
2009 |
|
2008 |
|
||||||||
|
|
Outstanding |
|
Weighted |
|
Outstanding |
|
Weighted |
|
||||
|
|
|
|
|
|
|
|
|
|
||||
Canadian Dollar Denominated (C$) |
|
|
|
|
|
|
|
|
|
||||
Outstanding, Beginning of Year |
|
1,620,930 |
|
69.40 |
|
- |
|
- |
|
||||
Granted |
|
2,140,440 |
|
55.31 |
|
1,677,030 |
|
69.40 |
|
||||
Forfeited |
|
(256,235 |
) |
67.47 |
|
(56,100 |
) |
69.40 |
|
||||
Exchanged for Replacement Performance SARs |
|
(3,505,135 |
) |
60.94 |
|
- |
|
- |
|
||||
Outstanding, End of Year |
|
- |
|
- |
|
1,620,930 |
|
69.40 |
|
||||
Exercisable, End of Year |
|
- |
|
- |
|
- |
|
- |
|
||||
|
|
|
|
|
|
|
|
|
|
||||
|
|
|
|
|
|
|
|
|
|
||||
As at December 31, 2009 |
|
EnCana Performance SARs |
|
Cenovus Performance SARs |
|
||||||||
|
|
|
|
|
|
|
|
|
|
||||
|
|
Outstanding |
|
Weighted |
|
Outstanding |
|
Weighted |
|
||||
|
|
|
|
|
|
|
|
|
|
||||
Canadian Dollar Denominated (C$) |
|
|
|
|
|
|
|
|
|
||||
Replacement Performance SARs exchanged November 30, 2009 |
|
3,481,203 |
|
31.99 |
|
3,481,203 |
|
28.94 |
|
||||
Forfeited |
|
(9,205 |
) |
29.97 |
|
(9,205 |
) |
27.11 |
|
||||
Outstanding, End of Year |
|
3,471,998 |
|
32.00 |
|
3,471,998 |
|
28.94 |
|
||||
Exercisable, End of Year |
|
293,344 |
|
36.44 |
|
293,344 |
|
32.96 |
|
||||
|
|
|
|
|
|
||||||||
|
|
|
|
|
|
||||||||
As at December 31, 2009 |
|
Outstanding EnCana Performance |
|
Exercisable EnCana Performance |
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||
Range of Exercise Price (C$) |
|
Number of |
|
Weighted |
|
Weighted |
|
Number of |
|
Weighted |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
||
20.00 to 29.99 |
|
2,085,310 |
|
4.11 |
|
29.04 |
|
- |
|
- |
|
||
30.00 to 39.99 |
|
1,386,688 |
|
3.12 |
|
36.44 |
|
293,344 |
|
36.44 |
|
||
|
|
3,471,998 |
|
3.72 |
|
32.00 |
|
293,344 |
|
36.44 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|
||
As at December 31, 2009 |
|
Outstanding Cenovus Performance |
|
Exercisable Cenovus Performance |
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||
Range of Exercise Price (C$) |
|
Number of |
|
Weighted |
|
Weighted |
|
Number of |
|
Weighted |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
||
20.00 to 29.99 |
|
2,085,310 |
|
4.11 |
|
26.27 |
|
- |
|
- |
|
||
30.00 to 39.99 |
|
1,386,688 |
|
3.12 |
|
32.96 |
|
293,344 |
|
32.96 |
|
||
|
|
3,471,998 |
|
3.72 |
|
28.94 |
|
293,344 |
|
32.96 |
|
||
During the year, the Company recorded compensation costs of $1 million related to the outstanding Performance SARs prior to the Split Transaction, $3 million related to the EnCana Replacement Performance SARs and $7 million related to the Cenovus Replacement Performance SARs (2008 nil; 2007 nil).
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
E) DEFERRED SHARE UNITS
The Company has in place a program whereby Directors and certain key employees are issued Deferred Share Units (DSUs), which are equivalent in value to a Common Share of the Company. DSUs granted to Directors vest immediately. DSUs expire on December 15th of the year following the Directors resignation or employees termination.
Employees have the option to convert either 25 or 50 percent of their annual High Performance Results (HPR) award into DSUs. The number of DSUs is based on the value of the award divided by the closing value of EnCanas share price at the end of the performance period of the HPR award. DSUs vest immediately, can be redeemed in accordance with the terms of the agreement and expire on December 15th of the year following the year of termination.
Pursuant to the Split Transaction, additional EnCana DSUs were credited to employees, officers and directors of EnCana to compensate employees, officers and directors for the loss in value of the EnCana Common Shares. The number of EnCana DSUs credited to each was determined so that, immediately after the adjustment, each participant has an aggregate number of EnCana DSUs based on a formula that the EnCana DSUs fair value would equal the fair value of the exchanged EnCana DSUs. EnCana DSUs credited to employees, officers and directors of Cenovus were exchanged for Cenovus DSUs, each having a notional value equal to the value of one Cenovus Common Share.
The following table summarizes information related to the DSUs:
As at December 31 |
|
2009 |
|
2008 |
|
|
|
Outstanding |
|
Outstanding |
|
|
|
|
|
|
|
Canadian Dollar Denominated |
|
|
|
|
|
Outstanding, Beginning of Year |
|
656,841 |
|
589,174 |
|
Granted |
|
74,600 |
|
85,792 |
|
Converted from HPR awards |
|
46,884 |
|
15,883 |
|
EnCana DSUs exchanged for Cenovus DSUs |
|
(367,293 |
) |
- |
|
EnCana DSU credit adjustment |
|
321,375 |
|
- |
|
Units, in Lieu of Dividends |
|
22,749 |
|
- |
|
Redeemed |
|
(83,009 |
) |
(34,008 |
) |
Outstanding, End of Year |
|
672,147 |
|
656,841 |
|
During the year, the Company recorded compensation costs of $8 million related to the outstanding DSUs (2008 $2 million; 2007 $14 million).
F) PERFORMANCE SHARE UNITS
Performance Share Units (PSUs) were granted in 2003, 2004 and 2005 and entitled employees to receive upon vesting, either a Common Share of EnCana or a cash payment equal to the value of one Common Share of EnCana, depending upon the terms of the PSUs granted. PSUs vested over a three-year period from the date granted. If EnCanas performance was at or above a specified level compared to a pre-determined peer group, payments ranged from one-half to two times the PSU. At December 31, 2009, there are no PSUs outstanding.
PSUs granted in 2003 were paid out in cash at 75 percent of the number granted. PSUs granted in 2004 were paid out in Common Shares at 100 percent of the number granted. PSUs granted in 2005 were paid out in Common Shares at 125 percent of the number granted.
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
The following table summarizes information related to the PSUs:
As at December 31 |
|
2009 |
|
2008 |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding |
|
Average Share |
|
Outstanding |
|
Average |
|
|
|
|
|
|
|
|
|
|
|
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 |
|
- |
|
- |
|
- |
|
- |
|
During the year, the Company did not record any compensation costs related to the outstanding PSUs (2008 $1 million; 2007 $43 million).
G) PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS
The Company sponsors defined benefit and defined contribution plans, providing pension and other post-employment benefits (OPEB) to its employees. In the past, the defined benefit plan was offered, however it has been closed to new entrants beginning January 1, 2003. The average remaining service period of the active employees covered by the defined benefit pension plan is six years. The average remaining service period of the active employees covered by the OPEB plan is 10 years.
The Company is required to file an actuarial valuation of its pension plans with the provincial regulator at least every three years. The most recent filing was dated December 31, 2008 and the next required filing will be as at December 31, 2011.
Information related to defined benefit pension and other post-employment benefit plans, based on actuarial estimations as at December 31, 2009 is as follows:
|
|
Pension Benefits |
|
|
OPEB |
|
|||||||||||||
As at December 31 |
|
2009 |
|
2008 |
|
|
2009 |
|
2008 |
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Fair Value of Plan Assets, End of Year |
|
|
|
$ |
251 |
|
|
$ |
233 |
|
|
|
$ |
- |
|
|
$ |
- |
|
Accrued Benefit Obligation, End of Year |
|
|
|
277 |
|
|
263 |
|
|
|
62 |
|
|
55 |
|
||||
Funded Status Plan Assets (less) than Benefit Obligation |
|
|
|
(26 |
) |
|
(30 |
) |
|
|
(62 |
) |
|
(55 |
) |
||||
Amounts Not Recognized: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Unamortized net actuarial (gain) loss |
|
|
|
59 |
|
|
74 |
|
|
|
1 |
|
|
(5 |
) |
||||
Unamortized past service costs |
|
|
|
2 |
|
|
4 |
|
|
|
1 |
|
|
1 |
|
||||
Net transitional asset (liability) |
|
|
|
- |
|
|
- |
|
|
|
5 |
|
|
10 |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Accrued Benefit Asset (Liability) |
|
|
|
$ |
35 |
|
|
$ |
48 |
|
|
|
$ |
(55 |
) |
|
$ |
(49 |
) |
The 2009 pension benefit obligation was determined using the weighted average discount rate of 5.75 percent (2008 6.25 percent) and a weighted average rate of compensation increase of 4.15 percent (2008 4.16 percent). The 2009 OPEB obligation was determined using the weighted average discount rate of 5.93 percent (2008 6.25 percent) and a weighted average rate of compensation increase of 6.31 percent (2008 6.00 percent).
Accrued benefit obligation and plan assets of $50 million were allocated in conjunction with the Split Transaction for active employees who are with Cenovus.
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
The periodic pension and OPEB expense is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits |
|
|
OPEB |
|
||||||||||||||||||||
For the years ended December 31 |
|
|
2009 |
|
2008 |
|
2007 |
|
|
2009 |
|
2008 |
|
2007 |
|
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Defined Benefit Plans Expense |
|
|
|
$ |
20 |
|
|
$ |
9 |
|
|
$ |
8 |
|
|
|
$ |
14 |
|
|
$ |
12 |
|
|
$ |
12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Defined Contribution Plans Expense |
|
|
|
43 |
|
|
44 |
|
|
34 |
|
|
|
- |
|
|
- |
|
|
- |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Total Benefit Plans Expense |
|
|
|
$ |
63 |
|
|
$ |
53 |
|
|
$ |
42 |
|
|
|
$ |
14 |
|
|
$ |
12 |
|
|
$ |
12 |
|
The Companys pension plan assets were invested in the following as at December 31, 2009: 39 percent Domestic Equity (2008 34 percent), 23 percent Foreign Equity (2008 25 percent), 29 percent Bonds (2008 33 percent), and 9 percent Real Estate and Other (2008 8 percent). The expected long-term rate of return is 6.75 percent. The expected rate of return on plan assets is based on historical and projected rates of return for each asset class in the plan investment portfolio. The asset allocation structure is subject to diversification requirements and constraints which reduce risk by limiting exposure to individual equity investment, credit rating categories and foreign currency exposure.
The Companys contributions to the defined benefit pension plans are subject to the results of the actuarial valuation and direction by the Human Resources and Compensation Committee. Contributions by the participants to the pension and other benefits plans were $1 million for the year ended December 31, 2009 (2008 $1 million; 2007 $1 million). EnCanas contribution to the defined benefit pension plans for the year ended December 31, 2009 was $12 million (2008 $8 million; 2007 $ 8 million).
The Companys OPEB plans are funded on an as required basis.
Estimated future payments of pension and other benefits are as follows:
|
|
Pension Benefits |
|
OPEB |
|
||||
|
|
|
|
|
|
|
|
||
2010 |
|
|
$ |
16 |
|
|
$ |
2 |
|
2011 |
|
|
17 |
|
|
3 |
|
||
2012 |
|
|
17 |
|
|
3 |
|
||
2013 |
|
|
18 |
|
|
4 |
|
||
2014 |
|
|
18 |
|
|
4 |
|
||
2015 2019 |
|
|
95 |
|
|
26 |
|
||
|
|
|
|
|
|
|
|
||
Total |
|
|
$ |
181 |
|
|
$ |
42 |
|
20. Financial Instruments and Risk Management |
EnCanas financial assets and liabilities include cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued liabilities, the partnership contribution receivable, 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 except for the amounts associated with Replacement share units issued as part of the Split Transaction, as discussed in Notes 17 and 19.
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
At December 31, 2008, the fair value of the partnership contribution receivable approximates its carrying amount due to the specific nature of the instruments in relation to the creation of the Integrated Oil joint venture. Further information about this note is disclosed in Note 11.
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 December 31 |
|
|
2009 |
|
|
2008 |
|
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
|
|
|
Carrying |
|
Fair |
|
|
Carrying |
|
Fair |
|
||||||||
Financial Assets |
|
|
|
|
|
|
|
|
|
|
|
||||||||
Held-for-trading: |
|
|
|
|
|
|
|
|
|
|
|
||||||||
Cash and cash equivalents |
|
|
|
$ |
4,275 |
|
|
$ |
4,275 |
|
|
|
$ |
354 |
|
|
$ |
354 |
|
Accounts receivable and accrued revenues (1) |
|
|
|
75 |
|
|
75 |
|
|
|
- |
|
|
- |
|
||||
Risk management assets (2) |
|
|
|
360 |
|
|
360 |
|
|
|
3,052 |
|
|
3,052 |
|
||||
Loans and Receivables: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Accounts receivable and accrued revenues |
|
|
|
1,105 |
|
|
1,105 |
|
|
|
1,436 |
|
|
1,436 |
|
||||
Partnership contribution receivable (2) |
|
|
|
- |
|
|
- |
|
|
|
3,147 |
|
|
3,147 |
|
||||
Financial Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Held-for-trading: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Accounts payable and accrued liabilities (3), (4) |
|
|
|
$ |
155 |
|
|
$ |
155 |
|
|
|
$ |
- |
|
|
$ |
- |
|
Risk management liabilities (2) |
|
|
|
168 |
|
|
168 |
|
|
|
50 |
|
|
50 |
|
||||
Other Financial Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Accounts payable and accrued liabilities |
|
|
|
1,988 |
|
|
1,988 |
|
|
|
2,448 |
|
|
2,448 |
|
||||
Long-term debt (2) |
|
|
|
7,768 |
|
|
8,527 |
|
|
|
9,005 |
|
|
8,242 |
|
(1) Represents amounts due from Cenovus for EnCana Replacement share units held by Cenovus employees as discussed in Note 17.
(2) Including current portion.
(3) Includes amounts due to Cenovus employees for EnCana Replacement share units held as discussed in Note 17.
(4) Includes amounts due to Cenovus for Cenovus Replacement share units held by EnCana employees as discussed in Notes 17 and 19.
B) RISK MANAGEMENT ASSETS AND LIABILITIES
NET RISK MANAGEMENT POSITION
As at December 31 |
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
|
2008 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
Risk Management |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
Current asset |
|
|
|
|
|
|
|
|
|
|
$ |
328 |
|
|
|
$ |
2,818 |
|
Long-term asset |
|
|
|
|
|
|
|
|
|
|
32 |
|
|
|
234 |
|
||
|
|
|
|
|
|
|
|
|
|
|
360 |
|
|
|
3,052 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
Risk Management |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
Current liability |
|
|
|
|
|
|
|
|
|
|
126 |
|
|
|
43 |
|
||
Long-term liability |
|
|
|
|
|
|
|
|
|
|
42 |
|
|
|
7 |
|
||
|
|
|
|
|
|
|
|
|
|
|
168 |
|
|
|
50 |
|
||
Net Risk Management Asset |
|
|
|
|
|
|
|
|
|
|
$ |
192 |
|
|
|
$ |
3,002 |
|
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
SUMMARY OF UNREALIZED RISK MANAGEMENT POSITIONS
As at December 31 |
|
|
2009 |
|
2008 |
|
|||||||||||||||||||||
|
|
|
Risk Management |
|
|
Risk Management |
|
||||||||||||||||||||
|
|
|
Asset |
|
Liability |
|
Net |
|
|
Asset |
|
Liability |
|
Net |
|
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity Prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Natural Gas |
|
|
|
$ |
298 |
|
|
$ |
88 |
|
|
$ |
210 |
|
|
|
$ |
2,941 |
|
|
$ |
10 |
|
|
$ |
2,931 |
|
Crude Oil |
|
|
|
62 |
|
|
72 |
|
|
(10 |
) |
|
|
92 |
|
|
40 |
|
|
52 |
|
||||||
Power |
|
|
|
- |
|
|
8 |
|
|
(8 |
) |
|
|
19 |
|
|
- |
|
|
19 |
|
||||||
Total Fair Value |
|
|
|
$ |
360 |
|
|
$ |
168 |
|
|
$ |
192 |
|
|
|
$ |
3,052 |
|
|
$ |
50 |
|
|
$ |
3,002 |
|
NET FAIR VALUE METHODOLOGIES USED TO CALCULATE UNREALIZED RISK MANAGEMENT POSITIONS
As at December 31 |
|
2009 |
|
2008 |
|
||||
|
|
|
|
|
|
|
|
|
|
Prices actively quoted |
|
|
$ |
285 |
|
|
$ |
2,055 |
|
Prices sourced from observable data or market corroboration |
|
|
|
(93 |
) |
|
947 |
|
|
Total Fair Value |
|
|
$ |
192 |
|
|
$ |
3,002 |
|
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, 2009
|
|
Notional Volumes |
|
Term |
|
Average Price |
|
Fair Value |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Contracts |
|
|
|
|
|
|
|
|
|
|
|
Fixed Price Contracts |
|
|
|
|
|
|
|
|
|
|
|
NYMEX Fixed Price |
|
1,852 MMcf/d |
|
2010 |
|
6.05 US$/Mcf |
|
|
$ |
223 |
|
NYMEX Fixed Price |
|
640 MMcf/d |
|
2011 |
|
6.57 US$/Mcf |
|
|
63 |
|
|
NYMEX Fixed Price |
|
267 MMcf/d |
|
2012 |
|
6.55 US$/Mcf |
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis Contracts * |
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
|
2010 |
|
|
|
|
(4 |
) |
|
United States |
|
|
|
2010 |
|
|
|
|
(3 |
) |
|
Canada and United States |
|
|
|
2011-2013 |
|
|
|
|
(78 |
) |
|
|
|
|
|
|
|
|
|
|
209 |
|
|
Other Financial Positions ** |
|
|
|
|
|
|
|
|
1 |
|
|
Natural Gas Fair Value Position |
|
|
|
|
|
|
|
|
$ |
210 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Contracts |
|
|
|
|
|
|
|
|
|
|
|
Fixed Price Contracts |
|
|
|
|
|
|
|
|
|
|
|
WTI NYMEX Fixed Price |
|
5,400 bbls/d |
|
2010 |
|
76.99 US$/bbl |
|
|
$ |
(10 |
) |
Crude Oil Fair Value Position |
|
|
|
|
|
|
|
|
$ |
(10 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Power Purchase Contracts |
|
|
|
|
|
|
|
|
|
|
|
Power Fair Value Position |
|
|
|
|
|
|
|
|
$ |
(8 |
) |
* 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 Companys proprietary production management.
EARNINGS IMPACT OF REALIZED AND UNREALIZED GAINS (LOSSES) ON RISK MANAGEMENT POSITIONS
|
|
Realized Gain (Loss) |
|
||||||||||
For the years ended December 31 |
|
2009 |
|
2008 |
|
2007 |
|
||||||
|
|
|
|
|
|
|
|
|
|||||
Revenues, Net of Royalties |
|
|
$ |
4,420 |
|
|
$ |
(309 |
) |
|
$ |
1,601 |
|
Operating Expenses and Other |
|
|
(44 |
) |
|
28 |
|
|
3 |
|
|||
Gain (Loss) on Risk Management |
|
|
$ |
4,376 |
|
|
$ |
(281 |
) |
|
$ |
1,604 |
|
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
|
|
Unrealized Gain (Loss) |
|
|||||||||||
For the years ended December 31 |
|
2009 |
|
|
2008 |
|
2007 |
|
||||||
|
|
|
|
|
|
|
|
|
||||||
Revenues, Net of Royalties |
|
|
$ |
(2,640 |
) |
|
|
$ |
2,717 |
|
|
$ |
(1,239 |
) |
Operating Expenses and Other |
|
|
(40 |
) |
|
|
12 |
|
|
4 |
|
|||
Gain (Loss) on Risk Management |
|
|
$ |
(2,680 |
) |
|
|
$ |
2,729 |
|
|
$ |
(1,235 |
) |
RECONCILIATION OF UNREALIZED RISK MANAGEMENT POSITIONS FROM JANUARY 1 TO DECEMBER 31, 2009
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
|
|
|
Fair Value |
|
Total |
|
|
Total |
|
|
Total |
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Fair Value of Contracts, Beginning of Year |
|
|
|
$ |
2,892 |
|
|
|
|
|
|
|
|
|
|
|||||
Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered into During the Year |
|
|
|
1,696 |
|
|
$ |
1,696 |
|
|
|
$ |
2,448 |
|
|
|
$ |
353 |
|
|
Fair Value of Contracts in Place at Transition that Expired During the Year |
|
|
|
- |
|
|
- |
|
|
|
- |
|
|
|
16 |
|
||||
Foreign Exchange Translation Adjustment on Canadian Dollar Contracts |
|
|
|
4 |
|
|
- |
|
|
|
- |
|
|
|
- |
|
||||
Fair Value of Contracts Transferred to Cenovus |
|
|
|
(24 |
) |
|
- |
|
|
|
- |
|
|
|
- |
|
||||
Fair Value of Contracts Realized During the Year |
|
|
|
(4,376 |
) |
|
(4,376 |
) |
|
|
281 |
|
|
|
(1,604 |
) |
||||
Fair Value of Contracts Outstanding, End of Year |
|
|
|
$ |
192 |
|
|
$ |
(2,680 |
) |
|
|
$ |
2,729 |
|
|
|
$ |
(1,235 |
) |
COMMODITY PRICE SENSITIVITIES
The following table summarizes the sensitivity of the fair value of the Companys risk management positions to fluctuations in commodity prices, with all other variables held constant. The Company has used a 10 percent variability to assess the potential impact of commodity price changes. Fluctuations in commodity prices could have resulted in unrealized gains (losses) impacting pre-tax net earnings as at December 31, 2009 as follows:
|
|
10% Price |
|
10% Price |
|
||||
|
|
|
|
|
|
||||
Natural gas price |
|
|
$ |
(608 |
) |
|
$ |
608 |
|
Crude oil price |
|
|
(9 |
) |
|
9 |
|
||
Power price |
|
|
5 |
|
|
(5 |
) |
||
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 Board). The Companys 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 swaps which fix the NYMEX prices. To help protect against widening natural gas price differentials in various production areas, EnCana has entered into swaps to manage the price differentials between these production areas and various sales points.
Crude Oil The Company has partially mitigated its exposure to the commodity price risk on crude oil with swaps which fix WTI NYMEX prices.
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
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 Companys credit portfolio and with credit practices that limit transactions according to counterparties credit quality. At December 31, 2009, cash equivalents include high-grade, short-term securities, placed with Governments, crown corporations and financial institutions with strong investment grade ratings. Any foreign currency agreements entered into are with major financial institutions in Canada and the United States or with counterparties having investment grade credit ratings.
A substantial portion of the Companys accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. As at December 31, 2009, over 93 percent (2008 95 percent) of EnCanas accounts receivable and financial derivative credit exposures are with investment grade counterparties.
At December 31, 2009, EnCana had two counterparties (2008 two 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 18, EnCana targets a Debt to Capitalization ratio of less than 40 percent and a Debt to Adjusted EBITDA of less than 2.0 times to steward the Companys 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, 2009, EnCana had available unused committed bank credit facilities in the amount of $4.9 billion and unused capacity under shelf prospectuses, the availability of which is dependent on market conditions, in the amount of $5.4 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 November 30, 2009 following the completion of the Split Transaction (See Note 3), Standard & Poors Ratings Services lowered the rating to BBB+ from A- and changed the outlook to Stable from CreditWatch with negative implications. Moodys Investors Service affirmed the rating of Baa2 with a Stable outlook. DBRS Limited maintained the rating of A (low) and changed the outlook to Stable from Under Review with Developing Implications. These credit ratings remained unchanged at December 31, 2009.
The timing of cash outflows relating to financial liabilities are outlined in the table below:
|
|
Less than 1 |
|
1 3 Years |
|
4 5 Years |
|
Thereafter |
|
|
Total |
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Accounts Payable and Accrued Liabilities |
|
|
$ |
2,143 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
|
$ |
2,143 |
|
Risk Management Liabilities |
|
|
126 |
|
|
34 |
|
|
8 |
|
|
- |
|
|
|
168 |
|
|||||
Long-Term Debt * |
|
|
685 |
|
|
1,875 |
|
|
2,282 |
|
|
9,936 |
|
|
|
14,778 |
|
|||||
* Principal and interest, including current portion.
EnCanas total long-term debt obligations were $14,778 million at December 31, 2009. Further information on Long-Term Debt is contained in Note 15.
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
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 Companys 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 is 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.
EnCana's foreign exchange (gain) loss primarily includes foreign exchange gains and losses on U.S. dollar cash and short-term investments, unrealized foreign exchange gains and losses on the translation of U.S. dollar debt issued from Canada, foreign exchange gains and losses on the translation of the U.S. dollar partnership contribution receivable issued from Canada and unrealized foreign exchange gains and losses on the translation of U.S. dollar denominated risk management assets and liabilities.
At December 31, 2009, EnCana had $5,600 million in U.S. dollar debt issued from Canada ($5,350 million at December 31, 2008). At December 31, 2009, as a result of the Split Transaction (See Note 3), EnCana had nil related to the U.S. dollar partnership contribution receivable ($3,147 million at December 31, 2008). A $0.01 change in the U.S. to Canadian dollar exchange rate would have resulted in a $20 million change in foreign exchange (gain) loss at December 31, 2009 (2008 $18 million).
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 Companys financial assets or liabilities. Typically, the Company partially mitigates its exposure to interest rate changes by maintaining a mix of both fixed and floating rate debt.
At December 31, 2009, the Company had no floating rate debt. Therefore, the increase or decrease in net earnings for each one percent change in interest rates on floating rate debt was nil (2008 $12 million).
21. Supplementary Information |
A) NET CHANGE IN NON-CASH WORKING CAPITAL FROM CONTINUING OPERATIONS
For the years ended December 31 |
|
2009 |
|
|
2008 |
|
|
2007 |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Operating Activities |
|
|
|
|
|
|
|
|
|
|||
Accounts receivable and accrued revenues |
|
$ |
(487 |
) |
|
$ |
452 |
|
|
$ |
33 |
|
Inventories |
|
(271 |
) |
|
211 |
|
|
46 |
|
|||
Accounts payable and accrued liabilities |
|
567 |
|
|
(354 |
) |
|
(78 |
) |
|||
Income tax payable |
|
1,237 |
|
|
(589 |
) |
|
(5 |
) |
|||
Discontinued operations |
|
(1,075 |
) |
|
(1,073 |
) |
|
(104 |
) |
|||
|
|
$ |
(29 |
) |
|
$ |
(1,353 |
) |
|
$ |
(108 |
) |
|
|
|
|
|
|
|
|
|
|
|||
Investing Activities |
|
|
|
|
|
|
|
|
|
|||
Accounts payable and accrued liabilities |
|
$ |
(50 |
) |
|
$ |
34 |
|
|
$ |
51 |
|
B) SUPPLEMENTARY CASH FLOW INFORMATION CONTINUING OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
For the years ended December 31 |
|
|
|
2009 |
|
|
|
|
2008 |
|
|
|
|
2007 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Interest Paid |
|
|
|
$ |
507 |
|
|
|
|
$ |
574 |
|
|
|
|
$ |
486 |
|
Income Taxes Paid |
|
|
|
$ |
766 |
|
|
|
|
$ |
1,574 |
|
|
|
|
$ |
1,262 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
22. Commitments and Contingencies |
COMMITMENTS
As at December 31, 2009 |
|
|
2010 |
|
|
2011 |
|
|
2012 |
|
|
2013 |
|
|
2014 |
|
Thereafter |
|
|
Total |
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Pipeline Transportation |
|
|
$ |
438 |
|
|
$ |
485 |
|
|
$ |
506 |
|
|
$ |
501 |
|
|
$ |
497 |
|
|
$ |
1,911 |
|
|
$ |
4,338 |
|
Purchases of Goods and Services |
|
|
377 |
|
|
365 |
|
|
275 |
|
|
224 |
|
|
198 |
|
|
684 |
|
|
2,123 |
|
|||||||
Operating Leases* |
|
|
69 |
|
|
71 |
|
|
87 |
|
|
160 |
|
|
169 |
|
|
3,238 |
|
|
3,794 |
|
|||||||
Capital Commitments |
|
|
127 |
|
|
169 |
|
|
67 |
|
|
- |
|
|
38 |
|
|
- |
|
|
401 |
|
|||||||
Other Long-Term Commitments |
|
|
2 |
|
|
2 |
|
|
2 |
|
|
2 |
|
|
1 |
|
|
24 |
|
|
33 |
|
|||||||
Total |
|
|
$ |
1,013 |
|
|
$ |
1,092 |
|
|
$ |
937 |
|
|
$ |
887 |
|
|
$ |
903 |
|
|
$ |
5,857 |
|
|
$ |
10,689 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Cenovuss Share of Costs** |
|
|
$ |
90 |
|
|
$ |
111 |
|
|
$ |
68 |
|
|
$ |
72 |
|
|
$ |
76 |
|
|
$ |
1,576 |
|
|
$ |
1,993 |
|
* Primarily related to office space associated with The Bow.
** Tenant costs associated with The Bow as well as current office space lease arrangements remain with EnCana. Cenovus and EnCana have entered into an agreement to share in the costs.
EnCana has entered into various commitments primarily related to demand charges for firm transportation, leasing of office space, procurement arrangements for goods and services, as well as other minor spending commitments. EnCana and Cenovus have entered into an arrangement whereby the portion of the commitments related to the Cenovus operations have been transferred to Cenovus as a result of the Split Transaction and are excluded from the table above.
In addition to the above, the Company has made commitments related to its risk management program (See Note 20).
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. All but one of these lawsuits had been settled prior to 2009. Without admitting any liability whatsoever, the remaining lawsuit was settled on October 16, 2009.
ASSET RETIREMENT
EnCana is responsible for the retirement of long-lived assets related to its oil and gas properties and Midstream facilities at the end of their useful lives. The Company has recognized a liability of $787 million based on current legislation and estimated costs. Actual costs may differ from those estimated due to changes in legislation and changes in costs.
INCOME TAX MATTERS
The operations of the Company are complex, and related tax interpretations, regulations and legislation in the various jurisdictions that EnCana operates in are continually changing. As a result, there are usually some tax matters under review. The Company believes that the provision for taxes is adequate.
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
23. United States Accounting Principles and Reporting |
The Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in Canada (Canadian GAAP) which, in most respects, conform to accounting principles generally accepted in the United States (U.S. GAAP). The significant differences between Canadian GAAP and U.S. GAAP are described in this note.
RECONCILIATION OF NET EARNINGS UNDER CANADIAN GAAP TO U.S. GAAP
For the years ended December 31 |
|
Note |
|
|
|
2009 |
|
|
|
2008 |
|
|
2007 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Net Earnings Canadian GAAP |
|
|
|
|
|
$ |
1,862 |
|
|
|
$ |
5,944 |
|
|
$ |
3,959 |
|
Less: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Net Earnings From Discontinued Operations Canadian GAAP |
|
|
|
|
|
32 |
|
|
|
(555 |
) |
|
512 |
|
|||
Net Earnings From Continuing Operations Canadian GAAP |
|
|
|
|
|
1,830 |
|
|
|
6,499 |
|
|
3,447 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Increase
(Decrease) in Net Earnings From Continuing Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Revenues, net of royalties |
|
A |
|
|
|
- |
|
|
|
- |
|
|
(15 |
) |
|||
Operating |
|
D ii), H |
|
|
|
(16 |
) |
|
|
(46 |
) |
|
3 |
|
|||
Depreciation, depletion and amortization |
|
B, D ii) |
|
|
|
(10,926 |
) |
|
|
(1,755 |
) |
|
86 |
|
|||
Administrative |
|
D ii) |
|
|
|
22 |
|
|
|
(27 |
) |
|
1 |
|
|||
Interest, net |
|
A |
|
|
|
- |
|
|
|
(3 |
) |
|
(2 |
) |
|||
Foreign exchange (gain) loss, net |
|
G |
|
|
|
128 |
|
|
|
- |
|
|
- |
|
|||
Stock-Based compensation options |
|
C |
|
|
|
- |
|
|
|
2 |
|
|
(5 |
) |
|||
Income tax expense |
|
E |
|
|
|
3,378 |
|
|
|
695 |
|
|
(204 |
) |
|||
Net Earnings (Loss) From Continuing Operations U.S. GAAP |
|
|
|
|
|
(5,584 |
) |
|
|
5,365 |
|
|
3,311 |
|
|||
Net Earnings (Loss) From Discontinued Operations U.S. GAAP |
|
|
|
|
|
32 |
|
|
|
(555 |
) |
|
512 |
|
|||
Net Earnings (Loss) U.S. GAAP |
|
|
|
|
|
$ |
(5,552 |
) |
|
|
$ |
4,810 |
|
|
$ |
3,823 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Net Earnings (Loss) From Continuing Operations per Common Share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Basic |
|
|
|
|
|
$ |
(7.44 |
) |
|
|
$ |
7.15 |
|
|
$ |
4.37 |
|
Diluted |
|
|
|
|
|
$ |
(7.44 |
) |
|
|
$ |
7.14 |
|
|
$ |
4.33 |
|
Net Earnings (Loss) per Common Share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Basic |
|
|
|
|
|
$ |
(7.39 |
) |
|
|
$ |
6.41 |
|
|
$ |
5.05 |
|
Diluted |
|
|
|
|
|
$ |
(7.39 |
) |
|
|
$ |
6.40 |
|
|
$ |
5.00 |
|
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
CONSOLIDATED STATEMENT OF EARNINGS U.S. GAAP
For the years ended December 31 |
|
Note |
|
|
2009 |
|
|
|
2008 |
|
|
2007 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Revenues, Net of Royalties |
|
A |
|
|
$ |
11,114 |
|
|
|
$ |
21,053 |
|
|
$ |
14,370 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Production and mineral taxes |
|
|
|
|
171 |
|
|
|
478 |
|
|
291 |
|
|||
Transportation and selling |
|
|
|
|
1,280 |
|
|
|
1,704 |
|
|
1,264 |
|
|||
Operating |
|
D ii), H |
|
|
1,643 |
|
|
|
2,029 |
|
|
1,847 |
|
|||
Purchased product |
|
|
|
|
1,460 |
|
|
|
2,426 |
|
|
2,770 |
|
|||
Depreciation, depletion and amortization |
|
B, D ii) |
|
|
14,630 |
|
|
|
5,790 |
|
|
3,571 |
|
|||
Administrative |
|
D ii) |
|
|
455 |
|
|
|
474 |
|
|
355 |
|
|||
Interest, net |
|
A |
|
|
405 |
|
|
|
405 |
|
|
236 |
|
|||
Accretion of asset retirement obligation |
|
|
|
|
71 |
|
|
|
77 |
|
|
63 |
|
|||
Foreign exchange (gain) loss, net |
|
G |
|
|
(150 |
) |
|
|
423 |
|
|
(164 |
) |
|||
Stock-Based compensation options |
|
C |
|
|
- |
|
|
|
(2 |
) |
|
5 |
|
|||
(Gain) loss on divestitures |
|
|
|
|
2 |
|
|
|
(141 |
) |
|
(65 |
) |
|||
Net Earnings (Loss) Before Income Tax |
|
|
|
|
(8,853 |
) |
|
|
7,390 |
|
|
4,197 |
|
|||
Income tax expense (recovery) |
|
E |
|
|
(3,269 |
) |
|
|
2,025 |
|
|
886 |
|
|||
Net Earnings (Loss) From Continuing Operations U.S. GAAP |
|
|
|
|
(5,584 |
) |
|
|
5,365 |
|
|
3,311 |
|
|||
Net Earnings (Loss) From Discontinued Operations U.S. GAAP |
|
|
|
|
32 |
|
|
|
(555 |
) |
|
512 |
|
|||
Net Earnings (Loss) U.S. GAAP |
|
|
|
|
$ |
(5,552 |
) |
|
|
$ |
4,810 |
|
|
$ |
3,823 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Net Earnings (Loss) From Continuing Operations per Common Share U.S. GAAP |
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Basic |
|
|
|
|
$ |
(7.44 |
) |
|
|
$ |
7.15 |
|
|
$ |
4.37 |
|
Diluted |
|
|
|
|
$ |
(7.44 |
) |
|
|
$ |
7.14 |
|
|
$ |
4.33 |
|
Net Earnings (Loss) From Discontinued Operations per Common Share U.S. GAAP |
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Basic |
|
|
|
|
$ |
0.05 |
|
|
|
$ |
(0.74 |
) |
|
$ |
0.68 |
|
Diluted |
|
|
|
|
$ |
0.05 |
|
|
|
$ |
(0.74 |
) |
|
$ |
0.67 |
|
Net Earnings (Loss) per Common Share U.S. GAAP |
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Basic |
|
|
|
|
$ |
(7.39 |
) |
|
|
$ |
6.41 |
|
|
$ |
5.05 |
|
Diluted |
|
|
|
|
$ |
(7.39 |
) |
|
|
$ |
6.40 |
|
|
$ |
5.00 |
|
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME U.S. GAAP
For the years ended December 31 |
|
Note |
|
|
2009 |
|
|
|
2008 |
|
|
2007 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Net Earnings (Loss) U.S. GAAP |
|
|
|
|
$ |
(5,552 |
) |
|
|
$ |
4,810 |
|
|
$ |
3,823 |
|
Change in Fair Value of Financial Instruments |
|
A |
|
|
- |
|
|
|
2 |
|
|
- |
|
|||
Foreign Currency Translation Adjustment |
|
B, D ii), F, G |
|
|
1,970 |
|
|
|
(2,217 |
) |
|
1,707 |
|
|||
Compensation Plans |
|
D i), F |
|
|
13 |
|
|
|
(12 |
) |
|
1 |
|
|||
Comprehensive Income (Loss) |
|
|
|
|
$ |
(3,569 |
) |
|
|
$ |
2,583 |
|
|
$ |
5,531 |
|
CONSOLIDATED STATEMENT OF ACCUMULATED OTHER COMPREHENSIVE INCOME U.S. GAAP
For the years ended December 31 |
|
Note |
|
|
2009 |
|
|
|
2008 |
|
|
2007 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Balance, Beginning of Year |
|
|
|
|
$ |
811 |
|
|
|
$ |
3,038 |
|
|
$ |
1,330 |
|
Change in Fair Value of Financial Instruments |
|
A |
|
|
- |
|
|
|
2 |
|
|
- |
|
|||
Foreign Currency Translation Adjustment |
|
B, D ii), F, G |
|
|
1,970 |
|
|
|
(2,217 |
) |
|
1,707 |
|
|||
Compensation Plans |
|
D i), F |
|
|
13 |
|
|
|
(12 |
) |
|
1 |
|
|||
Net Distribution to Cenovus Energy |
|
|
|
|
(2,096 |
) |
|
|
- |
|
|
- |
|
|||
Balance, End of Year |
|
|
|
|
$ |
698 |
|
|
|
$ |
811 |
|
|
$ |
3,038 |
|
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
CONSOLIDATED STATEMENT OF RETAINED EARNINGS U.S. GAAP
For the years ended December 31 |
|
|
2009 |
|
|
|
2008 |
|
|
2007 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Retained Earnings, Beginning of Year |
|
|
$ |
16,344 |
|
|
|
$ |
12,976 |
|
|
$ |
11,374 |
|
Net Earnings (Loss) |
|
|
(5,552 |
) |
|
|
4,810 |
|
|
3,823 |
|
|||
Dividends on Common Shares |
|
|
(1,051 |
) |
|
|
(1,199 |
) |
|
(603 |
) |
|||
Charges for Normal Course Issuer Bid |
|
|
- |
|
|
|
(243 |
) |
|
(1,618 |
) |
|||
Net Distribution to Cenovus Energy |
|
|
(4,937 |
) |
|
|
- |
|
|
- |
|
|||
Retained Earnings, End of Year |
|
|
$ |
4,804 |
|
|
|
$ |
16,344 |
|
|
$ |
12,976 |
|
CONDENSED CONSOLIDATED BALANCE SHEET U.S. GAAP
As at December 31 |
|
|
|
|
2009 |
|
|
2008 |
|
||||||||||||
|
|
Note |
|
|
As Reported |
|
U.S. GAAP |
|
|
As Reported |
|
U.S. GAAP |
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Current Assets |
|
D i), H |
|
|
|
$ |
5,795 |
|
|
$ |
5,750 |
|
|
|
$ |
5,602 |
|
|
$ |
5,604 |
|
Property, Plant and Equipment |
|
B, D ii) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
(includes unproved properties and major development projects of $3,128 and $4,797 as of December 31, 2009 and 2008, respectively) |
|
|
|
|
|
45,503 |
|
|
45,393 |
|
|
|
55,524 |
|
|
55,483 |
|
||||
Accumulated Depreciation, Depletion and Amortization |
|
|
|
|
|
(19,330 |
) |
|
(31,738 |
) |
|
|
(23,614 |
) |
|
(25,135 |
) |
||||
Property, Plant and Equipment, net |
|
|
|
|
|
26,173 |
|
|
13,655 |
|
|
|
31,910 |
|
|
30,348 |
|
||||
(Full Cost Method for Oil and Gas Activities) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Investments and Other Assets |
|
D i) |
|
|
|
164 |
|
|
119 |
|
|
|
72 |
|
|
26 |
|
||||
Partnership Contribution Receivable |
|
|
|
|
|
- |
|
|
- |
|
|
|
2,834 |
|
|
2,834 |
|
||||
Risk Management |
|
|
|
|
|
32 |
|
|
32 |
|
|
|
234 |
|
|
234 |
|
||||
Goodwill |
|
|
|
|
|
1,663 |
|
|
1,663 |
|
|
|
2,426 |
|
|
2,426 |
|
||||
Assets of Discontinued Operations |
|
|
|
|
|
- |
|
|
- |
|
|
|
4,169 |
|
|
4,169 |
|
||||
|
|
|
|
|
|
$ |
33,827 |
|
|
$ |
21,219 |
|
|
|
$ |
47,247 |
|
|
$ |
45,641 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Liabilities and Shareholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Current Liabilities |
|
A, D i), ii) |
|
|
|
$ |
4,245 |
|
|
$ |
4,530 |
|
|
|
$ |
3,894 |
|
|
$ |
4,201 |
|
Long-Term Debt |
|
|
|
|
|
7,568 |
|
|
7,568 |
|
|
|
8,755 |
|
|
8,755 |
|
||||
Other Liabilities |
|
A, D i), ii) |
|
|
|
1,185 |
|
|
1,220 |
|
|
|
576 |
|
|
613 |
|
||||
Risk Management |
|
|
|
|
|
42 |
|
|
42 |
|
|
|
7 |
|
|
7 |
|
||||
Asset Retirement Obligation |
|
|
|
|
|
787 |
|
|
787 |
|
|
|
1,230 |
|
|
1,230 |
|
||||
Future Income Taxes |
|
E |
|
|
|
3,386 |
|
|
(829 |
) |
|
|
6,917 |
|
|
6,196 |
|
||||
Liabilities of Discontinued Operations |
|
|
|
|
|
- |
|
|
- |
|
|
|
2,894 |
|
|
2,894 |
|
||||
|
|
|
|
|
|
17,213 |
|
|
13,318 |
|
|
|
24,273 |
|
|
23,896 |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Share Capital |
|
C |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Common shares, no par value |
|
|
|
|
|
2,360 |
|
|
2,393 |
|
|
|
4,557 |
|
|
4,590 |
|
||||
Outstanding: 2009 751.3 million shares |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
2008 750.4 million shares |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Paid in Surplus |
|
|
|
|
|
6 |
|
|
6 |
|
|
|
- |
|
|
- |
|
||||
Retained Earnings |
|
|
|
|
|
13,493 |
|
|
4,804 |
|
|
|
17,584 |
|
|
16,344 |
|
||||
Accumulated Other Comprehensive Income |
|
A, B, D i), ii), F, G |
|
|
|
755 |
|
|
698 |
|
|
|
833 |
|
|
811 |
|
||||
|
|
|
|
|
|
16,614 |
|
|
7,901 |
|
|
|
22,974 |
|
|
21,745 |
|
||||
|
|
|
|
|
|
$ |
33,827 |
|
|
$ |
21,219 |
|
|
|
$ |
47,247 |
|
|
$ |
45,641 |
|
EnCana Corporation |
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS U.S. GAAP
For the years ended December 31 |
|
2009 |
|
2008 |
|
2007 |
||||||
|
|
|
|
|
|
|
|
|
|
|||
Operating Activities |
|
|
|
|
|
|
|
|
|
|||
Net earnings (loss) from continuing operations |
|
$ |
(5,584 |
) |
|
$ |
5,365 |
|
|
$ |
3,311 |
|
Depreciation, depletion and amortization |
|
14,630 |
|
|
5,790 |
|
|
3,571 |
|
|||
Future income taxes |
|
(5,177 |
) |
|
1,028 |
|
|
(673 |
) |
|||
Unrealized (gain) loss on risk management |
|
2,680 |
|
|
(2,729 |
) |
|
1,251 |
|
|||
Unrealized foreign exchange (gain) loss |
|
(359 |
) |
|
417 |
|
|
41 |
|
|||
Accretion of asset retirement obligation |
|
71 |
|
|
77 |
|
|
63 |
|
|||
(Gain) loss on divestitures |
|
2 |
|
|
(141 |
) |
|
(65 |
) |
|||
Other |
|
320 |
|
|
(8 |
) |
|
97 |
|
|||
Cash flow from discontinued operations |
|
149 |
|
|
(441 |
) |
|
678 |
|
|||
Net change in other assets and liabilities |
|
23 |
|
|
(254 |
) |
|
(10 |
) |
|||
Net change in non-cash working capital from continuing operations |
|
18 |
|
|
(1,353 |
) |
|
71 |
|
|||
Net change in non-cash working capital from discontinued operations |
|
1,100 |
|
|
1,210 |
|
|
(73 |
) |
|||
|
|
|
|
|
|
|
|
|
|
|||
Cash From Operating Activities |
|
$ |
7,873 |
|
|
$ |
8,961 |
|
|
$ |
8,262 |
|
|
|
|
|
|
|
|
|
|
|
|||
Cash (Used in) Investing Activities |
|
$ |
(4,806 |
) |
|
$ |
(7,517 |
) |
|
$ |
(8,179 |
) |
|
|
|
|
|
|
|
|
|
|
|||
Cash From (Used in) Financing Activities |
|
$ |
835 |
|
|
$ |
(1,439 |
) |
|
$ |
(119 |
) |
Notes:
A) DERIVATIVE INSTRUMENTS AND HEDGING
On January 1, 2004, the Company implemented under Canadian GAAP, EIC 128 Accounting For Trading, Speculative or Non-Hedging Derivative Financial Instruments, which requires derivatives not designated as hedges to be recorded in the balance sheet as either assets or liabilities at their fair value. Changes in the derivatives fair value are recognized in current period earnings. Under the transitional rules any gain or loss at the implementation date is deferred and recognized into revenue once realized. Currently, Management has not designated any of the financial instruments as hedges.
The adoption of EIC 128 at January 1, 2004 resulted in the recognition of a $235 million deferred loss which was recognized into earnings when realized. As at December 31, 2007, under Canadian GAAP, the remaining transition amount had been fully recognized into net earnings.
The Company adopted Financial Accounting Standards Board (FASB) Accounting Standards for derivatives and hedging effective January 1, 2001. The standard requires that all derivatives be recorded in the balance sheet as either assets or liabilities at their fair value. Changes in the derivatives fair value are recognized in current period earnings unless specific hedge accounting criteria are met. Management has currently not designated any of the financial instruments as hedges for U.S. GAAP purposes. Any gain or loss on implementation of this U.S. GAAP standard was recorded in Other Comprehensive Income. These transitional amounts are recognized into net earnings as the positions are realized.
Unrealized gain (loss) on derivatives relates to:
For the years ended December 31 |
|
2009 |
|
2008 |
|
2007 |
||||||
|
|
|
|
|
|
|
|
|
|
|||
Commodity Prices (Revenues, net of royalties) |
|
$ |
(2,640 |
) |
|
$ |
2,717 |
|
|
$ |
(1,249 |
) |
Operating Expenses and Other |
|
(40 |
) |
|
12 |
|
|
- |
|
|||
Interest and Currency Swaps (Interest, net) |
|
- |
|
|
(3 |
) |
|
(2 |
) |
|||
Total Unrealized Gain (Loss) |
|
$ |
(2,680 |
) |
|
$ |
2,726 |
|
|
$ |
(1,251 |
) |
|
|
|
|
|
|
|
|
|
|
|||
Amounts Allocated to Continuing Operations |
|
$ |
(2,680 |
) |
|
$ |
2,726 |
|
|
$ |
(1,251 |
) |
Amounts Allocated to Discontinued Operations |
|
- |
|
|
- |
|
|
- |
|
|||
|
|
$ |
(2,680 |
) |
|
$ |
2,726 |
|
|
$ |
(1,251 |
) |
EnCana Corporation |
|
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
In 2008, the remaining balance related to the transitional amounts in Accumulated Other Comprehensive Income was recognized in net earnings for U.S. GAAP.
B) FULL COST ACCOUNTING
Under U.S. GAAP, a ceiling test is applied to ensure the unamortized capitalized costs in each cost centre do not exceed the sum, net of applicable income taxes, of the present value, discounted at 10 percent, of the estimated future net revenues calculated on the basis of estimated value of future production from proved reserves using an average price based upon the prior 12-month period, less related unescalated estimated future development and production costs, plus unimpaired unproved property costs.
Under Canadian GAAP, a similar ceiling test calculation is performed with the exception that cash flows from proved reserves are undiscounted and utilize forecast pricing and future development and production costs to determine whether impairment exists. The impairment amount is measured using the fair value of proved and probable reserves. Depletion charges under Canadian GAAP are also calculated by reference to proved reserves estimated using estimated future prices and costs.
At December 31, 2009, the Company's capitalized costs of oil and gas properties exceeded the full cost ceiling resulting in a non-cash U.S. GAAP write-down of $11.1 billion charged to depreciation, depletion and amortization ($7.6 billion after-tax). This write-down included $6.3 billion from properties in the United States ($4.0 billion after-tax) (2008 $1.8 billion charged to depreciation, depletion and amortization; $1.1 billion after-tax) and $4.8 billion from properties in Canada ($3.6 billion after-tax) (2008 nil). Additional depletion was also recorded in 2001, and certain prior years, as a result of the ceiling test difference between Canadian GAAP and U.S. GAAP. As a result, the depletion base of unamortized capitalized costs is less for U.S. GAAP purposes.
The U.S. GAAP adjustment for the difference in depletion calculations results in an impact to depreciation, depletion and amortization charges and foreign currency translation adjustment of $171.8 million decrease and $0.5 million decrease respectively (2008 $13.3 million decrease and $0.8 million increase; 2007 $85.4 million decrease and $2.9 million increase).
C) STOCK-BASED COMPENSATION CPL REORGANIZATION
U.S. GAAP requires that compensation expense must be recorded if the intrinsic value of the stock options is not exactly the same immediately before and after an equity restructuring. As part of the corporate reorganization of Canadian Pacific Limited (CPL), an equity restructuring occurred that resulted in CPL stock options being replaced with stock options granted by EnCana, as described in Note 17. This resulted in the replacement options having a different intrinsic value after the restructuring than prior to the restructuring. Canadian GAAP does not require revaluation of these options.
D) COMPENSATION PLANS
i) Pensions and Other Post-Employment Benefits
For the year ended December 31, 2006, the Company adopted, for U.S. GAAP purposes, the standard for retirement benefits. The standard requires EnCana to recognize the over-funded or under-funded status of defined benefit and post-employment plans on the balance sheet as an asset or liability and to recognize changes in the funded status through Other Comprehensive Income. Canadian GAAP does not require the Company to recognize the funded status of these plans on its balance sheet.
ii) Liability-Based Stock Compensation Plans
Under Canadian GAAP, obligations for liability-based stock compensation plans are recorded using the intrinsic-value method of accounting. For U.S. GAAP purposes, the Company adopted the standard for stock compensation for the year ended December 31, 2006 using the modified-prospective approach. Under the standard, the intrinsic-value method of accounting for liability-based stock compensation plans is no longer an alternative.
EnCana Corporation |
|
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
Liability-based stock compensation plans, including tandem share appreciation rights, performance tandem share appreciation rights, share appreciation rights, performance share appreciation rights and deferred share units, are required to be re-measured at fair value at each reporting period up until the settlement date.
To the extent compensation cost relates to employees directly involved in natural gas and crude oil exploration and development activities, such amounts are capitalized to property, plant and equipment. Amounts not capitalized are recognized as administrative expenses or operating expenses. The current period adjustments have the following impact:
· Net capital assets decreased by $56.4 million (2008 $37.7 million increase)
· Current liabilities decreased by $76.7 million (2008 $111.4 million increase)
· Other liabilities increased by $3.2 million (2008 $0.5 million decrease)
· Other comprehensive income decreased by $3.2 million (2008 $5.9 million increase)
· Operating expenses decreased by $31.5 million (2008 $46.1 million increase)
· Administrative expenses decreased by $21.8 million (2008 $26.7 million increase)
· Depreciation, depletion and amortization expenses decreased by $0.8 million (2008 $9.9 million increase)
E) INCOME TAXES
Under U.S. GAAP, enacted tax rates and legislative changes are used to calculate current and future income taxes, whereas Canadian GAAP uses substantively enacted tax rates and legislative changes. In 2007, a Canadian tax legislative change was substantively enacted for Canadian GAAP; however, this tax legislative change was not considered enacted for U.S. GAAP by December 31, 2007. This tax legislative change was still not considered enacted for U.S. GAAP by December 31, 2009. Accordingly, there was no difference in 2009 (2008 nil; 2007 increase to income tax expense of $179 million) for U.S. GAAP.
The remaining differences resulted from the future income tax adjustments included in the Reconciliation of Net Earnings under Canadian GAAP to U.S. GAAP and the Condensed Consolidated Balance Sheet which include the effect of such rate differences, if any, as well as the tax effect of the other reconciling items noted.
The following table provides a reconciliation of the statutory rate to the actual tax rate:
For the years ended December 31 |
|
2009 |
|
|
2008 |
|
|
2007 |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Net Earnings (Loss) Before Income Tax U.S. GAAP |
|
$ |
(8,853 |
) |
|
$ |
7,390 |
|
|
$ |
4,197 |
|
Canadian Statutory Rate |
|
29.2% |
|
|
29.7% |
|
|
32.3% |
|
|||
Expected Income Tax |
|
(2,585 |
) |
|
2,191 |
|
|
1,356 |
|
|||
Effect on Taxes Resulting from: |
|
|
|
|
|
|
|
|
|
|||
Statutory and other rate differences |
|
(389 |
) |
|
15 |
|
|
41 |
|
|||
Effect of tax rate changes |
|
- |
|
|
- |
|
|
(301 |
) |
|||
International financing |
|
(101 |
) |
|
(268 |
) |
|
(62 |
) |
|||
Foreign exchange (gains) losses not included in net earnings |
|
20 |
|
|
47 |
|
|
- |
|
|||
Non-taxable capital (gains) losses |
|
(71 |
) |
|
84 |
|
|
(124 |
) |
|||
Other |
|
(143 |
) |
|
(44 |
) |
|
(24 |
) |
|||
Income Tax U.S. GAAP |
|
$ |
(3,269 |
) |
|
$ |
2,025 |
|
|
$ |
886 |
|
Effective Tax Rate |
|
36.9% |
|
|
27.4% |
|
|
21.1% |
|
EnCana Corporation |
|
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
The net future income tax liability is comprised of:
As at December 31 |
|
2009 |
|
|
2008 |
|
||
|
|
|
|
|
|
|
||
Future Tax Liabilities |
|
|
|
|
|
|
||
Property, plant and equipment in excess of tax values |
|
$ |
- |
|
|
$ |
4,635 |
|
Timing of partnership items |
|
78 |
|
|
924 |
|
||
Risk management |
|
75 |
|
|
955 |
|
||
|
|
|
|
|
|
|
||
Future Tax Assets |
|
|
|
|
|
|
||
Tax values of property, plant and equipment in excess of carrying amounts |
|
(802 |
) |
|
- |
|
||
Non-capital and net operating losses carried forward |
|
(174 |
) |
|
(46 |
) |
||
Other |
|
(6 |
) |
|
(272 |
) |
||
Net Future Income Tax Liability |
|
$ |
(829 |
) |
|
$ |
6,196 |
|
F) OTHER COMPREHENSIVE INCOME
The U.S. GAAP standard for retirement benefits requires the funded status of defined benefit and post-employment plans to be presented on the balance sheet and changes in the funded status be recorded through comprehensive income. In 2009, a gain of $12.5 million, net of tax was recognized in Other Comprehensive Income (2008 $12 million loss, net of tax) as noted in D i). On adoption of the standard, as required, the transitional amount of $48 million, net of tax was booked directly to Accumulated Other Comprehensive Income.
The foreign currency translation adjustment includes the effect of the accumulated U.S. GAAP differences.
G) FOREIGN CURRENCY TRANSLATION
In 2009 in accordance with Canadian GAAP, the Company recognized a foreign exchange loss arising from the translation of an intercompany transaction that reduced the Companys net investment in a self-sustaining foreign operation. Under U.S. GAAP intra-entity foreign currency transactions that are of a long-term investment nature between entities that are consolidated in the Company's financial statements are not included in determining net income but reported as translation adjustments. Accordingly, net earnings under U.S. GAAP increased by $128 million with a corresponding decrease to foreign currency translation.
H) CURRENT ASSETS
In 2009, the Company reversed an impairment of inventory previously recorded in 2008 under Canadian GAAP. U.S. GAAP does not permit the reversal of inventory impairments. Accordingly, net earnings before income tax under U.S. GAAP decreased by $47 million with a corresponding decrease to the inventory balance.
I) CONSOLIDATED STATEMENT OF CASH FLOWS
Certain items presented as investing or financing activities under Canadian GAAP are required to be presented as operating activities under U.S. GAAP. Cash tax on sale of assets presented as investing activities under Canadian GAAP is presented as operating activities under U.S. GAAP.
J) DIVIDENDS DECLARED ON COMMON STOCK
For the years ended December 31 |
|
2009 |
|
|
2008 |
|
|
2007 |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Dividends per share |
|
$ |
1.40 |
|
|
$ |
1.60 |
|
|
$ |
0.80 |
|
K) RECENT ACCOUNTING PRONOUNCEMENTS
As of January 1, 2009, EnCana prospectively adopted, for U.S. GAAP purposes, ASC 805-10, Business Combinations. This revised standard requires assets and liabilities acquired in a business combination, contingent consideration, and certain acquired contingencies to be measured at their fair values as of the date of acquisition. In addition, acquisition-
EnCana Corporation |
|
Notes to Consolidated Financial Statements (prepared in US$) |
Notes to Consolidated Financial Statements
related and restructuring costs are to be recognized separately from the business combination. The adoption of this standard had no material impact on EnCana's U.S. GAAP accounting treatment of business combinations entered into after January 1, 2009.
As of January 1, 2009, EnCana adopted, for U.S. GAAP purposes, ASC 810-10 Consolidation. This standard requires a noncontrolling interest in a subsidiary to be classified as a separate component of equity. The standard also changes the way the U.S. GAAP consolidated statement of earnings is presented by requiring net earnings to include the amounts attributable to both the parent and the noncontrolling interest and to disclose these respective amounts. The adoption of this standard did not have an impact on EnCana's Consolidated Financial Statements for U.S. GAAP.
In June 2009, FASB issued the Accounting Standards Update (ASU) 2009-01, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles which establishes the FASB Accounting Standards Codification (ASC) as the sole source of authoritative accounting principles recognized by FASB for nongovernmental entities. Rules and interpretive releases of the SEC also continue to be sources of authoritative U.S. GAAP for SEC registrants. The Codification was not intended to change existing U.S. GAAP and therefore it did not have an effect on EnCanas Consolidated Financial Statements under U.S. GAAP.
As of December 31, 2009, EnCana prospectively adopted the new reserves requirements and reporting that arise from the completion of the U.S. Securities Exchange Commissions project, Modernization of Oil and Gas Reporting and FASBs Accounting Standards Update 2010-03 Oil and Gas Reserve Estimation and Disclosures. The new SEC rules and FASB standard include provisions that permit the use of new technologies to establish proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. Additionally, oil and gas reserves are now reported using an average price based upon the prior 12-month period rather than year-end prices. In addition, the FASB standard affected the amounts reported in the Supplementary Oil and Gas Information Topic 932 as discussed in that supplementary information.
EnCana Corporation |
|
Notes to Consolidated Financial Statements (prepared in US$) |
ADDITIONAL DISCLOSURE
Certifications and Disclosure Regarding Controls and Procedures.
(a) Certifications. See Exhibits 99.1, 99.2, 99.3, 99.4, 99.5 and 99.6 to this Annual Report on Form 40-F.
(b) Disclosure Controls and Procedures. As of the end of the registrants fiscal year ended December 31, 2009, an evaluation of the effectiveness of the registrants disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the Exchange Act)) was carried out by the registrants management with the participation of the principal executive officer and principal financial officer. Based upon that evaluation, the registrants principal executive officer and principal financial officers have concluded that as of the end of that fiscal year, the registrants disclosure controls and procedures are effective to ensure that information required to be disclosed by the registrant in reports that it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission (the Commission) rules and forms and (ii) accumulated and communicated to the registrants management, including its principal executive officer and principal financial officers, to allow timely decisions regarding required disclosure.
It should be noted that while the registrants principal executive officer and principal financial officers believe that the registrants disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the registrants disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
(c) Managements Annual Report on Internal Control Over Financial Reporting. The required disclosure is included in the Management Report that accompanies the registrants Consolidated Financial Statements for the fiscal year ended December 31, 2009, filed as part of this Annual Report on Form 40-F.
(d) Attestation Report of the Registered Public Accounting Firm. The required disclosure is included in the Auditors Report that accompanies the registrants Consolidated Financial Statements for the fiscal year ended December 31, 2009, filed as part of this Annual Report on Form 40-F.
(e) Changes in Internal Control Over Financial Reporting. During the fiscal year ended December 31, 2009, there were no changes in the registrants internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrants internal control over financial reporting.
Notices Pursuant to Regulation BTR.
None.
Audit Committee Financial Expert.
The registrants board of directors has determined that Jane L. Peverett, a member of the registrants audit committee, qualifies as an audit committee financial expert (as such term is defined in Form 40-F), and is independent as that term is defined in the rules of the New York Stock Exchange.
Code of Ethics.
The registrant has adopted a code of ethics (as that term is defined in Form 40-F), entitled the Business Conduct & Ethics Practice (as amended to the date of this Form 40-F, the Code of Ethics), that applies to its principal executive officer, principal financial officer, principal accounting officer or controller, and persons performing similar functions.
The Code of Ethics is available for viewing on the registrants website at www.encana.com, and is available in print to any shareholder who requests it. Requests for copies of the Code of Ethics should be made by contacting: Jeffrey G. Paulson, Corporate Secretary, EnCana Corporation, 1800, 855-2nd Street S.W., P.O. Box 2850, Calgary, Alberta, Canada T2P 2S5. Alternatively, requests for a copy of the Code of Ethics may be made by contacting the registrants Corporate Secretarial Department at (403) 645-2000 (Fax: (403) 645-4617).
Since the adoption of the Code of Ethics, there have not been any waivers, including implicit waivers, granted from any provision of the Code of Ethics.
Principal Accountant Fees and Services.
The required disclosure is included under the heading Audit Committee InformationExternal Auditor Service Fees in the registrants Annual Information Form for the fiscal year ended December 31, 2009, filed as part of this Annual Report on Form 40-F.
Pre-Approval Policies and Procedures.
The required disclosure is included under the heading Audit Committee InformationPre-Approval Policies and Procedures in the registrants Annual Information Form for the fiscal year ended December 31, 2009, filed as part of this Annual Report on Form 40-F.
Off-Balance Sheet Arrangements.
The registrant does not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on its financial condition, changes in
financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.
Tabular Disclosure of Contractual Obligations.
The required disclosure is included under the heading Contractual Obligations and ContingenciesContractual Obligations and Commitments in the registrants Managements Discussion and Analysis for the fiscal year ended December 31, 2009, filed as part of this Annual Report on Form 40-F.
Identification of the Audit Committee.
The registrant has a separately-designated standing audit committee established in accordance with Section 3(a)(58)(A) of the Exchange Act. The members of the audit committee are: Claire S. Farley, Barry W. Harrison, Suzanne P. Nimocks, Jane L. Peverett, Allan P. Sawin and David P. OBrien (ex officio).
New York Stock Exchange Disclosure.
Presiding Director at Meetings of Non-Management Directors
The registrant schedules regular executive sessions in which the registrants non-management directors (as that term is defined in the rules of the New York Stock Exchange) meet without management participation. Mr. David P. OBrien serves as the presiding director (the Presiding Director) at such sessions. Each of the registrants non-management directors is independent for the purposes of National Instrument 58-101.
Communication with Non-Management Directors
Shareholders may send communications to the registrants non-management directors by writing to the Presiding Director, c/o Jeffrey G. Paulson, Corporate Secretary, EnCana Corporation, 1800, 855 - 2nd Street S.W., P.O. Box 2850, Calgary, Alberta, Canada, T2P 2S5. Communications will be referred to the Presiding Director for appropriate action. The status of all outstanding concerns addressed to the Presiding Director will be reported to the board of directors as appropriate.
Corporate Governance Guidelines
According to Section 303A.09 of the NYSE Listed Company Manual, a listed company must adopt and disclose a set of corporate governance guidelines with respect to specified topics. Such guidelines are required to be posted on the listed companys website. The registrant operates under corporate governance principles that are consistent with the requirements of Section 303A.09 of the NYSE Listed Company Manual, and which are described under the heading "Statement of Corporate Governance Practices" in the registrants Information Circular in connection with its 2009 Annual and Special Meeting. However, the registrant has not codified its corporate governance principles into formal guidelines in order to post them on its website.
Board Committee Mandates
The Mandates of the registrants audit committee, human resources and compensation committee, and nominating and corporate governance committee are each available for viewing on the registrants website at www.encana.com.
UNDERTAKING AND CONSENT TO SERVICE OF PROCESS
A. Undertaking.
The registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.
B. Consent to Service of Process.
The registrant has previously filed a Form F-X in connection with the class of securities in relation to which the obligation to file this report arises.
Any change to the name or address of the agent for service of process of the registrant shall be communicated promptly to the Commission by an amendment to the Form F-X referencing the file number of the registrant.
SIGNATURES
Pursuant to the requirements of the Exchange Act, the registrant certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized, on February 18, 2010.
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EnCana Corporation |
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By: |
/s/ Sherri A. Brillon |
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Name: |
Sherri A. Brillon |
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Title: |
Executive
Vice-President & |
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By: |
/s/ William A. Stevenson |
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Name: |
William A. Stevenson |
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Title: |
Executive
Vice-President & |
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EXHIBIT INDEX
Exhibit |
Description |
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99.1 |
Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934 |
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99.2 |
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934 |
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99.3 |
Certification of Chief Accounting Officer pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934 |
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99.4 |
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350 |
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99.5 |
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350 |
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99.6 |
Certification of Chief Accounting Officer pursuant to 18 U.S.C. Section 1350 |
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99.7 |
Consent of PricewaterhouseCoopers LLP |
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99.8 |
Consent of McDaniel & Associates Consultants Ltd. |
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99.9 |
Consent of Netherland, Sewell & Associates, Inc. |
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99.10 |
Consent of DeGolyer and MacNaughton |
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99.11 |
Consent of GLJ Petroleum Consultants Ltd. |