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TABLE OF CONTENTS
U.S. SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 40-F
(Check One) | |
o |
Registration statement pursuant to Section 12 of the Securities Exchange Act of 1934 |
or |
|
ý |
Annual report pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 |
For the fiscal year ended December 31, 2007 |
Commission file number 1-15226
ENCANA CORPORATION
(Exact name of registrant as specified in its charter)
Canada (Province or other jurisdiction of incorporation or organization) |
1311 (Primary Standard Industrial Classification Code Number (if applicable)) |
Not applicable (I.R.S. Employer Identification Number (if Applicable)) |
||
1800-855 2nd Street, S.W., P.O. Box 2850, Calgary, Alberta, Canada T2P 2S5 (403) 645-2000 (Address and Telephone Number of Registrant's Principal Executive Offices) |
||||
CT Corporation System, 111 8th Avenue, New York, NY 10011 (212) 894-8940 (Name, Address (Including Zip Code) and Telephone Number (Including Area Code) of Agent For Service in the United States) |
||||
Securities registered or to be registered pursuant to Section 12(b) of the Act. |
Title of each class Common Shares |
Name of each exchange on which registered New York Stock Exchange |
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:
ý Annual Information Form | ý Audited Annual Financial Statements |
Indicate the number of outstanding shares of each of the issuer's classes of capital or common stock as of the close of the period covered by the annual report: 752,800,029 common shares.
Indicate by check mark whether the registrant by filing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934 (the "Exchange Act"). If "Yes" is marked, indicate the file number assigned to the registrant in connection with such rule.
Yes | o | No | ý |
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of 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.
Yes | ý | No | o |
The Annual Report on Form 40-F shall be incorporated by reference into or as an exhibit to, as applicable, each of the registrant's Registration Statements under the Securities Act of 1933: Form S-8 (File Nos. 333-124218, 333-85598, 333-13956 and 333-140856) and Form F-9 (File Nos. 333-133648, 333-133648-01 and 333-137182).
Principal Documents
The following documents have been filed as part of this Annual Report on Form 40-F, beginning on the following page:
40-F1
ANNUAL INFORMATION FORM
February 22, 2008
ENCANA CORPORATION
ANNUAL INFORMATION FORM
This is the annual information form of EnCana Corporation ("EnCana" or the "Corporation") for the year ended December 31, 2007. 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.
Unless otherwise specified, all dollar amounts are expressed in United States ("U.S.") dollars and all references to "dollars" or to "$" are to U.S. dollars and all references to "C$" are to Canadian dollars. All production and reserves information is presented on an after royalties basis consistent with U.S. reporting protocol.
Unless otherwise indicated, all financial information included in this annual information form is determined using Canadian generally accepted accounting principles ("Canadian GAAP"), which differs from generally accepted accounting principles in the United States ("U.S. GAAP"). The notes to EnCana's audited consolidated financial statements contain a discussion of the principal differences between EnCana's financial results calculated under Canadian GAAP and under U.S. GAAP.
i
ii
NOTE REGARDING FORWARD-LOOKING STATEMENTS
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: bitumen strategy and the benefits of this strategy, capital investment levels and the allocation thereof, drilling plans and the timing and location thereof, production capacity and levels and the timing of achieving such capacity and levels, the anticipated date of production for the Deep Panuke natural gas project, the timing of completion of the Foster Creek and Christina Lake expansions, including the timing for receipt of regulatory approvals and well testing, the anticipated capacities of and the timing of capacity expansions for the Wood River and Borger refineries, anticipated capacity expansion of the Steeprock natural gas plant, reserves estimates, the level of expenditures for compliance with environmental regulations, site restoration costs including abandonment and reclamation costs, pending litigation, exploration plans, acquisition and divestiture plans, anticipated post-closing adjustments and indemnities and future 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 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 oil and natural gas prices, assumptions based upon EnCana's current guidance, fluctuations in currency and interest rates, product supply and demand, market competition, risks inherent in EnCana's North American and foreign oil and natural gas 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 EnCana's and its subsidiaries' marketing operations, including credit risk, imprecision of reserves estimates and estimates of recoverable quantities of oil, natural gas and liquids from resource plays and other sources not currently classified as proved reserves, EnCana's and its subsidiaries' ability to replace and expand oil and natural gas reserves, the ability of EnCana and ConocoPhillips to successfully manage and operate the integrated North American oil business and the ability of the parties to obtain necessary regulatory approvals, refining and marketing margins, potential disruption or unexpected technical difficulties in developing new products and manufacturing processes, potential failure of new products to achieve acceptance in the market, unexpected cost increases or technical difficulties in constructing or modifying manufacturing or refining facilities, unexpected difficulties in manufacturing, transporting or refining synthetic crude oil, risks associated with technology, EnCana's ability to generate sufficient cash flow from operations to meet its current and future obligations, EnCana's ability to access external sources of debt and equity capital, general economic and business conditions, EnCana's ability to enter into or renew leases, the timing and costs of construction of gas storage facilities, wells and pipelines, EnCana's 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, EnCana's 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 risks and uncertainties described from time to time in EnCana's reports and filings with the Canadian securities authorities and the United States Securities and Exchange Commission (the "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
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produced in the future. Readers are cautioned that the foregoing list of important factors is not exhaustive. The forward-looking statements contained in this annual information form are made as of the date hereof and, 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.
NOTE REGARDING RESERVES DATA AND OTHER OIL AND GAS INFORMATION
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 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 under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made, whereas NI 51-101 requires disclosure of reserves and related future net revenue using forecast prices and costs. The definitions of proved reserves also differ, but according to the Canadian Oil and Gas Evaluation Handbook (the reference source for the definition of proved reserves under NI 51-101), differences in the estimated proved reserves quantities based on constant prices should not be material. EnCana concurs with this assessment.
EnCana has disclosed proved reserves quantities using the standards contained in SEC Regulation S-X, and the standardized measure of discounted future net cash flows relating to proved oil and gas reserves determined in accordance with United States Statement of Financial Accounting Standards No. 69 "Disclosures About Oil and Gas Producing Activities" ("SFAS 69").
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.
In this annual information form, certain crude oil and natural gas liquids ("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") 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.
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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.
EnCana was formed through the business combination (the "Merger"), on April 5, 2002, of Alberta Energy Company Ltd. ("AEC") and PanCanadian Energy Corporation ("PanCanadian").
On April 27, 2005, EnCana amended its articles to effect a two-for-one share split.
Intercorporate Relationships
The following table presents the name, the percentage of voting securities owned and the jurisdiction of incorporation, continuance or formation of EnCana's principal subsidiaries and partnerships as at December 31, 2007. Each of these subsidiaries and partnerships had total assets that exceeded 10 percent of the total consolidated assets of EnCana or revenues that exceeded 10 percent of the total consolidated revenues of EnCana as at and for the year ended December 31, 2007.
Subsidiaries & Partnerships |
Percentage Owned(1) |
Jurisdiction of Incorporation, Continuance or Formation |
||
---|---|---|---|---|
EnCana Oil & Gas Partnership | 100 | Alberta | ||
EnCana USA Holdings | 100 | Delaware | ||
3080763 Nova Scotia Company | 100 | Nova Scotia | ||
Alenco Inc. | 100 | Delaware | ||
EnCana (USA) Investment Holdings | 100 | Delaware | ||
EnCana Oil & Gas (USA) Inc. | 100 | Delaware | ||
EnCana Marketing (USA) Inc. | 100 | Delaware | ||
EnCana Oil & Gas Co. Ltd. | 100 | Alberta | ||
1140102 Alberta Ltd. | 100 | Alberta | ||
FCCL Oil Sands Partnership | 50 | Alberta | ||
EnCana Downstream Holdings LLC | 100 | Delaware | ||
EnCana US Refinery Holdings | 100 | Delaware | ||
WRB Refining LLC | 50 | Delaware | ||
Note:
The above table does not include all of the subsidiaries and partnerships of EnCana. The assets and revenues of unnamed subsidiaries and partnerships in the aggregate did not exceed 20 percent of the total consolidated assets or total consolidated revenues of EnCana as at and for the year ended December 31, 2007.
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GENERAL DEVELOPMENT OF THE BUSINESS
EnCana is one of North America's leading natural gas producers, is among the largest holders of natural gas and oil resource lands onshore North America and is a technical and cost leader in the in-situ recovery of bitumen. EnCana's other operations include the transportation and marketing of crude oil, natural gas and natural gas liquids, as well as the refining of crude oil and the marketing of refined petroleum products. EnCana pursues profitable growth from its portfolio of long-life resource plays situated in Canada and the United States. All of EnCana's proved reserves and production come from onshore North America. The Corporation is also engaged in select exploration activities internationally.
Following the Merger in 2002, the majority of EnCana's Upstream operations were located in Canada, the U.S., Ecuador and the U.K. central North Sea. From the time of the Merger through early 2004, EnCana focused on the development and expansion of its highest growth, highest return assets in these key areas. Beginning in 2004, EnCana sharpened its strategic focus to concentrate on its inventory of North American resource play assets. As part of its ongoing strategic focus, the Corporation has completed a number of acquisitions while continuing with the divestiture of its non-core assets. A portion of the divestiture proceeds were used to fund EnCana's normal course issuer bid program. In 2007, EnCana purchased approximately 38.9 million shares under the program for a total cost of approximately $2.0 billion.
In January of 2007, EnCana, with ConocoPhillips, completed the creation of an integrated oil business. This venture provides greater certainty of execution for EnCana's in-situ projects and gave EnCana immediate participation in the North American refining industry.
EnCana is organized into six operating divisions:
In 2007, for financial reporting purposes, EnCana has defined its operations into the following segments: (i) Canada, United States and Other; (ii) Integrated Oil; (iii) Market Optimization; and (iv) Corporate. All divisions are reported under Canada, United States and Other with the exception of a portion of the Integrated Oil Division and the Midstream & Marketing Division. For financial reporting purposes the integrated oil business with ConocoPhillips is reported under the Integrated Oil segment. The Integrated Oil Division's remaining assets, including the Corporation's other bitumen interests and the natural gas assets on the Cold Lake Air Weapons Range, are reported under Canada, United States and Other. The Midstream & Marketing Division is reported under Market Optimization.
The following describes the significant events of the last three years. In this section, all divestiture proceeds are provided on a before tax basis unless otherwise noted.
2007 Projects:
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The creation of this business was completed on January 3, 2007. It is comprised of two 50-50 operating entities, one Canadian upstream enterprise managed by EnCana and one U.S. downstream enterprise managed by ConocoPhillips, with both EnCana and ConocoPhillips contributing equally valued assets and equity. For further information, refer to the "Narrative Description of the Business" in this annual information form.
2007 Acquisitions:
2007 Divestitures:
In addition to the transactions completed in 2007, EnCana also announced in September 2007 that it had reached an agreement to sell all of its remaining interests in Brazil for proceeds of approximately $165 million before closing adjustments. EnCana's Brazil interests include ten offshore exploration blocks. The sale is subject to closing conditions and regulatory approvals, which are expected to be completed in the first half of 2008.
2006 Acquisitions:
2006 Divestitures:
Subsequent to the divestiture, in May 2006, the Government of Ecuador seized the Block 15 assets. As part of the sales agreement with the purchaser, EnCana had agreed to indemnify the purchaser for certain defined losses. In August 2006, EnCana paid an indemnity claim of approximately $265 million, relating to the Block 15 assets, calculated in accordance with the terms of the agreement. EnCana expects no further liability.
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2005 Projects:
2005 Acquisitions:
2005 Divestitures:
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NARRATIVE DESCRIPTION OF THE BUSINESS
The following map outlines EnCana's onshore North America landholdings and key resource plays as of December 31, 2007. The map also identifies the Borger and Wood River refineries.
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The vast majority of EnCana's operations are located in Canada and the U.S., while the Offshore & International Division is mainly focusing on opportunities in Atlantic Canada, Brazil, the Middle East and Europe. All of EnCana's proved reserves and production come from onshore North America.
At December 31, 2007, EnCana had net proved reserves of approximately 13.3 trillion cubic feet of natural gas and 0.9 billion barrels of crude oil, bitumen and NGLs, as estimated by independent qualified reserves evaluators. Proved developed reserves comprise approximately 62 percent of total natural gas reserves, approximately 77 percent of crude oil and NGLs reserves excluding bitumen and approximately 12 percent of bitumen reserves. See "Reserves and Other Oil and Gas Information" in this annual information form.
Within western Canada, EnCana has an industry-leading land position of approximately 23.3 million gross acres (approximately 20.1 million net acres, of which approximately 11.1 million net acres are undeveloped). The mineral rights on approximately 39 percent of the total net acreage are owned in fee title by EnCana, which means that 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. In 2007, EnCana had total capital investment in western Canada of approximately $3,690 million and drilled approximately 3,837 net wells.
In the U.S., EnCana's landholdings are approximately 6.0 million gross acres (approximately 4.7 million net acres, of which approximately 4.1 million net acres are undeveloped), with the majority in Texas, Colorado, Wyoming and Washington. In 2007, EnCana had total capital investment of approximately $1,919 million and drilled approximately 644 net wells within the U.S.
EnCana's international landholdings are approximately 7.4 million gross acres (approximately 4.2 million net acres), all of which are undeveloped. The majority of the lands are in Atlantic Canada, Brazil, the Middle East and Europe. In 2007, EnCana had total capital investment of approximately $106 million and drilled approximately three net wells internationally.
As noted previously, EnCana's operations are divided into six divisions. The following narrative describes each division in greater detail.
Canadian Plains Division
The Canadian Plains Division encompasses the majority of EnCana's legacy natural gas production activities in southern Alberta and Saskatchewan as well as the Corporation's crude oil (excluding in-situ bitumen) development and production activities in Alberta and Saskatchewan. Two key resource plays are located in the Canadian Plains Division: (i) Shallow Gas; and (ii) Pelican Lake. The Shallow Gas key resource play is contained within the Suffield, Brooks North and Langevin areas.
In 2007, the Canadian Plains Division had total capital investment of approximately $846 million and drilled approximately 2,264 net wells. EnCana's 2008 total capital investment in the Canadian Plains Division is projected to be approximately $820 million, which includes the drilling of approximately 1,360 net wells.
The following table summarizes landholdings for the Canadian Plains Division as at December 31, 2007.
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Undeveloped Acreage |
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Developed Acreage |
Total Acreage |
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Landholdings (thousands of acres) |
Average Working Interest |
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Gross |
Net |
Gross |
Net |
Gross |
Net |
|||||||||
Suffield | 928 | 914 | 65 | 63 | 993 | 977 | 98% | |||||||
Brooks North | 560 | 558 | 9 | 9 | 569 | 567 | 100% | |||||||
Langevin | 1,250 | 1,112 | 1,051 | 931 | 2,301 | 2,043 | 89% | |||||||
Drumheller | 362 | 350 | 17 | 14 | 379 | 364 | 96% | |||||||
Pelican Lake | 133 | 133 | 280 | 266 | 413 | 399 | 97% | |||||||
Weyburn | 96 | 84 | 597 | 591 | 693 | 675 | 97% | |||||||
Other | 955 | 890 | 871 | 790 | 1,826 | 1,680 | 92% | |||||||
Canadian Plains Total | 4,284 | 4,041 | 2,890 | 2,664 | 7,174 | 6,705 | 93% | |||||||
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The following table sets forth daily average production figures for the periods indicated.
|
Natural Gas (MMcf/d) |
Crude Oil and NGLs (bbls/d) |
Total Production (MMcfe/d) |
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---|---|---|---|---|---|---|---|---|---|---|---|---|
Production (annual average) |
||||||||||||
2007 |
2006 |
2007 |
2006 |
2007 |
2006 |
|||||||
Suffield | 245 | 241 | 15,563 | 17,350 | 338 | 345 | ||||||
Brooks North | 271 | 272 | 742 | 726 | 275 | 276 | ||||||
Langevin | 219 | 238 | 9,542 | 10,400 | 277 | 300 | ||||||
Drumheller | 97 | 104 | 2,190 | 2,251 | 110 | 118 | ||||||
Pelican Lake | 1 | 2 | 23,253 | 23,563 | 141 | 143 | ||||||
Weyburn | | | 14,774 | 15,136 | 89 | 91 | ||||||
Other | 42 | 49 | 6,136 | 7,566 | 78 | 94 | ||||||
Canadian Plains Total | 875 | 906 | 72,200 | 76,992 | 1,308 | 1,367 | ||||||
Note:
The following table summarizes EnCana's interests in producing wells as at December 31, 2007. These figures exclude wells which were capable of producing, but that were not producing as of December 31, 2007.
|
Producing Gas Wells |
Producing Oil Wells |
Total Producing Wells |
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Producing Wells (number of wells) |
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Gross |
Net |
Gross |
Net |
Gross |
Net |
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Suffield | 9,512 | 9,494 | 719 | 719 | 10,231 | 10,213 | ||||||
Brooks North | 6,543 | 6,438 | 44 | 44 | 6,587 | 6,482 | ||||||
Langevin | 6,613 | 6,067 | 225 | 220 | 6,838 | 6,287 | ||||||
Drumheller | 1,357 | 1,305 | 101 | 99 | 1,458 | 1,404 | ||||||
Pelican Lake | 6 | 6 | 438 | 438 | 444 | 444 | ||||||
Weyburn | | | 1,037 | 478 | 1,037 | 478 | ||||||
Other | 1,158 | 1,140 | 703 | 661 | 1,861 | 1,801 | ||||||
Canadian Plains Total | 25,189 | 24,450 | 3,267 | 2,659 | 28,456 | 27,109 | ||||||
Note:
The following describes EnCana's major producing areas or activities in the Canadian Plains Division.
Suffield
EnCana holds interests in the Upper Cretaceous shallow natural gas horizons and deeper formations in the Suffield area in southeast Alberta. Suffield is one of the core areas of the Shallow Gas key resource play. EnCana also produces conventional heavy oil in the area. The Suffield area is largely made up of the Suffield Block, where operations are carried out by EnCana in cooperation with the Canadian military according to guidelines established under agreements with the Government of Canada. EnCana plans to continue development of its shallow gas and heavy oil resources at Suffield. In 2008, as part of its ongoing application to continue shallow gas infill drilling in the National Wildlife Area, EnCana will be participating in an Energy Resources Conservation Board ("ERCB") (as of January 1, 2008, the Alberta Energy & Utilities Board or EUB has been realigned into two separate bodies; the ERCB regulates the oil and gas industry) joint panel hearing as part of the Canadian Environmental Assessment Act. In 2007, EnCana drilled approximately 928 net wells in the Suffield area and production averaged approximately 245 million cubic feet per day of natural gas.
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Brooks North
EnCana produces natural gas, crude oil and NGLs from the Cretaceous horizons in the Brooks North area of southern Alberta, located east of Calgary. This area is another core area of the Shallow Gas key resource play and is largely comprised of EnCana fee title lands. In 2007, EnCana drilled approximately 602 net wells in the area and production averaged approximately 271 million cubic feet per day of natural gas.
Langevin
The Langevin area produces shallow gas predominantly from the Upper Cretaceous formations in southeast Alberta and southwestern Saskatchewan. Gas production in this area is from a mix of fee title and Crown lands and is included in EnCana's Shallow Gas key resource play. Crude oil production in the area is predominantly from fee title lands located south of Brooks, Alberta. Development of this area focuses on infill drilling and optimization of existing wells. In 2007, EnCana drilled approximately 450 net wells in the area and production averaged approximately 219 million cubic feet per day of natural gas.
Drumheller
EnCana produces natural gas, crude oil and NGLs from the Cretaceous horizons in the Drumheller area of southern Alberta. The area is mainly a conventional gas play, and is largely comprised of EnCana fee title lands. In 2007, EnCana drilled approximately 204 net wells in the area and production averaged approximately 97 million cubic feet per day of natural gas.
Pelican Lake
Pelican Lake is one of EnCana's key resource plays producing heavy crude oil in northeast Alberta. In 2007, EnCana continued its expansion of its facility infrastructure to accommodate higher total fluid production volumes associated with its waterflood and polymer projects. EnCana also expanded its polymer program from 37 injection wells at the end of 2006 to 60 wells at the end of 2007.
EnCana also holds a 38 percent non-operated interest in a 110-kilometre, 20-inch diameter crude oil pipeline which connects the Pelican Lake area to a major pipeline that transports crude oil from northern Alberta to crude oil markets.
The Pelican Lake project reached royalty payout in 2006, changing the royalty from one percent of gross revenues to 25 percent of net revenues.
Weyburn
EnCana has a 62 percent working interest (50 percent economic interest) in the unitized portion of the Weyburn crude oil field in southeast Saskatchewan. EnCana is the operator and expects to improve ultimate recovery in the enhanced oil recovery area of the field with a carbon dioxide ("CO2") miscible flood project. In 2007, EnCana continued its infill drilling program with 59 new wells in the unit. As of December 31, 2007, there were 45 patterns on CO2 injection out of a planned total of 75 patterns.
Canadian Foothills Division
The Canadian Foothills Division includes EnCana's key natural gas growth assets in British Columbia and Alberta. Four key resource plays are located in the Canadian Foothills Division: (i) Greater Sierra; (ii) Cutbank Ridge; (iii) Bighorn; and (iv) Coalbed Methane ("CBM"). The CBM key resource play (Horseshoe Canyon coalbed methane and commingled shallow gas) is located within the Clearwater business unit.
In 2007, the Canadian Foothills Division had total capital investment of approximately $2,392 million and drilled approximately 1,539 net wells. EnCana's 2008 total capital investment in the Canadian Foothills Division is projected to be approximately $2,094 million, which includes the drilling of approximately 775 net wells.
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The following table summarizes landholdings for the Canadian Foothills Division as at December 31, 2007.
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Undeveloped Acreage |
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|
Developed Acreage |
Total Acreage |
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Landholdings (thousands of acres) |
Average Working Interest |
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Gross |
Net |
Gross |
Net |
Gross |
Net |
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Greater Sierra | 687 | 611 | 2,053 | 1,814 | 2,740 | 2,425 | 89% | |||||||
Cutbank Ridge | 245 | 210 | 839 | 752 | 1,084 | 962 | 89% | |||||||
Bighorn | 316 | 174 | 754 | 456 | 1,070 | 630 | 59% | |||||||
Clearwater | 3,561 | 3,159 | 3,350 | 3,140 | 6,911 | 6,299 | 91% | |||||||
Sexsmith/Hythe/Saddle Hills | 354 | 218 | 214 | 166 | 568 | 384 | 68% | |||||||
Other | 248 | 172 | 1,300 | 839 | 1,548 | 1,011 | 65% | |||||||
Canadian Foothills Total | 5,411 | 4,544 | 8,510 | 7,167 | 13,921 | 11,711 | 84% | |||||||
The following table sets forth daily average production figures for the periods indicated.
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|
Natural Gas (MMcf/d) |
Crude Oil and NGLs (bbls/d) |
Total Production (MMcfe/d) |
|||||||||
Production (annual average) |
||||||||||||
2007 |
2006 |
2007 |
2006 |
2007 |
2006 |
|||||||
Greater Sierra | 211 | 213 | 852 | 837 | 216 | 218 | ||||||
Cutbank Ridge | 234 | 170 | 98 | 82 | 235 | 170 | ||||||
Bighorn | 119 | 91 | 1,803 | 1,480 | 130 | 100 | ||||||
Clearwater(1) | 497 | 483 | 10,595 | 11,555 | 561 | 552 | ||||||
Sexsmith/Hythe/Saddle Hills | 82 | 93 | 2,015 | 2,046 | 94 | 105 | ||||||
Other | 112 | 116 | 2,909 | 3,370 | 129 | 136 | ||||||
Canadian Foothills Total | 1,255 | 1,166 | 18,272 | 19,370 | 1,365 | 1,281 | ||||||
Note:
The following table summarizes EnCana's interests in producing wells as at December 31, 2007. These figures exclude wells which were capable of producing, but that were not producing as of December 31, 2007.
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Producing Oil Wells |
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|
Producing Gas Wells |
Total Producing Wells |
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Producing Wells (number of wells) |
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Gross |
Net |
Gross |
Net |
Gross |
Net |
|||||||
Greater Sierra | 960 | 896 | 3 | 3 | 963 | 899 | ||||||
Cutbank Ridge | 470 | 417 | | | 470 | 417 | ||||||
Bighorn | 295 | 193 | 1 | | 296 | 193 | ||||||
Clearwater(1) | 8,281 | 7,566 | 180 | 112 | 8,461 | 7,678 | ||||||
Sexsmith/Hythe/Saddle Hills | 292 | 246 | 72 | 54 | 364 | 300 | ||||||
Other | 613 | 456 | 175 | 96 | 788 | 552 | ||||||
Canadian Foothills Total | 10,911 | 9,774 | 431 | 265 | 11,342 | 10,039 | ||||||
Note:
11
The following describes EnCana's major producing areas or activities in the Canadian Foothills Division.
Greater Sierra
The Greater Sierra area of northeast British Columbia is one of EnCana's key natural gas resource plays. Primary focus is on the continued development of the Devonian Jean Marie formation and the pilot development of the Devonian Shale formation.
In 2007, EnCana drilled approximately 109 net natural gas wells in the area and production averaged approximately 211 million cubic feet per day of natural gas. Production has remained relatively constant over the past two years as EnCana has reduced capital expenditures, and is currently targeting a load leveled drilling program that is expected to continue to maintain current production levels.
EnCana controls approximately 346,000 undeveloped gross acres (205,000 net acres) in the emerging Devonian Shale formation of the Horn River Basin in northeast British Columbia. The Horn River Formation shales (Muskwa, Otter Park and Evie) in EnCana's focus area are upwards of 360 feet thick and to date have been evaluated with six wells (five vertical and one horizontal), two of which have been placed on long-term production. In 2008, EnCana plans to drill, complete and tie-in four horizontal wells and participate in three others.
As at December 31, 2007, EnCana held an average 99 percent interest in 13 production facilities in the area that were capable of processing approximately 486 million cubic feet per day of natural gas. EnCana also holds a 100 percent 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.
Cutbank Ridge
Cutbank Ridge is a key natural gas resource play located in the Canadian Rocky Mountain foothills, southwest of Dawson Creek, British Columbia. Key producing horizons in Cutbank Ridge include the Cadomin, Doig and Montney zones. The majority of the Corporation's lands in this area were purchased in 2003. The Cadomin and Montney formations are almost exclusively being developed with horizontal well technology. In 2007, significant improvements were achieved with respect to horizontal well completions with the application of multi-stage hydraulic fracturing. In 2007, EnCana drilled approximately 81 net natural gas wells in the area and production averaged approximately 234 million cubic feet per day of natural gas.
EnCana's Steeprock plant has a capacity of approximately 70 million cubic feet per day and is currently under expansion to process an anticipated total of 140 million cubic feet per day.
Bighorn
The Bighorn area in west central Alberta is another of EnCana's key natural gas resource plays, focusing on exploitation of multi-zone stacked Cretaceous sands in the Deep Basin. The primary producing properties in Bighorn are Wild River, Resthaven, Kakwa, Berland and Aurora. In 2007, EnCana drilled approximately 58 net wells in the area and production averaged approximately 119 million cubic feet per day of sweet natural gas.
In 2007, new technology and regulatory approval permitting the reporting of production of commingled volumes from multiple zones allowed for significant advancements in well cost and cycle times. Pad drilling and simultaneous operations commenced in most of the areas. Well costs were reduced by approximately 25 percent and cycle times decreased by approximately 49 percent.
EnCana has a working interest in a number of natural gas plants within Bighorn. The Resthaven plant, in which EnCana has a 65 percent working interest, has a capacity of approximately 100 million cubic feet per day. The Kakwa gas plant has a capacity of approximately 30 million cubic feet per day. EnCana owns 50 percent of this plant and has firm processing capacity for the remaining 50 percent. The Wild River plant, in which EnCana holds a 70 percent working interest, has a capacity of approximately 30 million cubic feet per day and the Berland River plant, in which EnCana holds a 24 percent working interest, has a capacity of approximately 40 million cubic feet per day. In June 2007, a 20 million cubic feet per day compressor station was commissioned at Aurora along with a 27 kilometre pipeline to move the first gas volumes from this emerging property.
12
Clearwater
The Clearwater business unit extends from the U.S. border to just north of Edmonton. The primary focus of Clearwater is the CBM key natural gas resource play; however, Clearwater is also responsible for the development of the Mannville coalbed methane fairway, and deeper Cretaceous reservoirs. EnCana holds a combination of both fee lands, where it owns the mineral rights, and Crown lands within Clearwater. In 2007, EnCana drilled approximately 1,079 net CBM wells and production averaged approximately 259 million cubic feet per day of natural gas from the CBM key resource play.
Sexsmith/Hythe/Saddle Hills
EnCana produces natural gas, crude oil and NGLs in the Sexsmith/Hythe/Saddle Hills area in northwest Alberta. EnCana operates and has a 62 percent interest in the 210 million cubic feet per day Sexsmith sour natural gas and liquids processing plant. EnCana also operates and owns 100 percent of the Hythe sour natural gas plant, which has a capacity of approximately 170 million cubic feet per day. The Hythe and Sexsmith sour natural gas plants are interconnected by pipeline to provide greater operating efficiencies. In addition, EnCana owns and operates a 275-kilometre natural gas gathering system in the area. The production in this area has steadily declined over the last several years and it is no longer a primary area of focus.
USA Division
EnCana's operations in the USA Division are focused on exploiting long-life unconventional natural gas formations 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 also has landholdings in the Columbia River Basin in Washington State and the Maverick Basin in Texas. The majority of the production in the USA Division is from the following four key resource plays: (i) Jonah; (ii) Piceance; (iii) East Texas; and (iv) Fort Worth. The USA Division also has interests in natural gas gathering and processing assets, primarily in Colorado, Wyoming, Texas and Utah.
In 2007, the USA Division had total capital investment of approximately $1,919 million and drilled approximately 644 net wells. EnCana's 2008 total capital investment in the USA Division is projected to be approximately $2,510 million, which includes the drilling of approximately 650 net wells.
The following table summarizes landholdings for the USA Division as at December 31, 2007.
|
Developed Acreage |
Undeveloped Acreage |
|
|
|
|||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Total Acreage |
|
||||||||||||
Landholdings (thousands of acres) |
Average Working Interest |
|||||||||||||
Gross |
Net |
Gross |
Net |
Gross |
Net |
|||||||||
Jonah | 12 | 10 | 146 | 134 | 158 | 144 | 91% | |||||||
Piceance | 252 | 240 | 708 | 659 | 960 | 899 | 94% | |||||||
East Texas | 102 | 65 | 294 | 245 | 396 | 310 | 78% | |||||||
Fort Worth | 56 | 53 | 121 | 90 | 177 | 143 | 81% | |||||||
Maverick Basin | 17 | 15 | 345 | 220 | 362 | 235 | 65% | |||||||
Columbia River Basin | | | 878 | 397 | 878 | 397 | 45% | |||||||
Other | 278 | 186 | 2,777 | 2,375 | 3,055 | 2,561 | 84% | |||||||
USA Total | 717 | 569 | 5,269 | 4,120 | 5,986 | 4,689 | 78% | |||||||
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The following table sets forth daily average production figures for the periods indicated.
|
Natural Gas (MMcf/d) |
Crude Oil and NGLs (bbls/d) |
Total Production (MMcfe/d) |
|||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
Production (annual average) |
||||||||||||
2007 |
2006 |
2007 |
2006 |
2007 |
2006 |
|||||||
Jonah | 557 | 464 | 5,345 | 4,257 | 589 | 489 | ||||||
Piceance | 348 | 326 | 2,755 | 2,416 | 364 | 341 | ||||||
East Texas | 143 | 99 | 207 | 277 | 145 | 100 | ||||||
Fort Worth | 124 | 101 | 497 | 607 | 127 | 105 | ||||||
Other | 173 | 192 | 5,376 | 5,401 | 205 | 225 | ||||||
USA Total | 1,345 | 1,182 | 14,180 | 12,958 | 1,430 | 1,260 | ||||||
The following table summarizes EnCana's interests in producing wells as at December 31, 2007. These figures exclude wells which were capable of producing, but that were not producing as of December 31, 2007.
|
|
|
Producing Oil Wells |
Total Producing Wells |
||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Producing Gas Wells |
|||||||||||
Producing Wells (number of wells) |
||||||||||||
Gross |
Net |
Gross |
Net |
Gross |
Net |
|||||||
Jonah | 823 | 732 | | | 823 | 732 | ||||||
Piceance | 2,614 | 2,306 | | | 2,614 | 2,306 | ||||||
East Texas | 727 | 438 | | | 727 | 438 | ||||||
Fort Worth | 711 | 616 | | | 711 | 616 | ||||||
Other | 2,352 | 1,553 | 8 | 4 | 2,360 | 1,557 | ||||||
USA Total | 7,227 | 5,645 | 8 | 4 | 7,235 | 5,649 | ||||||
The following describes EnCana's major producing areas or activities in the USA Division.
Jonah
EnCana produces natural gas and associated NGLs from the Jonah field, located in the Green River Basin in southwest Wyoming. The Jonah key resource play produces 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.
EnCana currently plans to drill the field to ten acre spacing and has approximately 430 net remaining ten acre locations left to drill. Additional locations at tighter spacing are available if required to achieve optimal recovery. In 2007, EnCana drilled approximately 135 net wells in the Jonah area and production of natural gas averaged approximately 557 million cubic feet per day.
Piceance
The Piceance Basin in northwest Colorado is one of EnCana's key natural gas resource plays. The basin is characterized by thick natural gas accumulations primarily in the Williams Fork formation. EnCana's May 2004 acquisition of Tom Brown, Inc. included properties and natural gas production in the basin. In 2007, EnCana drilled approximately 286 net wells in the basin and production of natural gas averaged approximately 348 million cubic feet per day.
In 2006, EnCana finalized four agreements to jointly develop portions of the Piceance Basin. For the period 2007 to 2009, it is expected that EnCana will drill approximately 267 wells with third party funds and EnCana's partners will fund the drilling of approximately 182 more wells, allowing the third parties to earn approximately 20,000 net acres. During 2007, EnCana drilled approximately 131 net wells with third party funds and our partners drilled approximately 30 more wells.
14
In 2007, EnCana executed another development agreement with a third party, encompassing approximately 13,000 acres. EnCana's partner is expected to drill 64 wells by June 1, 2009, of which approximately 20 wells were drilled in 2007.
East Texas
EnCana produces natural gas and associated NGLs in the East Texas Basin, one of EnCana's key resource plays. EnCana first entered East Texas with the acquisition of Tom Brown, Inc. in 2004. In 2005, EnCana entered the Deep Bossier play through an acquisition of a 30 percent interest in the Leor Energy group's Deep Bossier assets. Subsequently, in 2006, EnCana increased this interest to 50 percent. In November 2007, EnCana acquired the Leor Energy group's remaining interests in the Deep Bossier play as well as additional East Texas acreage. This tight gas, multi-zone play targets the Bossier and Cotton Valley zones. During 2007, EnCana drilled approximately 35 net wells in the basin and production averaged approximately 143 million cubic feet per day of natural gas.
Fort Worth
EnCana produces natural gas and associated NGLs in the Fort Worth Basin in north Texas. The Fort Worth Basin is one of EnCana's key resource plays. Since entering the area in 2003, the Corporation has assembled a significant land position in the Barnett Shale play in this basin. EnCana is applying horizontal drilling and multi-stage reservoir stimulation to improve performance in this play. EnCana drilled approximately 75 net wells in the basin in 2007 and production averaged approximately 124 million cubic feet per day of natural gas.
Maverick Basin
EnCana controls approximately 345,000 undeveloped gross acres (220,000 net acres) in the Maverick Basin of southwest Texas. This acreage, acquired in September 2005, contains significant exploratory potential in the Pearsall Shale, plus multi-zone potential in the uphole section. In 2007, EnCana entered into a joint venture agreement to drill between three and seven wells, with an option to drill more. The first of these wells is expected to be drilled and tested in the first quarter of 2008.
Columbia River Basin
EnCana currently holds approximately 400,000 net acres in the Columbia River Basin. In 2007, EnCana concluded a three well exploration program in the basin that was funded by third party capital. The exploration wells did not flow commercial quantities of gas. EnCana has no immediate plans for further drilling in the basin.
Gathering & Processing Facilities
EnCana owns and operates various gas gathering and processing facilities within the USA Division. The Corporation's gathering, compression and processing facilities in the Piceance Basin include over 2,500 kilometres of pipelines and a processing facility with a capacity of approximately 60 million cubic feet per day. In Texas, EnCana's gathering facilities include field compression and over 715 kilometres of pipeline. Near Ft. Lupton, Colorado, the gathering and processing facilities include field compression, over 1,000 kilometres of pipelines and a processing facility with a capacity of approximately 90 million cubic feet per day. Near Moab, Utah, EnCana owns a cryogenic natural gas processing plant with a capacity of approximately 60 million cubic feet per day. In west central Wyoming, EnCana has field compression, over 500 kilometres of pipelines and a refrigeration facility with a capacity of approximately 70 million cubic feet per day.
Integrated Oil Division
The Integrated Oil Division includes all of the assets within the integrated oil business with ConocoPhillips described below, as well as the Corporation's other bitumen interests and the natural gas assets located on the Cold Lake Air Weapons Range. The Division has assets in both Canada and the U.S. and contains two key crude oil resource plays: (i) Foster Creek; and (ii) Christina Lake. As at December 31, 2007, the Corporation held bitumen rights of approximately 953,000 gross acres (656,000 net acres) within the Athabasca and Cold Lake
15
areas, as well as the exclusive rights to lease an additional 629,000 net acres on behalf of itself and/or its assignees on the Cold Lake Air Weapons Range.
In 2007, the Integrated Oil Division had total capital investment of approximately $671 million and drilled approximately 35 net wells. EnCana's 2008 total capital investment in the Integrated Oil Division is projected to be approximately $1,287 million which includes the drilling of approximately 42 net wells. Approximately $1,165 million of the total capital investment is related to the Foster Creek and Christina Lake oil projects and refinery expansion projects associated with the integrated oil business.
The following table summarizes landholdings for the Integrated Oil Division as at December 31, 2007.
|
Developed Acreage |
Undeveloped Acreage |
|
|
|
|||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Total Acreage |
|
||||||||||||
Landholdings (thousands of acres) |
Average Working Interest |
|||||||||||||
Gross |
Net |
Gross |
Net |
Gross |
Net |
|||||||||
Cold Lake Air Weapons Range | 415 | 392 | 405 | 375 | 820 | 767 | 94% | |||||||
Foster Creek(1) | 24 | 12 | 48 | 31 | 72 | 43 | 60% | |||||||
Christina Lake | 1 | | 27 | 14 | 28 | 14 | 50% | |||||||
Borealis | | | 37 | 37 | 37 | 37 | 100% | |||||||
Other | 173 | 103 | 1,090 | 767 | 1,263 | 870 | 69% | |||||||
Integrated Oil Total | 613 | 507 | 1,607 | 1,224 | 2,220 | 1,731 | 78% | |||||||
Note:
The following table sets forth daily average production figures for the periods indicated.
|
Natural Gas (MMcf/d) |
Crude Oil and NGLs (bbls/d) |
Total Production (MMcfe/d) |
|||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
Production (annual average) |
||||||||||||
2007 |
2006 |
2007 |
2006 |
2007 |
2006 |
|||||||
Cold Lake Air Weapons Range | 86 | 106 | | | 86 | 106 | ||||||
Foster Creek | | | 24,262 | 36,910 | 146 | 221 | ||||||
Christina Lake | | | 2,552 | 5,858 | 15 | 35 | ||||||
Other | 5 | 7 | 2,688 | 5,185 | 21 | 38 | ||||||
Integrated Oil Total | 91 | 113 | 29,502 | 47,953 | 268 | 400 | ||||||
Note:
The following table summarizes EnCana's interests in producing wells as at December 31, 2007. These figures exclude wells which were capable of producing, but that were not producing as of December 31, 2007.
|
Producing Gas Wells |
Producing Oil Wells |
Total Producing Wells |
|||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
Producing Wells (number of wells) |
||||||||||||
Gross |
Net |
Gross |
Net |
Gross |
Net |
|||||||
Cold Lake Air Weapons Range | 707 | 664 | | | 707 | 664 | ||||||
Foster Creek | | | 84 | 42 | 84 | 42 | ||||||
Christina Lake | 6 | 3 | 9 | 5 | 15 | 8 | ||||||
Other | | | 26 | 23 | 26 | 23 | ||||||
Integrated Oil Total | 713 | 667 | 119 | 70 | 832 | 737 | ||||||
16
The following describes EnCana's major producing areas or activities in the Integrated Oil Division.
Cold Lake Air Weapons Range
EnCana produces natural gas from the Cold Lake Air Weapons Range located in northeast Alberta. EnCana holds surface access and natural gas rights for exploration, development and transportation from areas within the Cold Lake Air Weapons Range which were granted by the Government of Canada. The majority of EnCana's natural gas production in the area is processed through wholly owned and operated compression facilities.
In 2007, natural gas production was impacted by the September 2003, July 2004, September 2004 and July 2007 ERCB decisions to shut-in McMurray, Wabiska and Clearwater natural gas production that may put at risk the recovery of bitumen resources in the area. The decisions resulted in a decrease in annualized natural gas production of approximately 20 million cubic feet per day in 2007 (18 million cubic feet per day in 2006). On September 1, 2007, approximately 29 additional wells were shut-in in accordance with the July 2007 ERCB decision. There were no additional wells shut-in in 2006. The Alberta Government's Department of Energy ("ADOE") is providing financial assistance in the form of a royalty credit, which is equal to approximately 50 percent of the cash flow lost as a result of the shut-in wells.
Foster Creek
At December 31, 2007, EnCana had a 50 percent working interest in Foster Creek, one of EnCana's key crude oil resource plays. EnCana holds surface access rights from the Governments of Canada and Alberta and bitumen rights for exploration, development and transportation from areas within the Cold Lake Air Weapons Range which were granted by the Government of Alberta. Additionally, EnCana has the exclusive rights to lease several hundred thousand acres of bitumen rights in other areas on the Cold Lake Air Weapons Range on behalf of itself and/or its assignees. EnCana is currently operating an in-situ oil recovery project in the Foster Creek area using steam-assisted gravity drainage ("SAGD") technology.
In the fourth quarter of 2006, EnCana completed the second stage of an expansion that added an additional 20,000 barrels of bitumen per day of capacity, increasing production capacity at Foster Creek to approximately 60,000 barrels per day. Current expansions are already underway and are expected to increase production capacity to approximately 120,000 barrels of bitumen per day by the end of 2009.
EnCana continues to research and develop technologies to increase recovery and decrease the costs of extracting crude oil bitumen. One focus area is alternate methods of artificial lift where EnCana is operating new pump designs that are expected to enable the Corporation to optimize SAGD performance by operating at lower pressures, thereby realizing lower steam-oil ratios and decreasing facility capital costs. At December 31, 2007, EnCana had 68 wells on electrical submersible pumps at Foster Creek, and the Corporation expects to continue to utilize this technology on new SAGD wells.
EnCana is also focused on reducing its reliance on natural gas for the production of steam in bitumen production. EnCana has piloted two technologies using solvents as part of the extraction process. The Vapex process, which uses solvent in place of steam, was piloted at Foster Creek from 2002 to 2005. Results from the Vapex pilot are being utilized during investigations into new production strategies for bitumen recovery. The Solvent Aided Process ("SAP") is discussed in the Christina Lake section.
EnCana continues to operate its 80 megawatt natural gas-fired cogeneration facility in conjunction with its SAGD operation at Foster Creek. The steam and power generated by the facility is being used within the SAGD operation and the excess power generated is being sold into the Alberta Power Pool grid.
Christina Lake
At December 31, 2007, EnCana had a 50 percent working interest in a SAGD oil recovery project at Christina Lake, one of EnCana's key crude oil resource plays. Current expansions already underway are expected to increase production capacity to approximately 18,000 barrels per day by the second half of 2008. In 2007, EnCana continued to utilize the remote water disposal system to successfully manage bottom water pressures and improve the steam-oil ratio.
17
The next phase of expansion at Christina Lake which is expected to increase production capacity by approximately 40,000 barrels of bitumen per day has been approved by the FCCL Oil Sands Partnership ("FCCL"). Regulatory approval had previously been received for development at Christina Lake for up to 70,000 barrels of bitumen per day. In July 2007, EnCana filed an amended application with the ERCB to expand the Christina Lake development plan to 100,000 barrels of bitumen per day. Approval of the amended plan is expected by mid-year 2008, with construction expected to take approximately two years to complete. This next phase of expansion is expected to increase production capacity to approximately 58,000 barrels of bitumen per day.
In 2004, EnCana commenced a pilot SAP program at Christina Lake. This process mixes a small amount of solvent with steam to enhance recovery. EnCana continues to produce and monitor current SAP pilot wells and recently began work with another SAP well test in the main reservoir. This second SAP test well is scheduled to start steaming in 2008 and is expected to provide information on optimal well spacing. Business cases are being evaluated for the potential use of this technology in the Christina Lake development plan.
Borealis
EnCana has a 100 percent working interest in the Borealis area, which is located approximately 90 kilometres north of Fort McMurray. Borealis is not included in the venture with ConocoPhillips. As of December 31, 2007, EnCana has drilled approximately 191 delineation wells in the Greater Borealis area since 2000. A joint application for development has been submitted to the ERCB and Alberta Environment that would allow for the construction of a SAGD facility with production capacity of approximately 35,000 barrels of bitumen per day. Production from this facility is expected to commence in 2015. In 2008, EnCana plans to continue its evaluation of the Greater Borealis area by drilling nine more wells to test specific reservoir properties of the McMurray Formation and to test for potential water disposal zones.
Integrated Oil Business
On January 3, 2007, EnCana completed the creation of an integrated oil business with ConocoPhillips. The integrated oil business includes Canadian upstream assets contributed by EnCana and U.S. downstream assets contributed by ConocoPhillips.
The upstream portion of the integrated oil business is conducted through FCCL which owns the Foster Creek and Christina Lake in-situ oil recovery projects contributed by EnCana. EnCana and ConocoPhillips each own 50 percent of FCCL. EnCana is the operating and managing partner of FCCL. The downstream portion of the integrated oil business is conducted through WRB Refining LLC ("WRB") which owns the Wood River and Borger refineries contributed by ConocoPhillips. EnCana and ConocoPhillips each own 50 percent of WRB; however, ConocoPhillips held a disproportionate economic interest in the Borger refinery of 85 percent in 2007 and will have a 65 percent interest in 2008 before reverting to 50 percent in 2009. ConocoPhillips is the operator and manager of WRB. FCCL has a Management Committee, while WRB has a Board of Directors; both are comprised of three EnCana and three ConocoPhillips representatives, with each company holding equal voting rights.
The goal of FCCL is to increase production to approximately 400,000 barrels per day of bitumen by 2015, with the intention to transport and sell the bitumen at major Alberta trading hubs.
18
The following table summarizes the combined refineries' key operational results for 2007.
Refinery Operations(1) |
2007 |
|
---|---|---|
Crude Oil Capacity (Mbbls/d) | 452 | |
Crude Oil Runs (Mbbls/d) | 432 | |
Crude Utilization (%) | 96% | |
Refined Products (Mbbls/d) | ||
Gasoline | 246 | |
Distillates | 128 | |
Other | 83 | |
Total | 457 | |
Note:
The Borger refinery, located in Borger, Texas, has a current capacity of approximately 146,000 barrels per day of crude oil and approximately 45,000 barrels per day of NGLs. It processes mainly medium, high-sulphur and heavy, high-sulphur crude oil and NGLs that it receives from North American pipeline systems to produce gasoline, diesel and jet fuel along with NGLs and solvents. The refined products are transported via pipelines to markets in Texas, New Mexico, Colorado and the mid-continent. In July 2007, a new coker with a capacity of approximately 25,000 barrels per day was brought into service along with a new vacuum unit and revamped gas oil and distillate hydrotreaters. This project has enabled the refinery to process heavy oil blends, particularly Canadian bitumen, and comply with clean fuel regulations for ultra-low sulphur diesel and low-sulphur gasoline. The project has also enabled compliance with required reductions of sulphur dioxide emissions.
The Wood River refinery, located in Roxana, Illinois, has a current capacity of approximately 306,000 barrels per day of crude oil. It processes mainly light, low-sulphur and heavy, high-sulphur crude oil that it receives from North American crude oil pipelines to produce gasoline, diesel and jet fuel, petrochemical feedstocks and asphalt. The gasoline and diesel are transported via pipelines to markets in the upper midwest. Other products are transported via pipeline, truck, barge and railcar to markets in the midwest. In early 2007, the refinery completed the construction of a facility utilizing proprietary sulphur removal technology for the production of low-sulphur gasoline.
The goal of WRB is to refine approximately 275,000 barrels per day of bitumen to primarily motor fuels by 2015. Currently, WRB has processing capability to refine up to approximately 70,000 barrels per day of bitumen.
Offshore & International Division
The Offshore & International Division invests a small portion of EnCana's capital in exploration opportunities, primarily in Atlantic Canada, Brazil, the Middle East and Europe. In 2007, EnCana's Offshore & International Division had total capital investment of approximately $106 million and drilled approximately three net wells. EnCana's 2008 total capital investment in the Offshore & International Division is projected to be approximately $56 million, which includes the drilling of approximately one net well and the commencement of the major contracting activities related to the development of the Deep Panuke natural gas project.
Atlantic Canada
At December 31, 2007, EnCana held an interest in approximately 533,000 gross acres (177,000 net acres) in Atlantic Canada, which includes Nova Scotia and Newfoundland and Labrador. EnCana operates five of its ten licenses in these areas and has an average working interest of approximately 33 percent.
EnCana is the operator of the Deep Panuke gas field, located offshore Nova Scotia, and has an approximate 78 percent interest at December 31, 2007, based upon proposed unitization. EnCana is currently moving forward with the development of the Deep Panuke natural gas project. In June 2006, EnCana and the Province of Nova Scotia reached an Offshore Strategic Energy Agreement that established the framework for the potential development of the Deep Panuke natural gas project. Subsequently, in November 2006, EnCana filed the
19
Development Plan Application ("DPA") with the Canada-Nova Scotia Offshore Petroleum Board. The filing included an Environmental Assessment Report and an application to the National Energy Board for approval of the construction and operation of an offshore pipeline. Regulatory approval of the DPA was received from the Governments of Nova Scotia and Canada on October 2, 2007. EnCana's Board of Directors authorized funding for the development of the Deep Panuke natural gas project on October 23, 2007. In November 2007, EnCana announced it had entered into an agreement with Single Buoy Moorings Inc. for the provision and operation of the Deep Panuke production field centre. The Deep Panuke natural gas project is expected to start production in late 2010.
Brazil
EnCana has non-operated interests in ten deep and ultra-deep water exploration blocks offshore Brazil, nine of which are operated by Petrobras, the Brazilian national oil company. EnCana's landholdings on these offshore blocks total approximately 1.7 million gross acres (522,000 net acres) with an average working interest of approximately 31 percent.
In September 2007, EnCana reached an agreement to sell all of its remaining interests in Brazil. The sale is subject to closing conditions and regulatory approvals, which are expected to be completed in the first half of 2008.
Middle East
EnCana has a 50 percent working interest in Block 2, which encompasses most of the onshore lands in the State of Qatar and covers approximately 2.2 million gross acres (1.1 million net acres). One well commenced drilling in the third quarter of 2007 and completed drilling in January 2008. The results are currently being evaluated. A second well is scheduled for the first quarter of 2008.
Greenland
At December 31, 2007, EnCana had an approximate 87 percent working interest in two exploration blocks offshore Greenland, comprising approximately 1.7 million gross acres (1.5 million net acres). In late 2007, EnCana received regulatory approval for the farmout of 40 percent of its interest in both blocks effective January 1, 2008. EnCana plans to conduct a seabed logging program in 2008 as part of its current work commitment.
France
EnCana has a 100 percent interest in the Foix exploration permit, which encompasses approximately 859,000 gross acres in the onshore Aquitaine Basin in southwest France. The Corporation drilled two exploration wells in 2007. Both wells have been abandoned. EnCana continues to evaluate plans for 2008.
Midstream & Marketing Division
EnCana's divisional marketing groups are focused on enhancing the netback price of the Corporation's proprietary production. Correspondingly, the Midstream & Marketing Division coordinates the market optimization activities that include third party purchases and sales of product to provide operational flexibility for transportation commitments, product type, delivery points and customer diversification. In addition, EnCana's power assets are managed to optimize the Corporation's electricity costs, particularly in the province of Alberta.
Natural Gas Marketing
In 2007, approximately 92 percent of EnCana's sales of produced natural gas were directly marketed by EnCana to local distribution companies, industrials, other producers and energy marketing companies. The remaining eight percent of sales of produced natural gas were marketed to aggregators who supply natural gas to markets throughout North America. Prices received by EnCana are based primarily upon prevailing index prices
20
for natural gas. Prices are impacted by competing fuels in such markets and by regional supply and demand for natural gas.
EnCana mitigates the market risk associated with forecasted cash flows by entering into various risk management contracts relating to produced natural gas. For 2008, after taking into account its risk management contracts, EnCana's gas sales price portfolio exposure consists of approximately 1.6 billion cubic feet per day for 2008 at an average fixed NYMEX price of approximately $8.21 per million cubic feet with the remainder unhedged. Details of these transactions are found in Note 18 to EnCana's audited consolidated financial statements for the year ended December 31, 2007.
Crude Oil Marketing
EnCana, through its operating divisions, sells and manages the transportation of its western Canadian crude oil to markets in Canada and the U.S. (95,082 barrels per day in 2007 and 132,760 barrels per day in 2006). Crude oil sales are normally executed under spot, term and monthly evergreen contracts with delivery to major pipeline hubs, such as Edmonton and Hardisty, in Alberta, with EnCana arranging the intermediate transportation on the feeder pipeline systems. Sales are also made on a delivered basis using trunk pipeline systems, such as the Enbridge system, for sales to U.S. refinery destinations.
EnCana provides North American marketing services to certain organizations on a fee for service basis. In 2007, EnCana provided marketing services to the ADOE (17,314 barrels per day in 2007 and 45,542 barrels per day in 2006). This agency agreement ended in May of 2007. Additionally, in 2007, EnCana marketed 71,415 barrels per day of blend oil on behalf of FCCL. This agency agreement became effective on January 2, 2007.
To help mitigate the market risk associated with forecasted cash flows, EnCana enters into various risk management contracts relating to crude oil. Details of these transactions are found in Note 18 to EnCana's audited consolidated financial statements for the year ended December 31, 2007.
Power
EnCana is a large consumer of electricity in Alberta and uses a portfolio of physical assets, short to medium term purchases and sales and spot market purchases to manage the cost of electricity for its operating divisions in Alberta's deregulated market. The physical assets include two, 106 megawatt gas-fired power plants in southern Alberta. The Cavalier Power Station, located approximately 54 kilometres east of Calgary, is 100 percent owned and operated by EnCana. The Balzac Power Station, in which EnCana holds a 50 percent non-operated interest, is also located near Calgary. EnCana's electricity requirements in Alberta are approximately 185 megawatts and its generation capacity is approximately 159 megawatts, excluding both the electricity requirements and generation capacity of the Integrated Oil Division.
21
RESERVES AND OTHER OIL AND GAS INFORMATION
EnCana has retained independent qualified reserves evaluators to evaluate and prepare reports on 100 percent of EnCana's natural gas, crude oil and NGLs reserves annually since its inception. In 2007, EnCana's Canadian reserves were evaluated by McDaniel & Associates Consultants Ltd. and GLJ Petroleum Consultants Ltd., and its U.S. reserves were evaluated by Netherland, Sewell & Associates, Inc. and DeGolyer and MacNaughton.
EnCana has a Reserves Committee of independent board members which reviews the qualifications and appointment of the independent qualified reserves evaluators. The Reserves Committee also reviews the procedures for providing information to the evaluators. All booked reserves are based upon annual evaluations by the independent qualified reserves evaluators. The evaluations are conducted from the fundamental geological and engineering data.
Reserves Quantities Information
EnCana's natural gas reserves increased by approximately seven percent in 2007 as a result of successful exploration and development drilling, which resulted in extensions and discoveries of 1,776 billion cubic feet. Changes in the revisions and improved recovery category for natural gas reserves were positive at 165 billion cubic feet, or approximately one percent of proved natural gas reserves at the beginning of 2007. Reserve additions from revisions and improved recovery and extensions and discoveries were generally equally distributed between Canada and the U.S. Approximately 12 percent of natural gas additions in 2007 were due to acquisitions, with approximately 75 percent of these additions attributable to the Leor Energy group acquisition.
In 2006 and 2005, natural gas reserves increased primarily from development and exploration drilling.
EnCana's crude oil and NGLs reserves were down approximately eighteen percent at year end 2007 in comparison to year end 2006 as a consequence of the contribution of the Corporation's interests in Foster Creek and Christina Lake into the integrated oil business effective January 2, 2007. Subsequent to this transaction, EnCana's crude oil and NGLs reserves increased approximately 26 percent over the balance of the year, mainly due to additions at Foster Creek and Christina Lake.
In 2006, significant increases in proved reserves primarily at Foster Creek and Christina Lake were offset by the completion of the sale of EnCana's interests in Ecuador and negative revisions in Canada. The downward revision in Canada was a consequence of net reserves being reduced in light of higher calculated average royalty rates at Foster Creek stemming from an almost two fold increase in field prices relative to the prior year end.
In 2005, crude oil and NGLs reserves increased significantly, largely as a result of the reinstatement, due to prices at year end 2005, of 363 million barrels that appeared as a downward revision in 2004 due to anomalously lower bitumen prices at year end 2004.
In keeping with U.S. standards requiring that the reserves and related future net revenue be estimated under existing economic and operating conditions (i.e., prices and costs as of the date that the estimate is made), reference year end 2007 prices were as follows: crude oil (WTI) $95.95/bbl, (Edmonton Light) C$93.39/bbl, increases of 58 percent and 38 percent from year end 2006, respectively; Foster Creek field price C$49.60/bbl, an increase of 41 percent from year end 2006; natural gas (Henry Hub) $6.80/MMbtu, an increase of 20 percent from year end 2006; and natural gas (AECO) C$6.63/MMbtu, an increase of 9 percent from year end 2006.
Each year, EnCana reviews the methodologies employed to arrive at year end prices to ensure that they are determined in a manner which is most consistent with SEC standards. At year end 2007, this review has resulted in EnCana changing its methodology with respect to bitumen price determination, placing greater emphasis on spot prices for the Western Canadian Select marker.
The following table sets forth reserves continuity information prepared by EnCana in accordance with U.S. disclosure standards, including SFAS 69. The end of year numbers represent estimates derived from the reports of the independent qualified reserves evaluators referred to above.
22
Net Proved Reserves (EnCana Share After Royalties)(1,2)
Constant Pricing
|
Natural Gas (billions of cubic feet) |
Crude Oil and Natural Gas Liquids (millions of barrels) |
|||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Canada |
United States |
Total |
Canada |
United States |
Ecuador |
Total |
||||||||
2005 |
|||||||||||||||
Beginning of year | 5,824 | 4,636 | 10,460 | 266.9 | 91.0 | 143.3 | 501.2 | ||||||||
Revisions due to bitumen price | | | | 362.7 | (3) | | | 362.7 | |||||||
Beginning of year before bitumen revisions | 5,824 | 4,636 | 10,460 | 629.6 | 91.0 | 143.3 | 863.9 | ||||||||
Revisions and improved recovery | 202 | (260 | ) | (58 | ) | 222.1 | (3.2 | ) | 8.1 | 227.0 | |||||
Extensions and discoveries | 1,289 | 1,252 | 2,541 | 148.1 | 8.9 | 10.2 | 167.2 | ||||||||
Purchase of reserves in place | 7 | 76 | 83 | | 0.4 | | 0.4 | ||||||||
Sale of reserves in place | (30 | ) | (37 | ) | (67 | ) | (15.1 | ) | (39.0 | ) | | (54.1 | ) | ||
Production | (775 | ) | (400 | ) | (1,175 | ) | (52.2 | ) | (5.0 | ) | (26.6 | ) | (83.8 | ) | |
End of year | 6,517 | 5,267 | 11,784 | 932.5 | 53.1 | 135.0 | (4) | 1,120.6 | |||||||
Developed | 4,513 | 2,718 | 7,231 | 318.7 | 32.2 | 104.0 | 454.9 | ||||||||
Undeveloped | 2,004 | 2,549 | 4,553 | 613.8 | 20.9 | 31.0 | 665.7 | ||||||||
Total | 6,517 | 5,267 | 11,784 | 932.5 | 53.1 | 135.0 | 1,120.6 | ||||||||
2006 |
|||||||||||||||
Beginning of year | 6,517 | 5,267 | 11,784 | 932.5 | 53.1 | 135.0 | 1,120.6 | ||||||||
Revisions and improved recovery | 301 | (88 | ) | 213 | (39.0 | ) | (1.1 | ) | | (40.1 | ) | ||||
Extensions and discoveries | 1,014 | 606 | 1,620 | 238.7 | 6.4 | | 245.1 | ||||||||
Purchase of reserves in place | | 68 | 68 | | 0.3 | | 0.3 | ||||||||
Sale of reserves in place | (6 | ) | (32 | ) | (38 | ) | (0.1 | ) | | (130.6 | ) | (130.7 | ) | ||
Production | (798 | ) | (431 | ) | (1,229 | ) | (52.7 | ) | (4.7 | ) | (4.4 | ) | (61.8 | ) | |
End of year | 7,028 | 5,390 | 12,418 | 1,079.4 | (5) | 54.0 | | 1,133.4 | |||||||
Developed | 4,718 | 2,964 | 7,682 | 316.9 | 33.5 | | 350.4 | ||||||||
Undeveloped | 2,310 | 2,426 | 4,736 | 762.5 | 20.5 | | 783.0 | ||||||||
Total | 7,028 | 5,390 | 12,418 | 1,079.4 | (5) | 54.0 | | 1,133.4 | |||||||
2007 |
|||||||||||||||
Beginning of year | 7,028 | 5,390 | 12,418 | 1,079.4 | 54.0 | | 1,133.4 | ||||||||
FCCL Partnership contribution | | | | (398.0) | (5) | | | (398.0 | ) | ||||||
Effective Jan 2, 2007 | 7,028 | 5,390 | 12,418 | 681.4 | 54.0 | | 735.4 | ||||||||
Revisions and improved recovery | 87 | 78 | 165 | 75.5 | 3.6 | | 79.1 | ||||||||
Extensions and discoveries | 949 | 827 | 1,776 | 155.8 | 5.9 | | 161.7 | ||||||||
Purchase of reserves in place | 63 | 211 | 274 | 0.2 | | | 0.2 | ||||||||
Sale of reserves in place | (24 | ) | (7 | ) | (31 | ) | (0.2 | ) | | | (0.2 | ) | |||
Production | (811 | ) | (491 | ) | (1,302 | ) | (43.8 | ) | (5.2 | ) | | (49.0 | ) | ||
End of year | 7,292 | 6,008 | 13,300 | 868.9 | 58.3 | | 927.2 | ||||||||
Developed | 4,868 | 3,368 | 8,236 | 289.5 | 37.0 | | 326.5 | ||||||||
Undeveloped | 2,424 | 2,640 | 5,064 | 579.4 | 21.3 | | 600.7 | ||||||||
Total | 7,292 | 6,008 | 13,300 | 868.9 | 58.3 | | 927.2 | ||||||||
Notes:
23
Other Disclosures About Oil and Gas Activities
The tables in this section set forth oil and gas information prepared by EnCana in accordance with U.S. disclosure standards, including SFAS 69.
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein
In calculating the standardized measure of discounted future net cash flows, year-end constant prices and cost assumptions were applied to EnCana's annual future production from proved reserves to determine cash inflows. Future production and development costs are based on constant price assumptions and 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 EnCana's independent qualified reserves evaluators in relation to the reserves they respectively evaluated, and adjusted by EnCana to account for management's estimates of price risk management activities, 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 EnCana's 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 EnCana's Market Optimization interests.
Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas Reserves
|
Canada |
United States |
|||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2007 |
2006 |
2005 |
2007 |
2006 |
2005 |
|||||||
|
($ millions) |
||||||||||||
Future cash inflows | 95,778 | 72,262 | 71,786 | 38,398 | 27,165 | 40,504 | |||||||
Less future: | |||||||||||||
Production costs | 25,089 | 20,471 | 16,765 | 5,869 | 4,123 | 3,262 | |||||||
Development costs | 10,171 | 9,355 | 6,164 | 6,943 | 4,715 | 4,174 | |||||||
Asset retirement obligation payments | 3,320 | 2,397 | 2,269 | 532 | 396 | 264 | |||||||
Income taxes | 12,871 | 8,816 | 13,170 | 7,375 | 5,349 | 11,041 | |||||||
Future net cash flows | 44,327 | 31,223 | 33,418 | 17,679 | 12,582 | 21,763 | |||||||
Less 10% annual discount for estimated timing of cash flows | 21,663 | 14,627 | 13,281 | 8,196 | 6,128 | 10,291 | |||||||
Discounted future net cash flows | 22,664 | 16,596 | 20,137 | 9,483 | 6,454 | 11,472 | |||||||
|
Ecuador |
Total |
|||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2007 |
2006 |
2005 |
2007 |
2006 |
2005 |
|||||||
|
($ millions) |
||||||||||||
Future cash inflows | | | 5,350 | 134,176 | 99,427 | 117,640 | |||||||
Less future: | |||||||||||||
Production costs | | | 2,093 | 30,958 | 24,594 | 22,120 | |||||||
Development costs | | | 429 | 17,114 | 14,070 | 10,767 | |||||||
Asset retirement obligation payments | | | 24 | 3,852 | 2,793 | 2,557 | |||||||
Income taxes | | | 662 | 20,246 | 14,165 | 24,873 | |||||||
Future net cash flows | | | 2,142 | 62,006 | 43,805 | 57,323 | |||||||
Less 10% annual discount for estimated timing of cash flows | | | 574 | 29,859 | 20,755 | 24,146 | |||||||
Discounted future net cash flows | | | 1,568 | 32,147 | 23,050 | 33,177 | |||||||
24
Changes in Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas Reserves
|
Canada |
United States |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2007 |
2006 |
2005 |
2007 |
2006 |
2005 |
||||||||
|
($ millions) |
|||||||||||||
Balance, beginning of year | 16,596 | 20,137 | 12,178 | 6,454 | 11,472 | 7,488 | ||||||||
Changes resulting from: | ||||||||||||||
Sales of oil and gas produced during the period | (6,055 | ) | (5,970 | ) | (5,720 | ) | (3,281 | ) | (2,373 | ) | (2,436 | ) | ||
Discoveries and extensions, net of related costs | 3,796 | 2,584 | 4,278 | 1,591 | 877 | 3,582 | ||||||||
Purchases of proved reserves in place | 129 | | 26 | 372 | 69 | 237 | ||||||||
Sales of proved reserves in place | (2,933 | ) | (19 | ) | (279 | ) | (15 | ) | (85 | ) | (486 | ) | ||
Net change in prices and production costs | 11,077 | (5,797 | ) | 11,624 | 4,818 | (7,636 | ) | 4,716 | ||||||
Revisions to quantity estimates | 823 | 155 | 1,071 | 830 | 265 | (700 | ) | |||||||
Accretion of discount | 2,087 | 2,809 | 1,629 | 924 | 1,714 | 1,103 | ||||||||
Previously estimated development costs incurred net of change in future development costs | (667 | ) | (805 | ) | (888 | ) | (907 | ) | (350 | ) | 162 | |||
Other | (82 | ) | (174 | ) | 63 | (113 | ) | (381 | ) | (64 | ) | |||
Net change in income taxes | (2,107 | ) | 3,676 | (3,845 | ) | (1,190 | ) | 2,882 | (2,130 | ) | ||||
Balance, end of year | 22,664 | 16,596 | 20,137 | 9,483 | 6,454 | 11,472 | ||||||||
|
Ecuador |
Total |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2007 |
2006 |
2005 |
2007 |
2006 |
2005 |
||||||||
|
($ millions) |
|||||||||||||
Balance, beginning of year | | 1,568 | 1,202 | 23,050 | 33,177 | 20,868 | ||||||||
Changes resulting from: | ||||||||||||||
Sales of oil and gas produced during the period | | (142 | ) | (604 | ) | (9,336 | ) | (8,485 | ) | (8,760 | ) | |||
Discoveries and extensions, net of related costs | | | 159 | 5,387 | 3,461 | 8,019 | ||||||||
Purchases of proved reserves in place | | | | 501 | 69 | 263 | ||||||||
Sales of proved reserves in place | | (1,359 | ) | | (2,948 | ) | (1,463 | ) | (765 | ) | ||||
Net change in prices and production costs | | | 967 | 15,895 | (13,433 | ) | 17,307 | |||||||
Revisions to quantity estimates | | | 88 | 1,653 | 420 | 459 | ||||||||
Accretion of discount | | | 147 | 3,011 | 4,523 | 2,879 | ||||||||
Previously estimated development costs incurred net of change in future development costs | | (46 | ) | (148 | ) | (1,574 | ) | (1,201 | ) | (874 | ) | |||
Other | | | 8 | (195 | ) | (555 | ) | 7 | ||||||
Net change in income taxes | | (21 | ) | (251 | ) | (3,297 | ) | 6,537 | (6,226 | ) | ||||
Balance, end of year | | | 1,568 | 32,147 | 23,050 | 33,177 | ||||||||
25
Results of Operations, Capitalized Costs and Costs Incurred
Results of Operations
|
Canada |
United States |
Ecuador(1) |
||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2007 |
2006 |
2005 |
2007 |
2006 |
2005 |
2007 |
2006 |
2005 |
||||||||||
|
($ millions) |
||||||||||||||||||
Oil and gas revenues, net of royalties, transportation and selling costs | 7,362 | 7,190 | 6,701 | 4,065 | 3,096 | 3,052 | | 190 | 873 | ||||||||||
Less: | |||||||||||||||||||
Operating costs, production and mineral taxes, and accretion of asset retirement obligations | 1,307 | 1,220 | 981 | 784 | 723 | 616 | | 48 | 269 | ||||||||||
Depreciation, depletion and amortization | 2,298 | 2,146 | 1,961 | 1,181 | 869 | 712 | | 84 | 234 | ||||||||||
Operating income (loss) | 3,757 | 3,824 | 3,759 | 2,100 | 1,504 | 1,724 | | 58 | 370 | ||||||||||
Income taxes | 1,114 | 1,235 | 1,274 | 809 | 556 | 638 | | 21 | 134 | ||||||||||
Results of operations | 2,643 | 2,589 | 2,485 | 1,291 | 948 | 1,086 | | 37 | 236 | ||||||||||
|
Other |
Total |
|||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2007 |
2006 |
2005 |
2007 |
2006 |
2005 |
|||||||
|
($ millions) |
||||||||||||
Oil and gas revenues, net of royalties, transportation and selling costs | (1 | ) | 2 | | 11,426 | 10,478 | 10,626 | ||||||
Less: | |||||||||||||
Operating costs, production and mineral taxes, and accretion of asset retirement obligations | 18 | 11 | 6 | 2,109 | 2,002 | 1,872 | |||||||
Depreciation, depletion and amortization | 69 | 10 | 8 | 3,548 | 3,109 | 2,915 | |||||||
Operating income (loss) | (88 | ) | (19 | ) | (14 | ) | 5,769 | 5,367 | 5,839 | ||||
Income taxes | | | | 1,923 | 1,812 | 2,046 | |||||||
Results of operations | (88 | ) | (19 | ) | (14 | ) | 3,846 | 3,555 | 3,793 | ||||
Note:
Capitalized Costs
|
Canada |
United States |
Ecuador |
|||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2007 |
2006 |
2005 |
2007 |
2006 |
2005 |
2007 |
2006 |
2005 |
|||||||||
|
($ millions) |
|||||||||||||||||
Proved oil and gas properties | 36,874 | 31,546 | 27,074 | 13,738 | 9,796 | 7,753 | | | 1,926 | |||||||||
Unproved oil and gas properties | 1,380 | 1,700 | 1,998 | 1,852 | 1,221 | 870 | | | 18 | |||||||||
Total capital cost | 38,254 | 33,246 | 29,072 | 15,590 | 11,017 | 8,623 | | | 1,944 | |||||||||
Accumulated DD&A | 19,286 | 14,261 | 12,131 | 3,783 | 2,595 | 1,750 | | | 778 | |||||||||
Net capitalized costs | 18,968 | 18,985 | 16,941 | 11,807 | 8,422 | 6,873 | | | 1,166 | |||||||||
|
Other |
Total |
||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2007 |
2006 |
2005 |
2007 |
2006 |
2005 |
||||||
|
($ millions) |
|||||||||||
Proved oil and gas properties | | | | 50,612 | 41,342 | 36,753 | ||||||
Unproved oil and gas properties | 297 | 361 | 470 | 3,529 | 3,282 | 3,356 | ||||||
Total capital cost | 297 | 361 | 470 | 54,141 | 44,624 | 40,109 | ||||||
Accumulated DD&A | 160 | 98 | 222 | 23,229 | 16,954 | 14,881 | ||||||
Net capitalized costs | 137 | 263 | 248 | 30,912 | 27,670 | 25,228 | ||||||
26
Costs Incurred
|
Canada |
United States |
Ecuador |
|||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2007 |
2006 |
2005 |
2007 |
2006 |
2005 |
2007 |
2006 |
2005 |
|||||||||
|
($ millions) |
|||||||||||||||||
Acquisitions | ||||||||||||||||||
Unproved | 28 | | | 1,048 | 278 | 271 | | | | |||||||||
Proved | 61 | 47 | 30 | 1,565 | 6 | 141 | | | | |||||||||
Total acquisitions | 89 | 47 | 30 | 2,613 | 284 | 412 | | | | |||||||||
Exploration costs | 427 | 403 | 817 | 48 | 236 | 264 | | 1 | 15 | |||||||||
Development costs | 3,309 | 3,611 | 3,333 | 1,871 | 1,826 | 1,724 | | 46 | 164 | |||||||||
Total costs incurred | 3,825 | 4,061 | 4,180 | 4,532 | 2,346 | 2,400 | | 47 | 179 | |||||||||
|
Other |
Total |
||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2007 |
2006 |
2005 |
2007 |
2006 |
2005 |
||||||
|
($ millions) |
|||||||||||
Acquisitions | ||||||||||||
Unproved | | | | 1,076 | 278 | 271 | ||||||
Proved | | | | 1,626 | 53 | 171 | ||||||
Total acquisitions | | | | 2,702 | 331 | 442 | ||||||
Exploration costs | 60 | 75 | 70 | 535 | 715 | 1,166 | ||||||
Development costs | | | | 5,180 | 5,483 | 5,221 | ||||||
Total costs incurred | 60 | 75 | 70 | 8,417 | 6,529 | 6,829 | ||||||
27
Production Volumes and Per-Unit Results
Production Volumes
The following tables summarize net daily production volumes for EnCana on a quarterly basis for the periods indicated.
|
Production Volumes 2007 |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Year |
Q4 |
Q3 |
Q2 |
Q1 |
||||||||
PRODUCTION VOLUMES | |||||||||||||
Continuing Operations: |
|||||||||||||
Produced Gas (MMcf/d) |
|||||||||||||
Canada | 2,221 | 2,258 | 2,243 | 2,203 | 2,178 | ||||||||
United States | 1,345 | 1,464 | 1,387 | 1,303 | 1,222 | ||||||||
Total Produced Gas | 3,566 | 3,722 | 3,630 | 3,506 | 3,400 | ||||||||
Oil and Natural Gas Liquids (bbls/d) |
|||||||||||||
North America | |||||||||||||
Light and Medium Oil | 40,690 | 40,462 | 40,345 | 40,025 | 41,946 | ||||||||
Heavy Oil Foster Creek/Christina Lake | 26,814 | 27,190 | 28,740 | 27,994 | 23,269 | ||||||||
Heavy Oil Other | 41,472 | 41,621 | 40,882 | 40,897 | 42,500 | ||||||||
Natural Gas Liquids(1) | |||||||||||||
Canada | 11,316 | 12,388 | 11,141 | 11,017 | 10,700 | ||||||||
United States | 13,862 | 14,476 | 15,275 | 13,483 | 12,175 | ||||||||
Total Oil and Natural Gas Liquids | 134,154 | 136,137 | 136,383 | 133,416 | 130,590 | ||||||||
Total Continuing Operations (MMcfe/d) | 4,371 | 4,539 | 4,448 | 4,306 | 4,184 | ||||||||
Note:
28
|
Production Volumes 2006 |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Year |
Q4 |
Q3 |
Q2 |
Q1 |
||||||||
PRODUCTION VOLUMES | |||||||||||||
Continuing Operations: |
|||||||||||||
Produced Gas (MMcf/d) |
|||||||||||||
Canada | 2,185 | 2,205 | 2,162 | 2,192 | 2,182 | ||||||||
United States | 1,182 | 1,201 | 1,197 | 1,169 | 1,161 | ||||||||
Total Produced Gas | 3,367 | 3,406 | 3,359 | 3,361 | 3,343 | ||||||||
Oil and Natural Gas Liquids (bbls/d) |
|||||||||||||
North America | |||||||||||||
Light and Medium Oil | 44,440 | 41,972 | 46,454 | 43,672 | 45,680 | ||||||||
Heavy Oil Foster Creek/Christina Lake | 42,768 | 46,678 | 43,073 | 39,215 | 42,050 | ||||||||
Heavy Oil Other | 45,858 | 41,913 | 43,287 | 44,572 | 53,822 | ||||||||
Natural Gas Liquids(1) | |||||||||||||
Canada | 11,713 | 11,856 | 11,387 | 11,607 | 12,006 | ||||||||
United States | 12,494 | 12,250 | 12,520 | 12,793 | 12,415 | ||||||||
Total Oil and Natural Gas Liquids | 157,273 | 154,669 | 156,721 | 151,859 | 165,973 | ||||||||
Total Continuing Operations (MMcfe/d) | 4,311 | 4,334 | 4,299 | 4,272 | 4,339 | ||||||||
Discontinued Operations: |
|||||||||||||
Ecuador (bbls/d) |
11,996 |
|
|
|
48,650 |
||||||||
Total Discontinued Operations (MMcfe/d) | 72 | | | | 292 | ||||||||
Total (MMcfe/d) | 4,383 | 4,334 | 4,299 | 4,272 | 4,631 | ||||||||
Note:
29
|
Production Volumes 2005 |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Year |
Q4 |
Q3 |
Q2 |
Q1 |
||||||||
PRODUCTION VOLUMES | |||||||||||||
Continuing Operations: |
|||||||||||||
Produced Gas (MMcf/d) |
|||||||||||||
Canada | 2,125 | 2,172 | 2,123 | 2,151 | 2,052 | ||||||||
United States | 1,095 | 1,154 | 1,099 | 1,061 | 1,067 | ||||||||
Total Produced Gas | 3,220 | 3,326 | 3,222 | 3,212 | 3,119 | ||||||||
Oil and Natural Gas Liquids (bbls/d) |
|||||||||||||
North America | |||||||||||||
Light and Medium Oil | 47,032 | 45,777 | 42,989 | 48,381 | 51,084 | ||||||||
Heavy Oil Foster Creek/Christina Lake | 34,379 | 39,839 | 32,580 | 31,025 | 34,027 | ||||||||
Heavy Oil Other | 49,814 | 52,625 | 50,856 | 49,421 | 46,273 | ||||||||
Natural Gas Liquids(1) | |||||||||||||
Canada | 11,907 | 12,287 | 11,924 | 11,719 | 11,692 | ||||||||
United States | 13,675 | 12,824 | 14,131 | 13,095 | 14,666 | ||||||||
Total Oil and Natural Gas Liquids | 156,807 | 163,352 | 152,480 | 153,641 | 157,742 | ||||||||
Total Continuing Operations (MMcfe/d) | 4,161 | 4,306 | 4,137 | 4,134 | 4,065 | ||||||||
Discontinued Operations: |
|||||||||||||
Ecuador (bbls/d) | 72,916 | 70,480 | 71,896 | 73,662 | 75,695 | ||||||||
Total Discontinued Operations (MMcfe/d) | 437 | 423 | 431 | 442 | 454 | ||||||||
Total (MMcfe/d) | 4,598 | 4,729 | 4,568 | 4,576 | 4,519 | ||||||||
Note:
30
The following tables summarize net per-unit results for EnCana on a quarterly basis for the periods indicated. The results exclude the impact of realized financial hedging.
|
Per-Unit Results 2007 |
||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
|
Year |
Q4 |
Q3 |
Q2 |
Q1 |
||||||
Continuing Operations: | |||||||||||
Produced Gas Canada ($/Mcf) |
|||||||||||
Price | 6.20 | 6.35 | 5.36 | 6.76 | 6.36 | ||||||
Production and mineral taxes | 0.09 | 0.03 | 0.10 | 0.11 | 0.10 | ||||||
Transportation and selling | 0.35 | 0.35 | 0.34 | 0.36 | 0.36 | ||||||
Operating | 0.92 | 1.03 | 0.83 | 0.90 | 0.91 | ||||||
Netback | 4.84 | 4.94 | 4.09 | 5.39 | 4.99 | ||||||
Produced Gas United States ($/Mcf) | |||||||||||
Price | 5.38 | 5.03 | 4.68 | 5.73 | 6.24 | ||||||
Production and mineral taxes | 0.34 | 0.29 | 0.38 | 0.17 | 0.53 | ||||||
Transportation and selling | 0.62 | 0.64 | 0.60 | 0.65 | 0.61 | ||||||
Operating | 0.65 | 0.70 | 0.52 | 0.71 | 0.67 | ||||||
Netback | 3.77 | 3.40 | 3.18 | 4.20 | 4.43 | ||||||
Produced Gas Total ($/Mcf) | |||||||||||
Price | 5.89 | 5.83 | 5.10 | 6.38 | 6.32 | ||||||
Production and mineral taxes | 0.18 | 0.14 | 0.21 | 0.14 | 0.26 | ||||||
Transportation and selling | 0.45 | 0.46 | 0.44 | 0.47 | 0.45 | ||||||
Operating | 0.82 | 0.90 | 0.72 | 0.83 | 0.82 | ||||||
Netback | 4.44 | 4.33 | 3.73 | 4.94 | 4.79 | ||||||
Natural Gas Liquids Canada ($/bbl) | |||||||||||
Price | 59.34 | 73.39 | 62.87 | 55.21 | 43.26 | ||||||
Production and mineral taxes | | | | | | ||||||
Transportation and selling | 1.01 | 0.96 | 1.80 | 0.74 | 0.54 | ||||||
Netback | 58.33 | 72.43 | 61.07 | 54.47 | 42.72 | ||||||
Natural Gas Liquids United States ($/bbl) | |||||||||||
Price | 59.83 | 73.45 | 60.17 | 55.43 | 47.77 | ||||||
Production and mineral taxes | 4.28 | 6.12 | 1.95 | 4.71 | 4.56 | ||||||
Transportation and selling | 0.01 | | 0.01 | 0.01 | 0.01 | ||||||
Netback | 55.54 | 67.33 | 58.21 | 50.71 | 43.20 | ||||||
Natural Gas Liquids Total ($/bbl) | |||||||||||
Price | 59.61 | 73.42 | 61.31 | 55.33 | 45.66 | ||||||
Production and mineral taxes | 2.36 | 3.30 | 1.13 | 2.59 | 2.43 | ||||||
Transportation and selling | 0.46 | 0.44 | 0.76 | 0.34 | 0.26 | ||||||
Netback | 56.79 | 69.68 | 59.42 | 52.40 | 42.97 | ||||||
Crude Oil Light and Medium ($/bbl) | |||||||||||
Price | 58.12 | 71.48 | 61.18 | 53.36 | 46.40 | ||||||
Production and mineral taxes | 2.11 | 2.20 | 1.89 | 2.19 | 2.14 | ||||||
Transportation and selling | 1.41 | 1.30 | 1.53 | 1.36 | 1.43 | ||||||
Operating | 9.72 | 11.09 | 9.51 | 9.28 | 9.00 | ||||||
Netback | 44.88 | 56.89 | 48.25 | 40.53 | 33.83 | ||||||
31
|
Per-Unit Results 2007 |
||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
|
Year |
Q4 |
Q3 |
Q2 |
Q1 |
||||||
Crude Oil Total excluding Foster Creek/Christina Lake ($/bbl) | |||||||||||
Price | 50.76 | 59.93 | 54.68 | 47.02 | 41.42 | ||||||
Production and mineral taxes | 1.09 | 1.12 | 1.01 | 1.16 | 1.06 | ||||||
Transportation and selling | 1.32 | 1.23 | 1.47 | 1.31 | 1.27 | ||||||
Operating | 9.03 | 10.52 | 8.68 | 8.85 | 8.06 | ||||||
Netback | 39.32 | 47.06 | 43.52 | 35.70 | 31.03 | ||||||
Crude Oil Heavy Foster Creek/Christina Lake ($/bbl) | |||||||||||
Price | 40.14 | 45.58 | 42.86 | 39.40 | 33.28 | ||||||
Production and mineral taxes | | | | | | ||||||
Transportation and selling | 2.88 | 2.75 | 2.10 | 3.62 | 3.07 | ||||||
Operating(1,2) | 14.46 | 14.05 | 12.55 | 14.02 | 17.12 | ||||||
Netback | 22.80 | 28.78 | 28.21 | 21.76 | 13.09 | ||||||
Crude Oil Total ($/bbl) | |||||||||||
Price | 47.90 | 56.23 | 51.50 | 44.92 | 39.19 | ||||||
Production and mineral taxes | 0.79 | 0.83 | 0.74 | 0.84 | 0.77 | ||||||
Transportation and selling | 1.74 | 1.62 | 1.64 | 1.94 | 1.75 | ||||||
Operating | 10.49 | 11.43 | 9.72 | 10.27 | 10.54 | ||||||
Netback | 34.88 | 42.35 | 39.40 | 31.87 | 26.13 | ||||||
Total Liquids Canada ($/bbl) | |||||||||||
Price | 48.92 | 57.92 | 52.50 | 45.83 | 39.50 | ||||||
Production and mineral taxes | 0.72 | 0.74 | 0.66 | 0.76 | 0.70 | ||||||
Transportation and selling | 1.68 | 1.56 | 1.66 | 1.84 | 1.67 | ||||||
Operating | 9.47 | 10.20 | 8.78 | 9.29 | 9.60 | ||||||
Netback | 37.05 | 45.42 | 41.40 | 33.94 | 27.53 | ||||||
Total Liquids ($/bbl) | |||||||||||
Price | 50.05 | 59.60 | 53.37 | 46.81 | 40.25 | ||||||
Production and mineral taxes | 1.08 | 1.32 | 0.81 | 1.16 | 1.04 | ||||||
Transportation and selling | 1.51 | 1.39 | 1.47 | 1.65 | 1.51 | ||||||
Operating | 8.57 | 9.19 | 7.87 | 8.41 | 8.81 | ||||||
Netback | 38.89 | 47.70 | 43.22 | 35.59 | 28.89 | ||||||
Total ($/Mcfe) | |||||||||||
Price | 6.35 | 6.57 | 5.80 | 6.65 | 6.40 | ||||||
Production and mineral taxes | 0.18 | 0.15 | 0.19 | 0.15 | 0.24 | ||||||
Transportation and selling | 0.42 | 0.42 | 0.41 | 0.43 | 0.42 | ||||||
Operating(3) | 0.93 | 1.02 | 0.83 | 0.93 | 0.95 | ||||||
Netback | 4.82 | 4.98 | 4.37 | 5.14 | 4.79 | ||||||
Notes:
32
|
Per-Unit Results 2006 |
||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
|
Year |
Q4 |
Q3 |
Q2 |
Q1 |
||||||
Continuing Operations: | |||||||||||
Produced Gas Canada ($/Mcf) |
|||||||||||
Price | 6.20 | 5.87 | 5.59 | 5.71 | 7.66 | ||||||
Production and mineral taxes | 0.10 | 0.05 | 0.09 | 0.08 | 0.18 | ||||||
Transportation and selling | 0.35 | 0.33 | 0.37 | 0.35 | 0.34 | ||||||
Operating | 0.79 | 0.82 | 0.78 | 0.77 | 0.79 | ||||||
Netback | 4.96 | 4.67 | 4.35 | 4.51 | 6.35 | ||||||
Produced Gas United States ($/Mcf) | |||||||||||
Price | 6.35 | 5.65 | 6.04 | 6.08 | 7.70 | ||||||
Production and mineral taxes | 0.49 | 0.50 | 0.43 | 0.22 | 0.85 | ||||||
Transportation and selling | 0.54 | 0.60 | 0.57 | 0.50 | 0.49 | ||||||
Operating | 0.65 | 0.68 | 0.59 | 0.70 | 0.64 | ||||||
Netback | 4.67 | 3.87 | 4.45 | 4.66 | 5.72 | ||||||
Produced Gas Total ($/Mcf) | |||||||||||
Price | 6.25 | 5.79 | 5.75 | 5.84 | 7.68 | ||||||
Production and mineral taxes | 0.24 | 0.21 | 0.21 | 0.13 | 0.41 | ||||||
Transportation and selling | 0.42 | 0.42 | 0.44 | 0.40 | 0.40 | ||||||
Operating | 0.74 | 0.77 | 0.71 | 0.74 | 0.74 | ||||||
Netback | 4.85 | 4.39 | 4.39 | 4.57 | 6.13 | ||||||
Natural Gas Liquids Canada ($/bbl) | |||||||||||
Price | 51.12 | 44.79 | 55.95 | 55.19 | 48.84 | ||||||
Production and mineral taxes | | | | | | ||||||
Transportation and selling | 0.67 | 0.58 | 0.74 | 0.73 | 0.61 | ||||||
Netback | 50.45 | 44.21 | 55.21 | 54.46 | 48.23 | ||||||
Natural Gas Liquids United States ($/bbl) | |||||||||||
Price | 56.33 | 51.04 | 61.76 | 58.25 | 54.07 | ||||||
Production and mineral taxes | 4.19 | 4.62 | 4.42 | 2.60 | 5.18 | ||||||
Transportation and selling | 0.01 | 0.01 | 0.01 | 0.01 | 0.01 | ||||||
Netback | 52.13 | 46.41 | 57.33 | 55.64 | 48.88 | ||||||
Natural Gas Liquids Total ($/bbl) | |||||||||||
Price | 53.81 | 47.97 | 58.99 | 56.80 | 51.50 | ||||||
Production and mineral taxes | 2.16 | 2.35 | 2.31 | 1.36 | 2.63 | ||||||
Transportation and selling | 0.33 | 0.29 | 0.36 | 0.35 | 0.31 | ||||||
Netback | 51.32 | 45.33 | 56.32 | 55.09 | 48.56 | ||||||
Crude Oil Light and Medium ($/bbl) | |||||||||||
Price | 51.76 | 43.28 | 56.50 | 61.62 | 45.31 | ||||||
Production and mineral taxes | 2.16 | 2.15 | 2.13 | 2.47 | 1.92 | ||||||
Transportation and selling | 0.98 | 0.61 | 1.32 | 0.65 | 1.29 | ||||||
Operating | 8.62 | 9.01 | 10.00 | 7.36 | 8.06 | ||||||
Netback | 40.00 | 31.51 | 43.05 | 51.14 | 34.04 | ||||||
33
|
Per-Unit Results 2006 |
||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
|
Year |
Q4 |
Q3 |
Q2 |
Q1 |
||||||
Crude Oil Total excluding Foster Creek/Christina Lake ($/bbl) | |||||||||||
Price | 44.83 | 37.65 | 51.37 | 55.58 | 35.39 | ||||||
Production and mineral taxes | 1.11 | 1.11 | 1.14 | 1.28 | 0.92 | ||||||
Transportation and selling | 0.91 | 0.60 | 1.27 | 0.76 | 1.00 | ||||||
Operating | 7.69 | 8.59 | 8.73 | 6.84 | 6.67 | ||||||
Netback | 35.12 | 27.35 | 40.23 | 46.70 | 26.80 | ||||||
Crude Oil Heavy Foster Creek/Christina Lake ($/bbl) | |||||||||||
Price | 36.49 | 39.32 | 37.19 | 46.53 | 23.08 | ||||||
Production and mineral taxes | | | | | | ||||||
Transportation and selling | 2.64 | 2.74 | 2.64 | 3.38 | 1.80 | ||||||
Operating(1) | 12.38 | 13.07 | 14.06 | 11.78 | 10.39 | ||||||
Netback | 21.47 | 23.51 | 20.49 | 31.37 | 10.89 | ||||||
Crude Oil Total ($/bbl) | |||||||||||
Price | 41.83 | 36.94 | 48.74 | 51.62 | 30.76 | ||||||
Production and mineral taxes | 0.77 | 0.74 | 0.81 | 0.88 | 0.66 | ||||||
Transportation and selling | 1.40 | 1.11 | 1.74 | 1.54 | 1.24 | ||||||
Operating | 9.09 | 10.05 | 10.20 | 8.34 | 7.82 | ||||||
Netback | 30.57 | 25.04 | 35.99 | 40.86 | 21.04 | ||||||
Total Liquids Canada ($/bbl) | |||||||||||
Price | 42.53 | 37.55 | 49.21 | 51.91 | 32.17 | ||||||
Production and mineral taxes | 0.70 | 0.67 | 0.73 | 0.80 | 0.61 | ||||||
Transportation and selling | 1.35 | 1.06 | 1.67 | 1.48 | 1.19 | ||||||
Operating | 8.33 | 9.21 | 9.39 | 7.63 | 7.17 | ||||||
Netback | 32.15 | 26.61 | 37.42 | 42.00 | 23.20 | ||||||
Total Liquids ($/bbl) | |||||||||||
Price | 43.71 | 38.69 | 50.37 | 52.44 | 33.87 | ||||||
Production and mineral taxes | 0.99 | 0.99 | 1.05 | 0.96 | 0.96 | ||||||
Transportation and selling | 1.24 | 0.98 | 1.52 | 1.35 | 1.10 | ||||||
Operating | 7.66 | 8.47 | 8.58 | 7.01 | 6.64 | ||||||
Netback | 33.82 | 28.25 | 39.22 | 43.12 | 25.17 | ||||||
Total ($/Mcfe) | |||||||||||
Price | 6.48 | 5.93 | 6.31 | 6.46 | 7.22 | ||||||
Production and mineral taxes | 0.22 | 0.20 | 0.20 | 0.13 | 0.36 | ||||||
Transportation and selling | 0.37 | 0.37 | 0.40 | 0.36 | 0.35 | ||||||
Operating(2) | 0.86 | 0.90 | 0.87 | 0.84 | 0.82 | ||||||
Netback | 5.03 | 4.46 | 4.84 | 5.13 | 5.69 | ||||||
Discontinued Operations: |
|||||||||||
Crude Oil Ecuador ($/bbl) |
|||||||||||
Price | 44.35 | | | | 44.35 | ||||||
Production and mineral taxes | 5.03 | | | | 5.03 | ||||||
Transportation and selling | 2.25 | | | | 2.25 | ||||||
Operating | 5.55 | | | | 5.55 | ||||||
Netback | 31.52 | | | | 31.52 | ||||||
Notes:
34
|
Per-Unit Results 2005 |
||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
|
Year |
Q4 |
Q3 |
Q2 |
Q1 |
||||||
Continuing Operations: | |||||||||||
Produced Gas Canada ($/Mcf) |
|||||||||||
Price | 7.27 | 10.00 | 7.18 | 6.08 | 5.70 | ||||||
Production and mineral taxes | 0.10 | 0.10 | 0.10 | 0.10 | 0.09 | ||||||
Transportation and selling | 0.36 | 0.36 | 0.36 | 0.36 | 0.37 | ||||||
Operating | 0.67 | 0.72 | 0.68 | 0.62 | 0.65 | ||||||
Netback | 6.14 | 8.82 | 6.04 | 5.00 | 4.59 | ||||||
Produced Gas United States ($/Mcf) | |||||||||||
Price | 7.82 | 10.84 | 7.51 | 6.60 | 6.04 | ||||||
Production and mineral taxes | 0.81 | 1.19 | 0.75 | 0.65 | 0.62 | ||||||
Transportation and selling | 0.46 | 0.45 | 0.49 | 0.42 | 0.46 | ||||||
Operating | 0.53 | 0.60 | 0.55 | 0.50 | 0.45 | ||||||
Netback | 6.02 | 8.60 | 5.72 | 5.03 | 4.51 | ||||||
Produced Gas Total ($/Mcf) | |||||||||||
Price | 7.46 | 10.29 | 7.29 | 6.25 | 5.81 | ||||||
Production and mineral taxes | 0.34 | 0.48 | 0.32 | 0.28 | 0.27 | ||||||
Transportation and selling | 0.40 | 0.39 | 0.41 | 0.38 | 0.40 | ||||||
Operating | 0.62 | 0.68 | 0.64 | 0.58 | 0.58 | ||||||
Netback | 6.10 | 8.74 | 5.92 | 5.01 | 4.56 | ||||||
Natural Gas Liquids Canada ($/bbl) | |||||||||||
Price | 44.24 | 49.51 | 47.39 | 39.55 | 40.04 | ||||||
Production and mineral taxes | | | | | | ||||||
Transportation and selling | 0.42 | 0.46 | 0.48 | 0.39 | 0.35 | ||||||
Netback | 43.82 | 49.05 | 46.91 | 39.16 | 39.69 | ||||||
Natural Gas Liquids United States ($/bbl) | |||||||||||
Price | 48.36 | 54.14 | 53.92 | 44.79 | 40.93 | ||||||
Production and mineral taxes | 4.86 | 5.42 | 5.46 | 4.37 | 4.20 | ||||||
Transportation and selling | 0.01 | 0.01 | 0.01 | 0.01 | 0.01 | ||||||
Netback | 43.49 | 48.71 | 48.45 | 40.41 | 36.72 | ||||||
Natural Gas Liquids Total ($/bbl) | |||||||||||
Price | 46.44 | 51.87 | 50.93 | 42.32 | 40.53 | ||||||
Production and mineral taxes | 2.60 | 2.77 | 2.96 | 2.31 | 2.34 | ||||||
Transportation and selling | 0.20 | 0.23 | 0.23 | 0.19 | 0.16 | ||||||
Netback | 43.64 | 48.87 | 47.74 | 39.82 | 38.03 | ||||||
Crude Oil Light and Medium ($/bbl) | |||||||||||
Price | 45.09 | 46.27 | 55.41 | 41.44 | 38.57 | ||||||
Production and mineral taxes | 1.54 | 1.83 | 1.29 | 1.71 | 1.32 | ||||||
Transportation and selling | 1.20 | 1.14 | 1.29 | 1.20 | 1.19 | ||||||
Operating | 6.34 | 6.41 | 6.24 | 6.34 | 6.38 | ||||||
Netback | 36.01 | 36.89 | 46.59 | 32.19 | 29.68 | ||||||
35
|
Per-Unit Results 2005 |
||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
|
Year |
Q4 |
Q3 |
Q2 |
Q1 |
||||||
Crude Oil Total excluding Foster Creek/Christina Lake ($/bbl) | |||||||||||
Price | 38.49 | 40.43 | 49.44 | 33.06 | 31.71 | ||||||
Production and mineral taxes | 0.79 | 0.93 | 0.65 | 0.86 | 0.71 | ||||||
Transportation and selling | 1.08 | 0.95 | 1.12 | 0.89 | 1.38 | ||||||
Operating | 5.90 | 6.04 | 6.15 | 5.58 | 5.86 | ||||||
Netback | 30.72 | 32.51 | 41.52 | 25.73 | 23.76 | ||||||
Crude Oil Heavy Foster Creek/Christina Lake ($/bbl) | |||||||||||
Price | 22.02 | 20.17 | 33.11 | 19.28 | 15.92 | ||||||
Production and mineral taxes | | | | | | ||||||
Transportation and selling | 1.54 | 1.53 | 1.24 | 2.02 | 1.42 | ||||||
Operating(1) | 10.94 | 11.93 | 10.74 | 11.71 | 9.25 | ||||||
Netback | 9.54 | 6.71 | 21.13 | 5.55 | 5.25 | ||||||
Crude Oil Total ($/bbl) | |||||||||||
Price | 34.15 | 34.41 | 45.16 | 29.83 | 27.60 | ||||||
Production and mineral taxes | 0.58 | 0.66 | 0.48 | 0.66 | 0.53 | ||||||
Transportation and selling | 1.20 | 1.12 | 1.15 | 1.15 | 1.39 | ||||||
Operating | 7.23 | 7.79 | 7.35 | 7.02 | 6.74 | ||||||
Netback | 25.14 | 24.84 | 36.18 | 21.00 | 18.94 | ||||||
Total Liquids Canada ($/bbl) | |||||||||||
Price | 34.97 | 35.65 | 45.35 | 30.58 | 28.60 | ||||||
Production and mineral taxes | 0.53 | 0.60 | 0.43 | 0.61 | 0.48 | ||||||
Transportation and selling | 1.14 | 1.07 | 1.09 | 1.09 | 1.31 | ||||||
Operating | 6.61 | 7.13 | 6.66 | 6.45 | 6.19 | ||||||
Netback | 26.69 | 26.85 | 37.17 | 22.43 | 20.62 | ||||||
Total Liquids ($/bbl) | |||||||||||
Price | 36.17 | 37.16 | 46.16 | 31.80 | 29.77 | ||||||
Production and mineral taxes | 0.91 | 0.99 | 0.91 | 0.92 | 0.83 | ||||||
Transportation and selling | 1.04 | 0.98 | 0.99 | 1.00 | 1.18 | ||||||
Operating | 6.04 | 6.56 | 6.08 | 5.91 | 5.61 | ||||||
Netback | 28.18 | 28.63 | 38.18 | 23.97 | 22.15 | ||||||
Total ($/Mcfe) | |||||||||||
Price | 7.13 | 9.37 | 7.38 | 6.03 | 5.62 | ||||||
Production and mineral taxes | 0.30 | 0.41 | 0.29 | 0.25 | 0.24 | ||||||
Transportation and selling | 0.35 | 0.34 | 0.35 | 0.33 | 0.36 | ||||||
Operating(2) | 0.71 | 0.77 | 0.72 | 0.67 | 0.66 | ||||||
Netback | 5.77 | 7.85 | 6.02 | 4.78 | 4.36 | ||||||
Discontinued Operations: |
|||||||||||
Crude Oil Ecuador ($/bbl) |
|||||||||||
Price | 39.36 | 37.82 | 47.76 | 36.37 | 35.80 | ||||||
Production and mineral taxes | 5.04 | 4.63 | 7.66 | 4.53 | 3.42 | ||||||
Transportation and selling | 2.25 | 1.86 | 2.45 | 2.48 | 2.21 | ||||||
Operating | 5.32 | 5.82 | 6.05 | 5.18 | 4.26 | ||||||
Netback | 26.75 | 25.51 | 31.60 | 24.18 | 25.91 | ||||||
Notes:
36
The following tables show the impact of realized financial hedging on EnCana's per-unit results.
|
2007 |
|||||||||
---|---|---|---|---|---|---|---|---|---|---|
|
Year |
Q4 |
Q3 |
Q2 |
Q1 |
|||||
Continuing Operations: | ||||||||||
Natural Gas ($/Mcf) |
1.33 |
1.49 |
1.65 |
1.24 |
0.92 |
|||||
Liquids ($/bbl) | (3.05 | ) | (8.76 | ) | (4.36 | ) | (1.34 | ) | 2.34 | |
Total ($/Mcfe) | 0.99 | 0.96 | 1.21 | 0.96 | 0.82 | |||||
|
2006 |
||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
|
Year |
Q4 |
Q3 |
Q2 |
Q1 |
||||||
Continuing Operations: | |||||||||||
Natural Gas ($/Mcf) |
0.47 |
0.91 |
0.82 |
0.66 |
(0.53 |
) |
|||||
Liquids ($/bbl) | (3.32 | ) | (3.30 | ) | (3.45 | ) | (3.43 | ) | (3.12 | ) | |
Total ($/Mcfe) | 0.25 | 0.60 | 0.53 | 0.40 | (0.53 | ) | |||||
Discontinued Operations: |
|||||||||||
Ecuador Oil ($/bbl) |
(0.12 |
) |
|
|
|
(0.12 |
) |
||||
|
2005 |
||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
|
Year |
Q4 |
Q3 |
Q2 |
Q1 |
||||||
Continuing Operations: | |||||||||||
Natural Gas ($/Mcf) |
(0.32 |
) |
(0.88 |
) |
(0.39 |
) |
(0.14 |
) |
0.18 |
||
Liquids ($/bbl) | (5.18 | ) | (5.00 | ) | (5.70 | ) | (4.88 | ) | (5.18 | ) | |
Total ($/Mcfe) | (0.44 | ) | (0.87 | ) | (0.52 | ) | (0.30 | ) | (0.06 | ) | |
Discontinued Operations: |
|||||||||||
Ecuador Oil ($/bbl) |
(4.92 |
) |
(3.57 |
) |
(7.81 |
) |
(4.90 |
) |
(3.48 |
) |
|
37
Drilling Activity
The following tables summarize EnCana's gross participation and net interest in wells drilled for the periods indicated.
Exploration Wells Drilled
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
|
|
|
Dry & Abandoned |
Total Working Interest |
|
Total |
|||||||||||||||
|
Gas |
Oil |
Royalty |
||||||||||||||||||||
|
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Gross |
Net |
||||||||||||
Continuing Operations: | |||||||||||||||||||||||
2007: |
|||||||||||||||||||||||
Canada | 120 | 96 | 7 | 6 | | | 127 | 102 | 180 | 307 | 102 | ||||||||||||
United States | 2 | 2 | | | | | 2 | 2 | | 2 | 2 | ||||||||||||
Other | | | | | 4 | 3 | 4 | 3 | | 4 | 3 | ||||||||||||
Total | 122 | 98 | 7 | 6 | 4 | 3 | 133 | 107 | 180 | 313 | 107 | ||||||||||||
2006: |
|||||||||||||||||||||||
Canada | 281 | 230 | 7 | 7 | 7 | 6 | 295 | 243 | 128 | 423 | 243 | ||||||||||||
United States | 12 | 7 | | | 2 | 1 | 14 | 8 | | 14 | 8 | ||||||||||||
Other | | | 2 | 1 | 4 | 1 | 6 | 2 | | 6 | 2 | ||||||||||||
Total | 293 | 237 | 9 | 8 | 13 | 8 | 315 | 253 | 128 | 443 | 253 | ||||||||||||
2005: |
|||||||||||||||||||||||
Canada | 605 | 540 | 8 | 8 | 7 | 7 | 620 | 555 | 99 | 719 | 555 | ||||||||||||
United States | 7 | 6 | | | 9 | 7 | 16 | 13 | 1 | 17 | 13 | ||||||||||||
Other | | | 3 | 1 | 3 | 2 | 6 | 3 | | 6 | 3 | ||||||||||||
Total | 612 | 546 | 11 | 9 | 19 | 16 | 642 | 571 | 100 | 742 | 571 | ||||||||||||
Discontinued Operations: |
|||||||||||||||||||||||
Ecuador 2005 |
|
|
2 |
1 |
3 |
2 |
5 |
3 |
|
5 |
3 |
||||||||||||
38
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
|
|
|
Dry & Abandoned |
Total Working Interest |
|
Total |
|||||||||||||||
|
Gas |
Oil |
Royalty |
||||||||||||||||||||
|
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Gross |
Net |
||||||||||||
Continuing Operations: | |||||||||||||||||||||||
2007: |
|||||||||||||||||||||||
Canada | 3,749 | 3,542 | 236 | 185 | 11 | 8 | 3,996 | 3,735 | 834 | 4,830 | 3,735 | ||||||||||||
United States | 809 | 641 | | | 1 | 1 | 810 | 642 | 102 | 912 | 642 | ||||||||||||
Total | 4,558 | 4,183 | 236 | 185 | 12 | 9 | 4,806 | 4,377 | 936 | 5,742 | 4,377 | ||||||||||||
2006: |
|||||||||||||||||||||||
Canada | 2,799 | 2,639 | 139 | 103 | 25 | 24 | 2,963 | 2,766 | 855 | 3,818 | 2,766 | ||||||||||||
United States | 779 | 625 | | | 7 | 6 | 786 | 631 | 22 | 808 | 631 | ||||||||||||
Total | 3,578 | 3,264 | 139 | 103 | 32 | 30 | 3,749 | 3,397 | 877 | 4,626 | 3,397 | ||||||||||||
2005: |
|||||||||||||||||||||||
Canada | 3,503 | 3,229 | 277 | 243 | 12 | 11 | 3,792 | 3,483 | 932 | 4,724 | 3,483 | ||||||||||||
United States | 699 | 604 | | | | | 699 | 604 | 9 | 708 | 604 | ||||||||||||
Total | 4,202 | 3,833 | 277 | 243 | 12 | 11 | 4,491 | 4,087 | 941 | 5,432 | 4,087 | ||||||||||||
Discontinued Operations: |
|||||||||||||||||||||||
Ecuador 2006 |
|
|
7 |
6 |
1 |
1 |
8 |
7 |
|
8 |
7 |
||||||||||||
Ecuador 2005 | | | 28 | 15 | 3 | 1 | 31 | 16 | | 31 | 16 | ||||||||||||
Notes:
39
Location of Wells
The following table summarizes EnCana's interest in producing wells and wells capable of producing as at December 31, 2007.
|
|
|
|
|
|
|
||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Gas |
Oil |
Total |
|||||||||
|
Gross |
Net |
Gross |
Net |
Gross |
Net |
||||||
Continuing Operations: | ||||||||||||
Alberta |
38,950 |
36,824 |
3,928 |
3,486 |
42,878 |
40,310 |
||||||
British Columbia | 2,166 | 1,962 | 19 | 13 | 2,185 | 1,975 | ||||||
Saskatchewan | 490 | 455 | 1,283 | 568 | 1,773 | 1,023 | ||||||
Manitoba | | | 1 | 1 | 1 | 1 | ||||||
Total Canada | 41,606 | 39,241 | 5,231 | 4,068 | 46,837 | 43,309 | ||||||
Colorado | 4,007 | 3,507 | | | 4,007 | 3,507 | ||||||
Texas | 1,777 | 1,119 | 8 | 4 | 1,785 | 1,123 | ||||||
Wyoming | 1,903 | 1,307 | | | 1,903 | 1,307 | ||||||
Utah | 43 | 39 | | | 43 | 39 | ||||||
Louisiana | 5 | 3 | | | 5 | 3 | ||||||
Kansas | 1 | 1 | | | 1 | 1 | ||||||
Montana | 1 | 1 | | | 1 | 1 | ||||||
Total United States | 7,737 | 5,977 | 8 | 4 | 7,745 | 5,981 | ||||||
Total | 49,343 | 45,218 | 5,239 | 4,072 | 54,582 | 49,290 | ||||||
Notes:
40
Interest in Material Properties
The following table summarizes EnCana's developed, undeveloped and total landholdings as at December 31, 2007.
|
|
Developed |
Undeveloped |
Total |
|||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
Gross |
Net |
Gross |
Net |
Gross |
Net |
||||||||
|
|
(thousands of acres) |
|||||||||||||
Continuing Operations: | |||||||||||||||
Canada |
|||||||||||||||
Alberta | Fee | 4,522 | 4,522 | 2,595 | 2,595 | 7,117 | 7,117 | ||||||||
Crown | 4,202 | 3,269 | 4,809 | 3,745 | 9,011 | 7,014 | |||||||||
Freehold | 253 | 155 | 187 | 154 | 440 | 309 | |||||||||
8,977 | 7,946 | 7,591 | 6,494 | 16,568 | 14,440 | ||||||||||
British Columbia | Crown | 1,118 | 958 | 4,144 | 3,398 | 5,262 | 4,356 | ||||||||
Freehold | | | 7 | | 7 | | |||||||||
1,118 | 958 | 4,151 | 3,398 | 5,269 | 4,356 | ||||||||||
Saskatchewan | Fee | 61 | 61 | 449 | 449 | 510 | 510 | ||||||||
Crown | 134 | 113 | 477 | 412 | 611 | 525 | |||||||||
Freehold | 15 | 11 | 32 | 30 | 47 | 41 | |||||||||
210 | 185 | 958 | 891 | 1,168 | 1,076 | ||||||||||
Manitoba | Fee | 3 | 3 | 261 | 261 | 264 | 264 | ||||||||
Newfoundland and Labrador | Crown | | | 35 | 2 | 35 | 2 | ||||||||
Nova Scotia | Crown | | | 498 | 175 | 498 | 175 | ||||||||
Northwest Territories | Crown | | | 45 | 11 | 45 | 11 | ||||||||
Total Canada | 10,308 | 9,092 | 13,539 | 11,232 | 23,847 | 20,324 | |||||||||
41
|
|
|
|
|
|
|
|
||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
Developed |
Undeveloped |
Total |
|||||||||||
|
|
Gross |
Net |
Gross |
Net |
Gross |
Net |
||||||||
|
|
(thousands of acres) |
|||||||||||||
United States | |||||||||||||||
Colorado | Federal/State Lands | 199 | 185 | 720 | 664 | 919 | 849 | ||||||||
Freehold | 111 | 105 | 173 | 159 | 284 | 264 | |||||||||
Fee | 3 | 3 | 30 | 30 | 33 | 33 | |||||||||
313 | 293 | 923 | 853 | 1,236 | 1,146 | ||||||||||
Washington | Federal/State Lands | | | 655 | 298 | 655 | 298 | ||||||||
Freehold | | | 223 | 98 | 223 | 98 | |||||||||
| | 878 | 396 | 878 | 396 | ||||||||||
Texas | Federal/State Lands | 7 | 4 | 472 | 452 | 479 | 456 | ||||||||
Freehold | 217 | 156 | 997 | 772 | 1,214 | 928 | |||||||||
Fee | | | 4 | 2 | 4 | 2 | |||||||||
224 | 160 | 1,473 | 1,226 | 1,697 | 1,386 | ||||||||||
Wyoming | Federal/State Lands | 143 | 87 | 636 | 452 | 779 | 539 | ||||||||
Freehold | 26 | 19 | 47 | 23 | 73 | 42 | |||||||||
169 | 106 | 683 | 475 | 852 | 581 | ||||||||||
Other | Federal/State Lands | 8 | 7 | 331 | 192 | 339 | 199 | ||||||||
Freehold | 3 | 3 | 981 | 978 | 984 | 981 | |||||||||
11 | 10 | 1,312 | 1,170 | 1,323 | 1,180 | ||||||||||
Total United States | 717 | 569 | 5,269 | 4,120 | 5,986 | 4,689 | |||||||||
Qatar | | | 2,161 | 1,080 | 2,161 | 1,080 | |||||||||
Greenland | | | 1,701 | 1,488 | 1,701 | 1,488 | |||||||||
Brazil(7) | | | 1,662 | 522 | 1,662 | 522 | |||||||||
France | | | 859 | 859 | 859 | 859 | |||||||||
Azerbaijan | | | 346 | 17 | 346 | 17 | |||||||||
Australia | | | 104 | 40 | 104 | 40 | |||||||||
Total International | | | 6,833 | 4,006 | 6,833 | 4,006 | |||||||||
Total | 11,025 | 9,661 | 25,641 | 19,358 | 36,666 | 29,019 | |||||||||
Notes:
42
Acquisitions, Divestitures and Capital Expenditures
EnCana's 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 EnCana's net capital investment for 2007 and 2006.
|
2007 |
2006 |
|||||
---|---|---|---|---|---|---|---|
|
($ millions) |
||||||
Capital | |||||||
Canada | 3,330 | 3,352 | |||||
United States | 1,919 | 2,061 | |||||
Other | 106 | 106 | |||||
Integrated Oil | 580 | 632 | |||||
Market Optimization | 6 | 44 | |||||
Corporate(1) | 94 | 74 | |||||
Capital from Continuing Operations | 6,035 | 6,269 | |||||
Acquisitions |
|||||||
Property | |||||||
Canada | 75 | 11 | |||||
United States(2) | 2,613 | 284 | |||||
Other | | 15 | |||||
Integrated Oil | 14 | 21 | |||||
Divestitures |
|||||||
Property | |||||||
Canada | (54 | ) | (59 | ) | |||
United States | (10 | ) | (19 | ) | |||
Other(3) | (149 | ) | | ||||
Corporate(4) | (57 | ) | | ||||
Corporate | |||||||
Market Optimization | | (244 | ) | ||||
Other(5) | (211 | ) | (367 | ) | |||
Net Acquisition and Divestiture Activity from Continuing Operations | 2,221 | (358 | ) | ||||
Discontinued Operations | |||||||
Ecuador | | (1,116 | ) | ||||
Midstream | | (1,531 | ) | ||||
Net Capital Investment | 8,256 | 3,264 | |||||
Notes:
43
Delivery Commitments
As part of ordinary business operations, EnCana has a number of delivery commitments to provide crude oil and natural gas under existing contracts and agreements. The Corporation has sufficient reserves of natural gas and crude oil to meet these commitments. More detailed information relating to such commitments can be found in Note 20 to EnCana's audited consolidated financial statements for the year ended December 31, 2007.
GENERAL
Competitive Conditions
All aspects of the oil and gas industry are highly competitive and EnCana actively competes with oil and natural gas and other companies, particularly in the following areas: (i) exploration for and development of new sources of oil and natural gas reserves; (ii) reserves and property acquisitions; (iii) transportation and marketing of oil, natural gas, NGLs, diluents and electricity; (iv) supply of refinery feedstock and the market for refined products; (v) access to services and equipment to carry out exploration, development or operating activities; and (vi) 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 oil and natural gas, both of which could have a negative impact on EnCana's financial results.
Environmental Protection
EnCana's worldwide operations are subject to government 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 EnCana's Board of Directors reviews and recommends to the Board of Directors for approval environmental policy 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 expects to incur abandonment and site reclamation costs as existing oil and gas properties are abandoned and reclaimed. In 2007, expenditures beyond normal compliance with environmental regulations were not material. EnCana does not anticipate making material expenditures beyond normal compliance with environmental regulations in 2008. Based on EnCana's 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 $7.4 billion.
Social and Environmental Policies
In 2003, EnCana developed a Corporate Responsibility Policy (the "Policy") that translates its constitutional values and shared principles into policy commitments. 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 Corporation's products including decommissioning of facilities, 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) environment, health and safety, (vii) stakeholder engagement, and (viii) socio-economic and community development.
Accountability for implementation of the Policy is at the operational level within EnCana's business units. Business units have established processes to evaluate risks, and programs are implemented to minimize that risk. Results related to the commitments outlined in the Corporate Constitution are tied to the individual
44
performance assessment process. Coordination and oversight of the Policy resides with the Environment, Health, Safety and Security Group within Corporate Relations.
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 environment, health and safety; (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 EnCana's 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: (i) while governments have the primary responsibility to promote and protect human rights, EnCana shares this goal and will support and respect human rights within its sphere of influence; (ii) 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; and (iii) in providing for the protection of company personnel and assets by public or private security forces, EnCana will promote respect for, and protection of, human rights.
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; (ii) an EH&S management system; (iii) a security program to regularly assess security threats to business operations and manage the associated risks; (iv) a formalized approach to stakeholder relations with a standardized Stakeholder Engagement Guide; (v) corporate responsibility performance metrics to track the Corporation's progress; (vi) contribution of a minimum of one percent of EnCana's pre-tax domestic profits to charitable and non-profit organizations in the communities in which EnCana operates; (vii) an Investigations Practice and an Investigations Committee to review and resolve potential violations of EnCana policies or practices and other regulations; (viii) an Integrity Hotline that provides an additional avenue for EnCana's 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; (ix) an internal corporate EH&S audit program that evaluates EnCana's compliance with the expectations and requirements of the EH&S management system; and (x) related policies and practices such as an Alcohol and Drug Policy and Business Conduct and Ethics Practice and guidelines for correct behaviors with respect to the acceptance of gifts and conflicts of interest. In addition, EnCana's 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.
Employees
At December 31, 2007, EnCana employed 5,285 full time equivalent ("FTE") employees as set forth in the following table.
|
FTE Employees |
|
---|---|---|
Canada, United States and Other | 4,048 | |
Integrated Oil | 665 | |
Market Optimization | 77 | |
Corporate | 495 | |
Total | 5,285 | |
The Corporation also engages a number of contractors and service providers.
45
Foreign Operations
As at December 31, 2007, all of EnCana's reserves and production were located in North America, which limits EnCana's exposure to risks and uncertainties in countries considered politically and economically unstable. EnCana's 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.
Reorganizations
As discussed under "Name and Incorporation" in this annual information form, EnCana was formed through the Merger of AEC and PanCanadian on April 5, 2002. AEC remained in existence as an indirect wholly owned subsidiary of EnCana, and on January 1, 2003, AEC was amalgamated with EnCana.
As a general matter, EnCana reorganizes its subsidiaries as required to maintain proper alignment of its businesses and facilitate acquisitions and divestitures.
The following information is provided for each director and executive officer of EnCana as at the date of this annual information form.
Directors
Name and Municipality of Residence |
Director Since(13) |
Principal Occupation |
||
---|---|---|---|---|
RALPH S. CUNNINGHAM(2,3) Houston, Texas, United States |
2003 |
President & Chief Executive Officer EPE Holdings LLC (Midstream energy services) |
||
PATRICK D. DANIEL(1,5) Calgary, Alberta, Canada |
2001 |
President & Chief Executive Officer Enbridge Inc. (Energy delivery) |
||
IAN W. DELANEY(3,4) Toronto, Ontario, Canada |
1999 |
Executive Chairman Sherritt International Corporation (Nickel/cobalt mining, oil and natural gas production, electricity generation and coal mining) |
||
RANDALL K. ERESMAN Calgary, Alberta, Canada |
2006 |
President & Chief Executive Officer EnCana Corporation |
||
MICHAEL A. GRANDIN(3,4,6,8) Calgary, Alberta, Canada |
1998 |
Chairman & Chief Executive Officer Fording Canadian Coal Trust (Metallurgical coal) |
||
BARRY W. HARRISON(1,4,9) Calgary, Alberta, Canada |
1996 |
Corporate Director and independent businessman |
||
DALE A. LUCAS(1,5) Calgary, Alberta, Canada |
1997 |
Corporate Director |
||
KEN F. MCCREADY(2,5,10) Calgary, Alberta, Canada |
1992 |
President K.F. McCready & Associates Ltd. (Private sustainable energy development consulting company) |
46
VALERIE A. A. NIELSEN(2,6) Calgary, Alberta, Canada |
1990 |
Corporate Director |
||
DAVID P. O'BRIEN(4,7,11) Calgary, Alberta, Canada |
1990 |
Chairman EnCana Corporation Chairman Royal Bank of Canada |
||
JANE L. PEVERETT(1,5) West Vancouver, British Columbia, Canada |
2003 |
President & Chief Executive Officer British Columbia Transmission Corporation (Electrical transmission) |
||
ALLAN P. SAWIN(1,3) Edmonton, Alberta, Canada |
2007 |
President Bear Investments Inc. (Private investment company) |
||
DENNIS A. SHARP(2,4) Calgary, Alberta, Canada & Montreal, Quebec, Canada |
1998 |
Chairman UTS Energy Corporation (Oilsands company) |
||
JAMES M. STANFORD, O.C.(1,3,6) Calgary, Alberta, Canada |
2001 |
President Stanford Resource Management Inc. (Private investment management) |
||
WAYNE G. THOMSON(2,6) Calgary, Alberta, Canada |
2007 |
President Virgin Resources Limited (Private international oil & gas exploration company) |
||
CLAYTON H. WOITAS(12) Calgary, Alberta, Canada |
2008 |
Chairman & Chief Executive Officer Range Royalty Management Ltd. (Private oil & gas company) |
||
Notes:
47
EnCana does not have an Executive Committee of its Board of Directors.
At the date of this annual information form, there are 16 directors of the Corporation. With the exception of Mr. Woitas, who was appointed to the Board effective January 1, 2008, all of the current directors were appointed at the last annual meeting of shareholders held on April 25, 2007. At the next annual meeting, shareholders will be asked to elect as directors the 14 individuals listed in the above table, with the exception of Mr. McCready who is not standing for re-election and Mr. Sharp who is retiring from the Board. 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 nominees shall be eligible for re-election.
Executive Officers
Name and Municipality of Residence |
Corporate Office (Divisional Title) |
|
---|---|---|
DAVID P. O'BRIEN Calgary, Alberta, Canada |
Chairman | |
RANDALL K. ERESMAN Calgary, Alberta, Canada |
President & Chief Executive Officer | |
JOHN K. BRANNAN Calgary, Alberta, Canada |
Executive Vice-President (President, Integrated Oil Division) |
|
SHERRI A. BRILLON Calgary, Alberta, Canada |
Executive Vice-President, Strategic Planning & Portfolio Management |
|
BRIAN C. FERGUSON Calgary, Alberta, Canada |
Executive Vice-President & Chief Financial Officer | |
MICHAEL M. GRAHAM Calgary, Alberta, Canada |
Executive Vice-President (President, Canadian Foothills Division) |
|
SHEILA M. MCINTOSH Calgary, Alberta, Canada |
Executive Vice-President, Corporate Communications | |
R. WILLIAM OLIVER Calgary, Alberta, Canada |
Executive Vice-President, Business Development (President, Midstream & Marketing Division) |
|
GERARD J. PROTTI Calgary, Alberta, Canada |
Executive Vice-President, Corporate Relations (President, Offshore & International Division) |
|
IVOR M. RUSTE(1) Calgary, Alberta, Canada |
Executive Vice-President & Chief Risk Officer | |
DONALD T. SWYSTUN Calgary, Alberta, Canada |
Executive Vice-President (President, Canadian Plains Division) |
|
HAYWARD J. WALLS Calgary, Alberta, Canada |
Executive Vice-President, Corporate Services | |
JEFF E. WOJAHN Denver, Colorado, USA |
Executive Vice-President (President, USA Division) |
|
Note:
48
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:
Mr. Cunningham has been, since August 1, 2007, a director and President and Chief Executive Officer of EPE Holdings LLC, the sole general partner of Enterprise GP Holdings L.P. (a publicly traded midstream energy holding company). From February 13, 2006 until July 31, 2007, he served as Group Executive Vice President and Chief Operating Officer and, from June 30, 2007 to July 31, 2007, also served as Interim President and Chief Executive Officer of Enterprise Products GP, LLC, the sole general partner of Enterprise Products Partners L.P. (a publicly traded midstream energy company). He was a director and Chairman of the Board of Texas Eastern Products Pipeline Company, LLC from March 2005 until November 2005. Prior to March 2005, he was a Corporate Director.
Mr. Grandin served as Dean of the Haskayne School of Business, University of Calgary from April 2004 to January 2006.
Ms. Peverett was Vice President, Corporate Services and Chief Financial Officer of British Columbia Transmission Corporation (BCTC) from June 2003 to April 2005 when she was appointed President and Chief Executive Officer of BCTC. 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. Ruste joined EnCana on May 1, 2006 as Vice-President, Finance of the Corporate Finance Group. He was appointed Vice-President, Finance for the Integrated Oil Division effective January 1, 2007 and was appointed Executive Vice-President & Chief Risk Officer effective January 1, 2008. From February 2003 to April 2006, he was a partner and the Office Managing Partner for the Edmonton, Alberta office of KPMG LLP, as well as the Alberta Region Managing Partner for KPMG LLP. During this period, he was also a member of the Board of Directors of KPMG Canada and, from December 2003 to March 2006, he was Vice Chair of the Board of Directors for KPMG Canada.
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. Sharp was Chairman and Chief Executive Officer of UTS Energy Corporation from July 1998 to October 2004.
Since February 2005, Mr. Thomson has been President and a director of Virgin Resources Limited, a private junior international oil and gas exploration company with activities focused in Yemen. He was President and a director of Airborne Pollution Control Inc. from 2001 to 2003.
Mr. Woitas was appointed to the EnCana Board effective January 1, 2008. Currently, Mr. Woitas is Chairman and Chief Executive Officer of Range Royalty Management Ltd., a private company which is focused on acquiring royalty interests in Western Canadian oil and natural gas production. He was founder, Chairman, and President and Chief Executive Officer of privately held Profico Energy Management Ltd. (January 2000 to June 2006), a company focused on natural gas exploration and production in western Canada.
All of the directors and executive officers of EnCana listed above beneficially owned, as of February 13, 2008, directly or indirectly, or exercised control or direction over an aggregate of 954,259 Common Shares representing 0.13 percent of the issued and outstanding voting shares of EnCana, and directors and executive officers held options to acquire an aggregate of 4,672,518 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.
49
The full text of the Audit Committee mandate is included in Appendix C of this annual information form.
Composition of the Audit Committee
The Audit Committee consists of six members, all of whom are independent and financially literate in accordance with the definitions in Multilateral Instrument 52-110 Audit Committees. The relevant education and experience of each Audit Committee member is outlined below.
Patrick D. Daniel
Mr. Daniel holds a Bachelor of Science (University of Alberta) and a Master of Science (University of British Columbia), both in chemical engineering. He also completed the Harvard Advanced Management Program. He is President and Chief Executive Officer and a director of Enbridge Inc. (energy delivery company), as well as a director of a number of Enbridge subsidiaries. He is also a director and past member of the Audit Committee of Enerflex Systems Ltd. (compression systems manufacturer) and a director and Chair of the Finance Committee of Synenco Energy Inc. (oilsands mining).
Barry W. Harrison (Audit Committee Chair)
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. (oil and gas). 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.
Dale A. Lucas
Mr. Lucas holds a Bachelor of Science in Chemical Engineering and a Bachelor of Arts in Economics (University of Alberta). Mr. Lucas is Chairman and a director of Petaquilla Copper Ltd. (a public mining company) and is President of D.A. Lucas Enterprises Inc., a private company owned by Mr. Lucas and through which he consulted internationally. During his 44-year career in the energy sector, he served the maximum 6-year term as a director of the New York Mercantile Exchange (NYMEX) and was past Chairman of the Alberta Petroleum Marketing Commission. He has held senior executive positions with J. Makowski Canada Ltd. (Calgary), J. Makowski Associates Inc. (Boston), BP Canada and BP Pipelines (San Francisco).
Jane L. Peverett
Ms. Peverett holds a Bachelor of Commerce (McMaster University) and a Master of Business Administration (Queen's 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 Vice President, Corporate Services and Chief Financial Officer of British Columbia Transmission Corporation (electrical transmission) from June 2003 to April 2005, when she was appointed President and Chief Executive Officer. 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
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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.
James M. Stanford, O.C.
Mr. Stanford holds a Doctor of Laws (Hon.) and a Bachelor of Science in Petroleum Engineering (University of Alberta), and a Doctor of Laws (Hon.) and a Bachelor of Science in Mining (Concordia University). He is President of Stanford Resource Management Inc. (investment management). He is a director and Chairman of both OPTI Canada Inc. (oilsands development and upgrading company) and NOVA Chemicals Corporation (commodity chemical company). He was Chairman of the Audit Committee of Inco Limited from April 2002 until August 2005 when he retired from the Board. Mr. Stanford was a director, President and Chief Executive Officer of Petro-Canada (oil and gas company) from 1993 until his retirement in 2000. He also served as the President, Chief Operating Officer and a director of Petro-Canada from 1990 to 1993.
The above list does not include David P. O'Brien who is an ex officio member of the Audit Committee.
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 Chairman of the Audit Committee (or if the Chairman is unavailable, any other member of the Committee) to pre-approve the provision of permitted services by PricewaterhouseCoopers LLP which are not otherwise pre-approved by the Audit Committee, including the fees and terms of the proposed services ("Delegated Authority"). Any required determination about the Chairman's 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$50,000, in the case of pre-approvals granted by any other member of the Audit Committee.
All proposed services or the fees payable in connection with such services that have not already been pre-approved must be pre-approved by either the Audit Committee or pursuant to Delegated Authority. Prohibited services may not be pre-approved by the Audit Committee or pursuant to Delegated Authority.
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External Auditor Service Fees
The following table provides information about the fees billed to the Corporation for professional services rendered by PricewaterhouseCoopers LLP during fiscal 2007 and 2006.
($ thousands) |
2007 |
2006 |
||
---|---|---|---|---|
Audit Fees(1) | 4,038 | 3,762 | ||
Audit-Related Fees(2) | 153 | 401 | ||
Tax Fees(3) | 847 | 1,215 | ||
All Other Fees(4) | 35 | 34 | ||
Total | 5,073 | 5,412 | ||
Notes:
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 2006 or 2007.
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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, 2007, there were approximately 753 million Common Shares outstanding and no Preferred Shares outstanding.
At the annual and special meeting of EnCana's shareholders on April 27, 2005, the Corporation's shareholders approved the subdivision of EnCana's outstanding common shares on a two-for-one basis. Each shareholder received one additional common share for each common share held on the record date for the stock split of May 12, 2005. EnCana's common shares commenced trading on a subdivided basis on May 10, 2005.
Common Shares
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 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 10 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 takeover bid, whereby a person acquires or attempts to acquire 20 percent or more of EnCana's 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 acquiror, 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 until it expires on July 30, 2011.
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 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 Corporation's affairs.
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The following table outlines the ratings of the Corporation's debt as of December 31, 2007.
|
Standard & Poor's Ratings Services ("S&P") |
Moody's Investors Service ("Moody's") |
DBRS Limited ("DBRS") |
|||
---|---|---|---|---|---|---|
Senior Unsecured/Long-Term Rating | A- | Baa2 | A (low) | |||
Commercial Paper/Short-Term Rating | A-1 (low) | P-2 | R-1 (low) | |||
Outlook | Stable | Positive | Stable | |||
S&P's 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- by S&P is within the third highest of ten categories and indicates that the obligor has strong capacity to meet its financial commitments but is somewhat more susceptible to the adverse effects of changes in circumstances and economic conditions than obligors in higher rated categories. The addition of a plus (+) or minus (-) designation after a rating indicates the relative standing within a particular rating category. S&P's Canadian commercial paper ratings scale ranges from A-1 (high) to D, representing the range from highest to lowest quality. A-1 (low) is the third highest of eight categories and indicates that the obligor has satisfactory capacity to meet its financial commitments.
Moody's 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 Moody's 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 issue ranks in the higher end of its generic rating category, the modifier 2 indicates a mid-range ranking and the modifier 3 indicates that the issue ranks in the lower end of its generic rating category. The addition a ratings outlook of "Positive (POS)", "Negative (NEG)" or "Stable (STA)" is an opinion regarding the likely direction of a rating over the medium term. Moody's short-term ratings are on a scale ranging from P-1 (highest quality) to NP (lowest quality). 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 still substantial, but the degree of strength is less than that of AA rated entities. While a respectable rating, 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 ratings are on a scale ranging from R-1 (high) to D, representing the range from highest to lowest quality. 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.
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 inasmuch as such ratings do not comment as to 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.
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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 2007.
|
Toronto Stock Exchange |
New York Stock Exchange |
||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Share Price Trading Range |
|
Share Price Trading Range |
|
||||||||||||
|
Share Volume |
Share Volume |
||||||||||||||
|
High |
Low |
Close |
High |
Low |
Close |
||||||||||
|
|
(C$ per share) |
|
(millions) |
|
($ per share) |
|
(millions) |
||||||||
2007 | ||||||||||||||||
January | 57.89 | 51.55 | 56.45 | 68.2 | 49.01 | 42.38 | 48.03 | 64.8 | ||||||||
February | 58.25 | 54.77 | 56.85 | 44.6 | 49.86 | 47.19 | 48.57 | 44.2 | ||||||||
March | 59.65 | 53.67 | 58.40 | 55.3 | 51.49 | 45.87 | 50.63 | 54.2 | ||||||||
April | 61.84 | 58.08 | 58.10 | 42.4 | 54.99 | 50.58 | 52.45 | 45.0 | ||||||||
May | 68.65 | 57.61 | 65.51 | 52.7 | 63.21 | 51.79 | 61.40 | 65.6 | ||||||||
June | 71.21 | 64.17 | 65.52 | 65.7 | 66.87 | 59.88 | 61.45 | 56.1 | ||||||||
July | 67.99 | 62.20 | 65.30 | 51.7 | 65.18 | 59.22 | 60.98 | 57.5 | ||||||||
August | 66.43 | 59.33 | 61.89 | 47.8 | 63.13 | 55.13 | 58.50 | 64.7 | ||||||||
September | 65.10 | 60.66 | 61.50 | 40.7 | 64.16 | 58.33 | 61.85 | 39.0 | ||||||||
October | 66.10 | 60.89 | 66.10 | 47.8 | 69.89 | 60.86 | 69.70 | 56.2 | ||||||||
November | 69.47 | 63.67 | 64.90 | 51.0 | 75.85 | 63.82 | 65.25 | 65.4 | ||||||||
December | 69.59 | 64.77 | 67.50 | 33.7 | 69.59 | 64.03 | 67.96 | 36.8 | ||||||||
In November 2007, EnCana received approval from the TSX to renew its normal course issuer bid. Under the renewed program, EnCana is entitled to purchase up to 10 percent of its outstanding common shares as at October 31, 2007. Purchases may be made through the facilities of the TSX and the NYSE, in accordance with the policies and rules of each exchange.
During January 2008, EnCana purchased approximately 3.0 million shares under the program for approximately $191 million.
In 2007, EnCana purchased approximately 38.9 million shares under the program for an average price of $52.05 for approximately $2.0 billion.
The declaration of dividends is at the discretion of the Board of Directors and is approved quarterly. At the beginning of 2005, cash dividends were paid to common shareholders at a rate of $0.20 per share annually ($0.05 per share quarterly). In the second quarter of 2005, EnCana increased its dividend by 50 percent to $0.30 per share annually ($0.075 per share quarterly). In the second quarter of 2006, EnCana increased its dividend by 33 percent to $0.40 per share ($0.10 per share quarterly). In the first quarter of 2007, EnCana increased its dividend by 100 percent to $0.80 per share annually ($0.20 per share quarterly). EnCana's Board of Directors has declared a quarterly dividend of $0.40 per share payable on March 31, 2008 to common shareholders of record on March 14, 2008, a 100 percent increase over the previous dividend. All of the figures in this section have been adjusted to reflect the May 2005 share split.
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 EnCana's 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.
For information on legal proceedings related to EnCana's discontinued merchant energy trading operations, refer to "Risk Factors" in this annual information form.
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If any event arising from the risk factors set forth below occurs, EnCana's business, prospects, financial condition, results of operation or cash flows could be materially adversely affected.
A substantial or extended decline in crude oil and natural gas prices could have a material adverse effect on EnCana.
EnCana's financial performance and condition are substantially dependent on the prevailing prices of crude oil and natural gas. Fluctuations in crude oil or natural gas prices could have an adverse effect on the Corporation's operations and financial condition and the value and amount of its proved reserves. Prices for crude oil and natural gas fluctuate in response to changes in the supply of and demand for crude oil and natural gas, market uncertainty and a variety of additional factors beyond the Corporation's control. 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. 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 liquefied natural gas). Any substantial or extended decline in the prices of crude oil and 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 Corporation's revenues, profitability and cash flows.
The market prices for heavy oil are lower than the established market indices for light and medium grades of oil, due principally to diluent prices and the higher transportation and refining costs associated with heavy oil. Also, the market for heavy oil is more limited than for light and medium grades, making it more susceptible to supply and demand fundamentals. Future price differentials are uncertain and any increase in the heavy oil differentials could have a material adverse effect on EnCana's business.
EnCana conducts an annual assessment of the carrying value of its assets in accordance with Canadian GAAP. If crude oil and natural gas prices decline, the carrying value of EnCana's assets could be subject to financial downward revisions, and the Corporation's earnings could be adversely affected.
If EnCana fails to acquire or find additional crude oil and natural gas reserves, the Corporation's reserves and production will decline materially from their current levels.
EnCana's future crude oil and natural gas 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 Corporation's 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, EnCana's ability to make the necessary capital investments to maintain and expand its crude oil and natural gas reserves will be impaired. In addition, there can be no guarantee that EnCana will be able to find and develop or acquire additional reserves to replace production at acceptable costs.
EnCana's crude oil and natural gas reserves data and future net revenue estimates are uncertain.
There are numerous uncertainties inherent in estimating quantities of crude oil and natural gas reserves, including many factors beyond the Corporation's control. The reserves data in this annual information form represent estimates only. In general, estimates of economically recoverable crude oil and natural gas 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
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are only attempts to define the degree of uncertainty involved. For those reasons, estimates of the economically recoverable crude oil and natural gas 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. EnCana's 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.
EnCana's hedging activities could result in realized and unrealized losses.
The nature of the Corporation's 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 crude oil and natural gas prices and changes in interest rates. Under Canadian GAAP, derivative instruments that do not qualify as hedges, or are not designated as hedges, are marked-to-market with changes in fair value recognized in current period net earnings. The utilization of derivative financial instruments may therefore introduce significant volatility into the Corporation's reported net earnings.
The terms of the Corporation's 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:
EnCana's ability to complete projects is dependent on factors outside of its control.
The Corporation undertakes a variety of projects including exploration and development projects and the construction or expansion of facilities, refineries and pipelines. Project delays may delay expected revenues and project cost overruns could make projects uneconomic. The Corporation's ability to complete projects depends upon numerous factors beyond the Corporation's control. These factors include:
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All of EnCana's 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 Corporation's existing and planned projects.
The Corporation's 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 crude oil, natural gas and refining 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 generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and waste 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 oil and gas operations. Environmental legislation also requires that wells, facility sites and other properties associated with EnCana's 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 EnCana's 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 ("GHG") 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.
EnCana's operations are subject to the risk of business interruption and casualty losses.
The Corporation's business is subject to all of the operating risks normally associated with the exploration for, development of and production of crude oil and natural gas and the operation of midstream and refining facilities. These risks include blowouts, explosions, fire, gaseous leaks, migration of harmful substances and crude oil spills, any of which could cause personal injury, result in damage to, or destruction of, crude oil and natural gas wells or formations or production facilities and other property, equipment and the environment, as well as interrupt operations. In addition, all of EnCana's operations will be subject to all of the risks normally incident to the transportation, processing, storing, refining and marketing of crude oil, natural gas and other related products, drilling and completion of crude oil and natural gas wells, and the operation and development of crude oil and natural gas 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 crude oil, natural gas or well fluids, adverse weather conditions, pollution and other environmental risks.
The occurrence of a significant event against which EnCana is not fully insured could have a material adverse effect on the Corporation's financial position.
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Fluctuations in exchange rates could affect expenses or result in realized and unrealized losses.
Worldwide prices for crude oil, natural gas and refined products are set in U.S. dollars. However, many of the Corporation's 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 Corporation's expenses and have an adverse effect on the Corporation's 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 interests. EnCana will have limited ability to exercise influence over operations of these assets or their associated costs. EnCana's 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 Corporation's financial performance. The success and timing of EnCana's activities on assets operated by others therefore will depend upon a number of factors that are outside of the Corporation's control, including:
All of the Corporation's downstream operations are operated by ConocoPhillips. The success of the Corporation's downstream operations is dependant on the ability of ConocoPhillips to successfully operate this business.
The volatility of downstream margins will have an impact on EnCana's results.
EnCana's downstream operations are sensitive to margins for refined products. Margin volatility is impacted by numerous conditions including: market competitiveness, the cost of crude oil, fluctuations in the supply and demand for refined products and weather. It is expected that all of these and other factors will continue to impact downstream margins for the foreseeable future. As a result, it can be reasonably expected that downstream results will fluctuate over time and from period to period.
The Corporation's foreign operations will expose it to risks from abroad which could negatively affect its results of operations.
Some of EnCana's operations and related assets are located 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 is exposed to risks associated with the use of current technology, and the pursuit of new technology, which could negatively affect its results of operations.
Current SAGD technologies for in-situ recovery of heavy oil and bitumen are energy intensive, requiring significant consumption of natural gas and other fuels in the production of steam that is used in the recovery
59
process. The amount of steam required in the production process can also vary and affect costs. The performance of the reservoir can also affect the timing and levels of production using this technology. A large increase in recovery costs could cause certain projects that rely on SAGD technology to become uneconomical, which could have a negative effect on EnCana's results of operations.
There are risks associated with growth and other capital projects that rely largely or partly on new technologies and the incorporation of such technologies into new or existing operations. The success of projects incorporating new technologies cannot be assured.
EnCana may be adversely affected by legal proceedings related to its discontinued merchant energy trading operations.
During the period between 2003 and 2005, EnCana and its indirect wholly owned U.S. marketing subsidiary, WD Energy Services Inc. ("WD"), along with other energy companies, were named as defendants in several lawsuits, some of which were class action lawsuits, relating to sales of natural gas from 1999 to 2002. The lawsuits allege that the defendants engaged in a conspiracy with unnamed competitors in the natural gas markets in California in violation of U.S. and California anti-trust and unfair competition laws.
Without admitting any liability in the lawsuits, WD agreed to settle all of the class action lawsuits in both state and federal court, for payments of $20.5 million and $2.4 million, respectively. Also, as previously disclosed, without admitting any liability whatsoever, WD concluded settlements with the U.S. Commodity Futures Trading Commission ("CFTC") for $20 million and of a previously disclosed consolidated class action lawsuit in the United States District Court in New York for $8.2 million.
The remaining lawsuits were commenced by individual plaintiffs, one of which is E. & J. Gallo Winery ("Gallo"). The Gallo lawsuit claims damages in excess of $30 million. The other remaining lawsuits do not specify the precise amount of damages claimed. California law allows for the possibility that the amount of damages assessed could be tripled.
The Corporation and WD intend to vigorously defend against the outstanding claims; however, the Corporation cannot predict the outcome of these proceedings or any future proceedings against EnCana, whether these proceedings would lead to monetary damages which could have a material adverse effect on the Corporation's financial position, or whether there will be other proceedings arising out of these allegations.
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TRANSFER AGENTS AND REGISTRARS
In Canada: CIBC Mellon Trust Company P.O Box 7010 Adelaide Street Postal Station Toronto, ON M5C 2W9 Tel: 1-800-387-0825 Website: www.cibcmellon.com/investorinquiry |
In the United States: BNY Mellon Shareowner Services 480 Washington Blvd Jersey City, NJ 07310 Tel: 1-800-387-0825 Website: www.cibcmellon.com/investorinquiry |
PricewaterhouseCoopers LLP, Chartered Accountants, are the Corporation's auditors and such firm has prepared an opinion with respect to the Corporation's consolidated financial statements as at and for the fiscal year ended December 31, 2007. PricewaterhouseCoopers LLP is independent in accordance with the Rules of Professional Conduct as outlined by the Institute of Chartered Accountants of Alberta. Information relating to reserves in this annual information form dated February 22, 2008 was calculated by GLJ Petroleum Consultants Ltd., McDaniel & Associates Consultants Ltd., Netherland, Sewell & Associates, Inc. and DeGolyer and MacNaughton as independent qualified reserves evaluators.
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 one percent of any class of EnCana's 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 EnCana's securities, and options to purchase securities, is contained in the Information Circular for EnCana's most recent annual meeting of shareholders that involved the election of directors. Additional financial information is contained in EnCana's audited consolidated financial statements and Management's Discussion and Analysis for the year ended December 31, 2007.
61
APPENDIX A
Report on Reserves Data by Independent Qualified Reserves Evaluators
To the Board of Directors of EnCana Corporation (the "Corporation"):
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").
|
|
Estimated Proved Reserves Quantities After Royalty |
|
|||||
---|---|---|---|---|---|---|---|---|
|
|
Related Estimates of Future Net Cash Flow BTax, 10% discount rate |
||||||
|
Reserves Location |
|||||||
Evaluator and Preparation Date of Report |
Gas |
Liquids |
||||||
|
|
(Bcf) |
(MMbbl) |
(US$MM) |
||||
McDaniel & Associates Consultants Ltd. | Canada | 4,156 | 772 | 19,687 | ||||
January 31, 2008 | ||||||||
GLJ Petroleum Consultants Ltd. | Canada | 3,136 | 97 | 9,501 | ||||
January 30, 2008 | ||||||||
Netherland, Sewell & Associates, Inc. | United States | 4,450 | 54 | 10,425 | ||||
January 29, 2008 | ||||||||
DeGolyer and MacNaughton | United States | 1,558 | 4 | 2,875 | ||||
January 18, 2008 | ||||||||
Totals | 13,300 | 927 | 42,488 | |||||
62
Executed as to our report referred to above:
(signed) McDaniel & Associates Consultants Ltd. Calgary, Alberta, Canada |
(signed) GLJ Petroleum Consultants Ltd. Calgary, Alberta, Canada |
|
(signed) Netherland, Sewell & Associates, Inc. Dallas, Texas, U.S.A. |
(signed) DeGolyer and MacNaughton Dallas, Texas, U.S.A. |
February 12, 2008
63
APPENDIX B
Report of Management and Directors on Reserves Data and Other Information
Management and directors of EnCana Corporation (the "Corporation") are responsible for the preparation and disclosure of information with respect to the Corporation's 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 an MRRS Decision Document dated December 16, 2003, and require disclosure of information contemplated by, and consistent with, US Disclosure Requirements and US Disclosure Practices (as defined in the Decision Document). Required information includes reserves data, which consist of the following:
Independent qualified reserves evaluators have evaluated the Corporation's reserves data. A report from the independent qualified reserves evaluators dated February 12, 2008 (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 Committee is comprised exclusively of non-management and unrelated directors, has:
The board of directors of the Corporation (the "Board of Directors") has reviewed the standardized measure calculation with respect to the Corporation's proved oil and gas reserves quantities. The Board of Directors has reviewed the Corporation's 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:
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.
(signed) Randall K. Eresman President & Chief Executive Officer |
(signed) Sherri A. Brillon Executive Vice-President, Strategic Planning & Portfolio Management |
|
(signed) David P. O'Brien Director and Chairman of the Board |
(signed) James M. Stanford, O.C. Director and Chairman of the Reserves Committee |
February 13, 2008
64
APPENDIX C
Audit Committee Mandate
Last Updated December 13, 2006
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 Committee's primary duties and responsibilities are to:
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 Member's 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 five and not more than eight directors as determined by the Board, all of whom shall qualify as independent directors pursuant to Multilateral Instrument 52-110 Audit Committees (as implemented by the Canadian Securities Administrators and as amended from time to time) ("MI 52-110").
All members of the Committee shall be financially literate, as defined in MI 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:
65
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, and the rules adopted by the 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.
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.
66
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 Comptroller and the head of internal audit are expected to be available to attend the Committee's 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 member's 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 Committee's activities by a report following each Committee meeting.
III. RESPONSIBILITIES
Review Procedures
Review and update the Committee's mandate annually, or sooner, where the Committee deems it appropriate to do so. Provide a summary of the Committee's composition and responsibilities in the Corporation's 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 Corporation's annual report filed with the United States Securities and Exchange Commission.
67
Annual Financial Statements
The review shall include a report from the external auditors about the quality of the most critical accounting principles upon which the Corporation's financial status depends, and which involve the most complex, subjective or significant judgemental decisions or assessments.
Quarterly Financial Statements
Review quarterly unaudited financial statements of any subsidiary of the Corporation with public securities prior to their distribution.
68
Other Financial Filings and Public Documents
Internal Control Environment
Other Review Items
69
which could adversely affect the Corporation's 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 United States Securities Exchange Act of 1934, as amended (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 Corporation's internal controls and procedures for financial reporting.
External Auditors
70
Internal Audit Department and Legal Compliance
Approval of Audit and Non-Audit Services
71
Other Matters
72
EnCana Corporation
December 31, 2007
Managements Discussion and Analysis
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, 2007, as well as the audited Consolidated Financial Statements and MD&A for the year ended December 31, 2006. Readers should also read the Forward-Looking Statements legal advisory contained at the end of this MD&A.
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. protocol reporting. This MD&A is dated February 21, 2008.
Readers can find the definition of certain terms used in this MD&A in the disclosure regarding Oil and Gas Information and Currency, Non-GAAP Measures and References to EnCana contained in the Advisories section located at the end of this MD&A.
EnCanas Business |
EnCana is a leading North American unconventional natural gas and integrated oil company.
EnCana operates three business segments:
Canada, United States and Other includes the Companys upstream exploration for, and development and production of natural gas, crude oil and natural gas liquids (NGLs) and other related activities. The majority of the Companys upstream operations are located in Canada and the U.S. Offshore and international exploration is mainly focused on opportunities in Atlantic Canada, the Middle East and Europe.
Integrated Oil is focused on two lines of business: the exploration for, and development and production of bitumen in Canada using in-situ recovery methods; and the refining of crude oil into petroleum and chemical products in the U.S. This segment represents EnCanas 50 percent interest in a joint venture with ConocoPhillips.
Market Optimization is focused on enhancing the sale of EnCanas upstream production. As part of these activities, Market Optimization buys and sells third party products to enhance EnCanas operational flexibility for transportation commitments, product type, delivery points and customer diversification.
2007 Overview |
In 2007 compared to 2006, EnCana:
Formed a North American integrated oil business with ConocoPhillips;
Reported a 20 percent increase in Cash Flow from Continuing Operations to $8,453 million primarily due to an increase of $1,018 million before-tax in Operating Cash Flow from the integrated oil business with ConocoPhillips and an increase of $760 million after-tax in realized financial hedging gains;
Reported a 27 percent increase in Operating Earnings from Continuing Operations to $4,100 million;
Reported a 23 percent decrease in Net Earnings from Continuing Operations to $3,884 million primarily due to after-tax unrealized mark-to-market losses of $811 million in 2007 compared with gains of $1,357 million in 2006 and a $255 million after-tax gain on divestiture of assets in Brazil in 2006;
Reported a $1,526 million increase in Free Cash Flow to $2,418 million;
Grew natural gas production 6 percent to 3,566 million cubic feet (MMcf) of gas per day (MMcf/d);
Increased production from natural gas key resource plays 14 percent;
Grew crude oil production 25 percent at Foster Creek and Christina Lake to 53,628 barrels per day (bbls/d). After reflecting the 50 percent contribution to the joint venture with ConocoPhillips, EnCanas reported production from these two properties decreased 37 percent to 26,814 bbls/d;
Reported a 6 percent decrease in natural gas prices to $5.89 per thousand cubic feet (Mcf). Realized natural gas prices, including the impact of financial hedging, averaged $7.22 per Mcf, an increase of 7 percent;
Acquired additional Deep Bossier natural gas and land interests in East Texas for approximately $2.55 billion before closing adjustments;
1
EnCana Corporation 2007 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Completed the sale of assets in Australia for $31 million, assets in the Mackenzie Delta and Beaufort Sea for $159 million and interests in Chad for $208 million;
Entered into an agreement to sell its remaining interests in Brazil for approximately $165 million before closing adjustments;
Purchased 38.9 million of its Common Shares, representing approximately 5 percent of the shares outstanding at the beginning of the year, at an average price of $52.05 per share under the Normal Course Issuer Bid (NCIB) for a total cost of $2,025 million in 2007;
Added net proved natural gas reserves of 2,184 billion cubic feet (Bcf) and crude oil and NGLs reserves of 241 million barrels (MMbbls) excluding the 398 MMbbls contributed to the integrated oil business;
Was impacted by a 5 percent increase in the U.S./Canadian dollar exchange rate that increased reported total capital investment by $199 million, operating expense by $0.04 per thousand cubic feet equivalent (Mcfe), administrative expense by $0.01 per Mcfe and depreciation, depletion and amortization (DD&A) by $130 million;
Increased its annual dividend by 113 percent to 80 cents per share in 2007 compared to 37.5 cents per share in 2006;
Increased its quarterly dividend to 40 cents per share for the first quarter of 2008; and
Approved the development of the Deep Panuke natural gas project offshore Nova Scotia.
On January 2, 2007, EnCana became a 50 percent partner in an integrated North American oil business with ConocoPhillips that consists of an upstream and a downstream entity. The upstream entity includes contributed assets from EnCana, primarily the Foster Creek and Christina Lake oil properties while the downstream entity includes ConocoPhillips Wood River and Borger refineries located in Illinois and Texas, respectively.
Business Environment |
EnCanas financial results are significantly influenced by fluctuations in commodity prices, which include price differentials, crack spreads and the U.S./Canadian dollar exchange rate. The following table shows select market benchmark prices and foreign exchange rates to assist in understanding EnCanas financial results:
|
|
|
|
2007 vs |
|
|
|
2006 vs |
|
|
|
|||
Year ended December 31 (Average for the period) |
|
2007 |
|
2006 |
|
2006 |
|
2005 |
|
2005 |
|
|||
Natural Gas Price Benchmarks |
|
|
|
|
|
|
|
|
|
|
|
|||
AECO (C$/Mcf) |
|
$ |
6.61 |
|
-5% |
|
$ |
6.98 |
|
-18% |
|
$ |
8.48 |
|
NYMEX ($/MMBtu) |
|
6.86 |
|
-5% |
|
7.22 |
|
-16% |
|
8.62 |
|
|||
Rockies (Opal) ($/MMBtu) |
|
3.95 |
|
-30% |
|
5.65 |
|
-19% |
|
6.96 |
|
|||
Texas (HSC) ($/MMBtu) |
|
6.58 |
|
1% |
|
6.53 |
|
-13% |
|
7.54 |
|
|||
Basis Differential ($/MMBtu) |
|
|
|
|
|
|
|
|
|
|
|
|||
AECO/NYMEX |
|
0.75 |
|
-29% |
|
1.06 |
|
-33% |
|
1.59 |
|
|||
Rockies/NYMEX |
|
2.91 |
|
85% |
|
1.57 |
|
-5% |
|
1.66 |
|
|||
Texas/NYMEX |
|
0.28 |
|
-60% |
|
0.70 |
|
-35% |
|
1.08 |
|
|||
Crude Oil Price Benchmarks |
|
|
|
|
|
|
|
|
|
|
|
|||
West Texas Intermediate (WTI) ($/bbl) |
|
72.41 |
|
9% |
|
66.25 |
|
17% |
|
56.70 |
|
|||
Western Canadian Select (WCS) ($/bbl) |
|
49.50 |
|
11% |
|
44.69 |
|
23% |
|
36.39 |
|
|||
Differential - WTI/WCS ($/bbl) |
|
22.91 |
|
6% |
|
21.56 |
|
6% |
|
20.31 |
|
|||
Refining Margin Benchmark |
|
|
|
|
|
|
|
|
|
|
|
|||
Chicago 3-2-1 Crack Spread ($/bbl)(1) |
|
17.67 |
|
32% |
|
13.38 |
|
11% |
|
12.03 |
|
|||
Foreign Exchange |
|
|
|
|
|
|
|
|
|
|
|
|||
U.S./Canadian Dollar Exchange Rate |
|
0.930 |
|
5% |
|
0.882 |
|
7% |
|
0.825 |
|
|||
(1) 3-2-1 Crack Spread is an indicator of the refining margin generated by converting three barrels of crude oil into two barrels of gasoline and one barrel of diesel. 2005 and 2006 are calculated using Low Sulphur Diesel; 2007 is calculated using Ultra Low Sulphur Diesel.
Acquisitions and Divestitures |
On November 20, 2007, EnCana acquired all of the Deep Bossier natural gas and land interests of privately owned Leor Energy group in East Texas for approximately $2.55 billion before closing adjustments, increasing EnCanas interest to 100 percent in these lands.
In keeping with EnCanas North American resource play and refining operations strategy, the Company completed the following divestitures in 2007:
2
EnCana Corporation 2007 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
The sale of assets in Australia on August 15 for $31 million resulting in a gain on sale of $30 million before-tax ($25 million after-tax);
The sale of its assets in the Mackenzie Delta and Beaufort Sea on May 30 for $159 million;
The sale of its interests in Chad on January 12 for $208 million resulting in a gain on sale of $59 million; and
The sale of other minor properties.
In addition to these divestitures, EnCana completed the sale of The Bow office project assets on February 9, 2007 for approximately $57 million, largely representing its investment at the date of sale.
Proceeds from these divestitures were directed primarily to the purchase of shares under EnCanas NCIB.
On September 13, 2007, EnCana reached an agreement to sell its remaining interests in Brazil for approximately $165 million before closing adjustments. The sale is subject to closing conditions and regulatory approvals, which are expected to be completed in the first half of 2008.
Consolidated Financial Results |
($ millions, except per |
|
2007 |
|
Q4 |
|
Q3 |
|
Q2 |
|
Q1 |
|
2006 |
|
Q4 |
|
Q3 |
|
Q2 |
|
Q1 |
|
2005 |
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Total Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Cash Flow (1) |
|
$ |
8,453 |
|
$ |
1,934 |
|
$ |
2,218 |
|
$ |
2,549 |
|
$ |
1,752 |
|
$ |
7,161 |
|
$ |
1,761 |
|
$ |
1,894 |
|
$ |
1,815 |
|
$ |
1,691 |
|
$ |
7,426 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- per share diluted |
|
11.06 |
|
2.56 |
|
2.93 |
|
3.33 |
|
2.25 |
|
8.56 |
|
2.18 |
|
2.30 |
|
2.15 |
|
1.96 |
|
8.35 |
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Net Earnings |
|
3,959 |
|
1,082 |
|
934 |
|
1,446 |
|
497 |
|
5,652 |
|
663 |
|
1,358 |
|
2,157 |
|
1,474 |
|
3,426 |
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
- per share basic |
|
5.23 |
|
1.44 |
|
1.24 |
|
1.91 |
|
0.65 |
|
6.89 |
|
0.84 |
|
1.68 |
|
2.60 |
|
1.74 |
|
3.95 |
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
- per share diluted |
|
5.18 |
|
1.43 |
|
1.24 |
|
1.89 |
|
0.64 |
|
6.76 |
|
0.82 |
|
1.65 |
|
2.55 |
|
1.70 |
|
3.85 |
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Operating Earnings (2) |
|
4,100 |
|
849 |
|
1,032 |
|
1,369 |
|
850 |
|
3,271 |
|
675 |
|
1,078 |
|
824 |
|
694 |
|
3,241 |
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
- per share diluted |
|
5.36 |
|
1.12 |
|
1.37 |
|
1.79 |
|
1.09 |
|
3.91 |
|
0.84 |
|
1.31 |
|
0.98 |
|
0.80 |
|
3.64 |
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Total Assets |
|
46,974 |
|
|
|
|
|
|
|
|
|
35,106 |
|
|
|
|
|
|
|
|
|
34,148 |
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Long-Term Debt |
|
8,840 |
|
|
|
|
|
|
|
|
|
6,577 |
|
|
|
|
|
|
|
|
|
6,703 |
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Cash Dividends per share |
|
0.800 |
|
0.200 |
|
0.200 |
|
0.200 |
|
0.200 |
|
0.375 |
|
0.100 |
|
0.100 |
|
0.100 |
|
0.075 |
|
0.275 |
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Continuing Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Cash Flow from Continuing Operations (1) |
|
8,453 |
|
1,934 |
|
2,218 |
|
2,549 |
|
1,752 |
|
7,043 |
|
1,742 |
|
1,883 |
|
1,839 |
|
1,579 |
|
6,962 |
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Net Earnings from Continuing Operations |
|
3,884 |
|
1,007 |
|
934 |
|
1,446 |
|
497 |
|
5,051 |
|
643 |
|
1,343 |
|
1,593 |
|
1,472 |
|
2,829 |
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
- per share basic |
|
5.13 |
|
1.34 |
|
1.24 |
|
1.91 |
|
0.65 |
|
6.16 |
|
0.81 |
|
1.66 |
|
1.92 |
|
1.74 |
|
3.26 |
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
- per share diluted |
|
5.08 |
|
1.33 |
|
1.24 |
|
1.89 |
|
0.64 |
|
6.04 |
|
0.80 |
|
1.63 |
|
1.88 |
|
1.70 |
|
3.18 |
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Operating Earnings from Continuing Operations (2) |
|
4,100 |
|
849 |
|
1,032 |
|
1,369 |
|
850 |
|
3,237 |
|
672 |
|
1,064 |
|
841 |
|
660 |
|
3,048 |
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Revenues, Net of Royalties |
|
21,446 |
|
5,801 |
|
5,596 |
|
5,613 |
|
4,436 |
|
16,399 |
|
3,676 |
|
4,029 |
|
3,922 |
|
4,772 |
|
14,573 |
|
(1) Cash Flow and Cash Flow from Continuing Operations are non-GAAP measures and are defined under the Cash Flow section of this MD&A.
(2) Operating Earnings and Operating Earnings from Continuing Operations are non-GAAP measures and are defined under the Operating Earnings section of this MD&A.
CASH FLOW |
Cash Flow is a non-GAAP measure defined as Cash from Operating Activities excluding net change in other assets and liabilities, net change in non-cash working capital from continuing operations and net change in non-cash working capital from discontinued operations, all of which are defined on the Consolidated Statement of Cash Flows. Cash Flow from Continuing Operations is a non-GAAP measure defined as Cash Flow excluding Cash Flow from Discontinued Operations, which is defined on the Consolidated Statement of Cash Flows. While Cash Flow measures are considered non-GAAP, they are commonly used in the oil and gas industry and are used by EnCana to assist Management and investors in measuring the Companys ability to finance capital programs and meet financial obligations.
3
EnCana Corporation 2007 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Summary of Cash Flow from Continuing Operations
($ millions) |
|
2007 |
|
2006 |
|
2005 |
|
|||
Cash From Operating Activities |
|
$ |
8,429 |
|
$ |
7,973 |
|
$ |
7,430 |
|
(Add back) deduct: |
|
|
|
|
|
|
|
|||
Cash Flow from Discontinued Operations |
|
- |
|
118 |
|
464 |
|
|||
Net change in other assets and liabilities |
|
(16 |
) |
138 |
|
(281 |
) |
|||
Net change in non-cash working capital from Continuing Operations |
|
(8 |
) |
3,343 |
|
497 |
|
|||
Net change in non-cash working capital from Discontinued Operations |
|
- |
|
(2,669 |
) |
(212 |
) |
|||
Cash Flow from Continuing Operations |
|
$ |
8,453 |
|
$ |
7,043 |
|
$ |
6,962 |
|
2007 versus 2006
EnCanas 2007 Cash Flow of $8,453 million increased $1,292 million or 18 percent compared to 2006 Cash Flow of $7,161 million.
Cash Flow from Continuing Operations in 2007 was $8,453 million (2006 $7,043 million).
The increase in Cash Flow from Continuing Operations in 2007 compared with 2006 resulted from:
Operating Cash Flow from the Integrated Oil business was $1,294 million in 2007 compared to $276 million in 2006;
Realized financial natural gas, crude oil and other hedging gains were $1,023 million after-tax in 2007 compared with gains of $263 million after-tax in 2006;
Natural gas production volumes in 2007 increased 6 percent to 3,566 MMcf/d from 3,367 MMcf/d in 2006; and
Average North American liquids prices, excluding financial hedges, increased 15 percent to $50.05 per bbl in 2007 compared to $43.71 per bbl in 2006.
Cash Flow from Continuing Operations was reduced by:
Cash taxes were $1,554 million in 2007 compared to $942 million in 2006 primarily as a result of increased operating cash flows in the U.S. and higher realized financial hedging gains offset partially by a $179 million recovery due to a Canadian federal corporate tax legislative change;
Average North American natural gas prices, excluding financial hedges, decreased 6 percent to $5.89 per Mcf in 2007 compared to $6.25 per Mcf in 2006; and
North American liquids production volumes decreased 15 percent to 134,154 bbls/d in 2007 from 157,273 bbls/d in 2006. This decrease reflects the increased production volumes at Foster Creek offset by EnCanas 50 percent contribution of the Foster Creek and Christina Lake properties to the joint venture with ConocoPhillips and natural declines in conventional properties.
2006 versus 2005
EnCanas 2006 Cash Flow was $7,161 million, a decrease of $265 million or 4 percent from 2005 mainly due to the decline in Cash Flow from Discontinued Operations of $346 million year over year.
Cash Flow from Continuing Operations in 2006 was $7,043 million (2005 $6,962 million).
The increase in Cash Flow from Continuing Operations resulted from:
Average North American liquids prices, excluding financial hedges, increased 21 percent to $43.71 per bbl in 2006 compared to $36.17 per bbl in 2005;
North American natural gas production volumes in 2006 increased 4 percent to 3,367 MMcf/d from 3,227 MMcf/d in 2005; and
Realized financial natural gas and crude oil hedging gains were $263 million after-tax in 2006 compared with losses of $441 million after-tax in 2005.
4
EnCana Corporation 2007 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Cash Flow from Continuing Operations was reduced by:
Average North American natural gas prices, excluding financial hedges, decreased 16 percent to $6.25 per Mcf in 2006 compared to $7.46 per Mcf in 2005;
Operating expenses, which increased 15 percent to $1,655 million in 2006 compared with $1,438 million in 2005; and
The current tax provision, excluding income tax on the 2006 sale of assets in Brazil, increased $267 million to $893 million in 2006 compared to $626 million in 2005, excluding income tax on sale of the Gulf of Mexico assets.
Q4 2007 versus Q4 2006
Cash Flow from Continuing Operations in 2007 was $1,934 million, an increase of $192 million or 11 percent compared to 2006.
The increase in Cash Flow from Continuing Operations resulted from:
Average North American liquids prices, excluding financial hedges, increased 54 percent to $59.60 per bbl in 2007 compared to $38.69 per bbl in 2006;
Operating Cash Flow from the integrated oil business was $222 million in 2007 compared to $93 million in 2006;
Realized financial natural gas, crude oil and other hedging gains were $246 million after-tax in 2007 compared with gains of $160 million after-tax in 2006; and
Natural gas production volumes in 2007 increased 9 percent to 3,722 MMcf/d from 3,406 MMcf/d in 2006.
Cash Flow from Continuing Operations was reduced by:
Cash taxes were $580 million in 2007 compared to $113 million in 2006 primarily as a result of adjustments made to full year estimates, U.S. operations and higher realized financial hedging gains; and
North American liquids production volumes decreased 12 percent to 136,137 bbls/d in 2007 from 154,669 bbls/d in 2006. This decrease reflects the increased production volumes at Foster Creek offset by EnCanas 50 percent contribution of the Foster Creek and Christina Lake properties to the joint venture with ConocoPhillips and natural declines in conventional properties.
NET EARNINGS
2007 versus 2006
EnCanas 2007 Net Earnings were $3,959 million, a decrease of $1,693 million compared to 2006. Net Earnings from Discontinued Operations of $75 million in 2007 decreased $526 million from 2006 primarily due to sales of the gas storage business and Ecuador assets in 2006 (discussed in the Discontinued Operations section of this MD&A).
EnCanas 2007 Net Earnings from Continuing Operations were $3,884 million or $1,167 million lower than 2006. In addition to the items affecting Cash Flow from Continuing Operations as detailed previously, significant items affecting Net Earnings from Continuing Operations were:
Unrealized mark-to-market losses of $811 million after-tax in 2007 compared with gains of $1,357 million after-tax in 2006;
DD&A increased $704 million in 2007 compared to 2006 primarily due to higher future development costs, the higher U.S./Canadian dollar exchange rate and the increase in production volumes. In addition, downstream refinery DD&A was $159 million in 2007 with no comparative amount in 2006;
A gain on sale of approximately $255 million after-tax from the sale of a 50 percent interest in the Chinook heavy oil discovery offshore Brazil in 2006;
Reductions in future tax in addition to the impact detailed above related to the unrealized mark-to-market; and
Non-operating foreign exchange gains of $217 million after-tax in 2007 with no comparative amount in 2006.
2006 versus 2005
EnCanas 2006 Net Earnings were $5,652 million, an increase of $2,226 million compared to 2005. Net Earnings for the year included unrealized after-tax mark-to-market gains of $1,370 million (2005 after-tax losses of $277 million) and the effect of the tax rate reduction of $457 million (2005 nil). Net Earnings from Discontinued Operations increased slightly to $601 million in 2006, mainly due to the gain on sale of gas storage assets offset partially by the loss on sale of Ecuador assets (discussed in the Discontinued Operations section of this MD&A).
5
EnCana Corporation 2007 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
EnCanas 2006 Net Earnings from Continuing Operations were $5,051 million, an increase of $2,222 million compared with 2005. In addition to the items affecting Cash Flow as detailed previously, significant items affecting Net Earnings were:
Unrealized mark-to-market gains of $1,357 million after-tax in 2006 compared with losses of $311 million after-tax in 2005;
A gain on sale of approximately $255 million after-tax from the sale of a 50 percent interest in the Chinook heavy oil discovery offshore Brazil; and
An increase in DD&A of $343 million as a result of the higher U.S./Canadian dollar exchange rate, higher DD&A rates and increased production volumes.
Q4 2007 versus Q4 2006
EnCanas 2007 Net Earnings were $1,082 million, an increase of $419 million compared to 2006. Net Earnings from Discontinued Operations of $75 million in 2007 relate to final adjustments on the December 2005 sale of the Companys Midstream NGLs processing operations.
EnCanas 2007 Net Earnings from Continuing Operations were $1,007 million or $364 million higher compared to 2006. In addition to the items affecting Cash Flow from Continuing Operations as detailed previously, significant items affecting Net Earnings from Continuing Operations were:
Non-operating foreign exchange gains of $267 million after-tax in 2007 compared with losses of $128 million after-tax in 2006;
Unrealized mark-to-market losses of $366 million after-tax in 2007 compared with gains of $99 million after-tax in 2006; and
DD&A increased $320 million in 2007 compared to 2006 primarily due to higher future development costs, the higher U.S./Canadian dollar exchange rate and the increase in production volumes; and
Reductions in future tax, which include the impact detailed above related to the unrealized mark-to-market and $264 million due to rate reductions.
OPERATING EARNINGS
Operating Earnings and Operating Earnings from Continuing Operations are non-GAAP measures that adjust Net Earnings and Net Earnings from Continuing Operations by non-operating items that Management believes reduce the comparability of the Companys underlying financial performance between periods. The following reconciliation of Operating Earnings and Operating Earnings from Continuing Operations has been prepared to provide investors with information that is more comparable between periods.
Summary of Operating Earnings
|
|
2007 |
|
2006 |
|
2005 |
|
||||||||||||
($ millions, except per share amounts) |
|
|
|
Per share(5) |
|
|
|
Per share(5) |
|
|
|
Per share(5) |
|
||||||
Net Earnings, as reported |
|
$ |
3,959 |
|
$ |
5.18 |
|
$ |
5,652 |
|
$ |
6.76 |
|
$ |
3,426 |
|
$ |
3.85 |
|
Add back (losses) and deduct gains: |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Unrealized mark-to-market accounting gain (loss), after-tax |
|
(811 |
) |
(1.06 |
) |
1,370 |
|
1.64 |
|
(277 |
) |
(0.31 |
) |
||||||
Non-operating foreign exchange gain (loss), after-tax (1) |
|
217 |
|
0.28 |
|
- |
|
- |
|
92 |
|
0.10 |
|
||||||
Gain (loss) on discontinuance, after-tax (2) |
|
152 |
|
0.20 |
|
554 |
|
0.66 |
|
370 |
|
0.42 |
|
||||||
Future tax recovery due to tax rate reductions |
|
301 |
|
0.40 |
|
457 |
|
0.55 |
|
- |
|
- |
|
||||||
Operating Earnings (3) (4) |
|
$ |
4,100 |
|
$ |
5.36 |
|
$ |
3,271 |
|
$ |
3.91 |
|
$ |
3,241 |
|
$ |
3.64 |
|
(1) Unrealized foreign exchange gain (loss) on translation of Canadian issued U.S. dollar debt, the partnership contribution receivable and realized foreign exchange gain (loss) on settlement of intercompany transactions, after-tax. The majority of U.S. dollar debt issued from Canada has maturity dates in excess of five years.
(2) For 2007, primarily the sale of interests in Chad, assets in Australia and final adjustments on the NGL processing business sold in 2005; sale of storage facilities and interests in Ecuador for 2006; sale of NGL processing business for 2005.
(3) Operating Earnings is a non-GAAP measure defined as Net Earnings excluding the after-tax gain/loss 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 and the effect of changes in statutory income tax rates. In 2007, EnCana changed its calculation of Operating Earnings to exclude the foreign exchange effects on settlement of significant intercompany transactions to provide information that is more comparable between periods.
(4) Unrealized gains or losses and realized foreign exchange gains or losses on settlement of intercompany transactions have no impact on Cash Flow.
(5) Per Common Share - diluted.
6
EnCana Corporation 2007 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Summary of Operating Earnings from Continuing Operations
($ millions) |
|
2007 |
|
2006 |
|
2005 |
|
|||
Net Earnings from Continuing Operations, as reported |
|
$ |
3,884 |
|
$ |
5,051 |
|
$ |
2,829 |
|
Add back (losses) and deduct gains: |
|
|
|
|
|
|
|
|||
Unrealized mark-to-market accounting gain (loss), after-tax |
|
(811 |
) |
1,357 |
|
(311 |
) |
|||
Non-operating foreign exchange gain (loss), after-tax (1) |
|
217 |
|
- |
|
92 |
|
|||
Gain (loss) on discontinuance, after-tax (2) |
|
77 |
|
- |
|
- |
|
|||
Future tax recovery due to tax rate reductions |
|
301 |
|
457 |
|
- |
|
|||
Operating Earnings from Continuing Operations (3) (4) |
|
$ |
4,100 |
|
$ |
3,237 |
|
$ |
3,048 |
|
(1) Unrealized foreign exchange gain (loss) on translation of Canadian issued U.S. dollar debt, the partnership contribution receivable and realized foreign exchange gain (loss) on settlement of intercompany transactions, after-tax. The majority of U.S. dollar debt issued from Canada has maturity dates in excess of five years.
(2) Primarily the sale of interests in Chad and assets in Australia for 2007.
(3) Operating Earnings from Continuing Operations is a non-GAAP measure defined as Net Earnings from Continuing Operations excluding the after-tax gain/loss 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 and the effect of changes in statutory income tax rates. In 2007, EnCana changed its calculation of Operating Earnings to exclude the foreign exchange effects on settlement of significant intercompany transactions to provide information that is more comparable between periods.
(4) Unrealized gains or losses and realized foreign exchange gains or losses on settlement of intercompany transactions have no impact on Cash Flow.
FOREIGN EXCHANGE
As disclosed in the Business Environment section of this MD&A, the average U.S./Canadian dollar exchange rate increased 5 percent to $0.930 in 2007 compared to $0.882 in 2006. The table below summarizes the quarterly and total year impacts of this increase on EnCanas operations when compared to the same periods in 2006.
|
|
2007 |
|
Q4 |
|
Q3 |
|
Q2 |
|
Q1 |
|
|||||
Average U.S./Canadian Dollar Exchange Rate |
|
$ |
0.930 |
|
$ |
1.019 |
|
$ |
0.957 |
|
$ |
0.911 |
|
$ |
0.854 |
|
Decrease (increase) in: |
|
|
|
|
|
|
|
|
|
|
|
|||||
Total Capital Investment ($millions) |
|
(199 |
) |
(136 |
) |
(63 |
) |
(20 |
) |
20 |
|
|||||
Operating Expense ($/Mcfe) |
|
(0.04 |
) |
(0.12 |
) |
(0.05 |
) |
(0.01 |
) |
0.01 |
|
|||||
Administrative Expense ($/Mcfe) |
|
(0.01 |
) |
(0.03 |
) |
(0.01 |
) |
- |
|
- |
|
|||||
DD&A ($millions) |
|
(130 |
) |
(86 |
) |
(40 |
) |
(12 |
) |
8 |
|
|||||
7
EnCana Corporation 2007 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
RESULTS OF OPERATIONS
Production Volumes
|
|
2007 |
|
Q4 |
|
Q3 |
|
Q2 |
|
Q1 |
|
2006 |
|
Q4 |
|
Q3 |
|
Q2 |
|
Q1 |
|
2005 |
|
Produced Gas (MMcf/d) |
|
3,566 |
|
3,722 |
|
3,630 |
|
3,506 |
|
3,400 |
|
3,367 |
|
3,406 |
|
3,359 |
|
3,361 |
|
3,343 |
|
3,220 |
|
Crude Oil (bbls/d) |
|
108,976 |
|
109,273 |
|
109,967 |
|
108,916 |
|
107,715 |
|
133,066 |
|
130,563 |
|
132,814 |
|
127,459 |
|
141,552 |
|
131,225 |
|
NGLs (bbls/d) |
|
25,178 |
|
26,864 |
|
26,416 |
|
24,500 |
|
22,875 |
|
24,207 |
|
24,106 |
|
23,907 |
|
24,400 |
|
24,421 |
|
25,582 |
|
Continuing Operations (MMcfe/d)(1) |
|
4,371 |
|
4,539 |
|
4,448 |
|
4,306 |
|
4,184 |
|
4,311 |
|
4,334 |
|
4,299 |
|
4,272 |
|
4,339 |
|
4,161 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ecuador (bbls/d)(2) |
|
- |
|
- |
|
- |
|
- |
|
- |
|
11,996 |
|
- |
|
- |
|
- |
|
48,650 |
|
72,916 |
|
Discontinued Operations (MMcfe/d)(1) |
|
- |
|
- |
|
- |
|
- |
|
- |
|
72 |
|
- |
|
- |
|
- |
|
292 |
|
437 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MMcfe/d)(1) |
|
4,371 |
|
4,539 |
|
4,448 |
|
4,306 |
|
4,184 |
|
4,383 |
|
4,334 |
|
4,299 |
|
4,272 |
|
4,631 |
|
4,598 |
|
(1) Liquids converted to thousand cubic feet equivalent at 1 barrel = 6 thousand cubic feet.
(2) Ecuador interests sold on February 28, 2006.
Production volumes from continuing operations increased 1 percent or 60 million cubic feet equivalent per day (MMcfe/d) in 2007 compared to 2006 due to:
Increased production from EnCanas natural gas key resource plays of 14 percent in 2007 compared to 2006; offset by
Decreased production from EnCanas crude oil key resource plays of 25 percent in 2007 compared to 2006 after reflecting the 50 percent contribution of Foster Creek and Christina Lake to the joint venture with ConocoPhillips and as a result of natural declines in conventional properties.
Production volumes on a pro forma basis, after reflecting 100 percent of Foster Creek and Christina Lake production, increased 5 percent or 221 MMcfe/d in 2007 compared to 2006.
Key Resource Plays
|
|
Daily Production |
|
Drilling Activity |
|
||||||||||||
|
|
|
|
2007 vs |
|
|
|
2006 vs |
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
2006 |
|
2005 |
|
2005 |
|
2007 |
|
2006 |
|
2005 |
|
Natural Gas (MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jonah |
|
557 |
|
20% |
|
464 |
|
7% |
|
435 |
|
135 |
|
163 |
|
104 |
|
Piceance |
|
348 |
|
7% |
|
326 |
|
6% |
|
307 |
|
286 |
|
220 |
|
266 |
|
East Texas |
|
143 |
|
44% |
|
99 |
|
10% |
|
90 |
|
35 |
|
59 |
|
84 |
|
Fort Worth |
|
124 |
|
23% |
|
101 |
|
44% |
|
70 |
|
75 |
|
97 |
|
59 |
|
Greater Sierra |
|
211 |
|
-1% |
|
213 |
|
-3% |
|
219 |
|
109 |
|
115 |
|
164 |
|
Cutbank Ridge |
|
234 |
|
38% |
|
170 |
|
85% |
|
92 |
|
81 |
|
116 |
|
135 |
|
Bighorn |
|
119 |
|
31% |
|
91 |
|
65% |
|
55 |
|
58 |
|
52 |
|
51 |
|
CBM |
|
259 |
|
34% |
|
194 |
|
73% |
|
112 |
|
1,079 |
|
729 |
|
1,245 |
|
Shallow Gas (1) |
|
726 |
|
-2% |
|
739 |
|
-3% |
|
765 |
|
1,914 |
|
1,310 |
|
1,389 |
|
|
|
2,721 |
|
14% |
|
2,397 |
|
12% |
|
2,145 |
|
3,772 |
|
2,861 |
|
3,497 |
|
Oil (Mbbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foster Creek |
|
49 |
|
31% |
|
37 |
|
27% |
|
29 |
|
45 |
|
6 |
|
39 |
|
Christina Lake |
|
5 |
|
-13% |
|
6 |
|
9% |
|
5 |
|
7 |
|
2 |
|
- |
|
Partners 50% Interest |
|
(27 |
) |
- |
|
- |
|
- |
|
- |
|
(26 |
) |
- |
|
- |
|
|
|
27 |
|
-37% |
|
43 |
|
24% |
|
34 |
|
26 |
|
8 |
|
39 |
|
Pelican Lake |
|
23 |
|
-1% |
|
24 |
|
-9% |
|
26 |
|
- |
|
- |
|
52 |
|
|
|
50 |
|
-25% |
|
66 |
|
10% |
|
60 |
|
26 |
|
8 |
|
91 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MMcfe/d) |
|
3,021 |
|
8% |
|
2,795 |
|
12% |
|
2,506 |
|
3,798 |
|
2,869 |
|
3,588 |
|
(1) Shallow Gas volumes and net wells drilled report commingled volumes from multiple zones within the same geographic area as a result of regulatory approval, which was received in late 2006. Figures for 2005 and 2006 have been restated accordingly.
8
EnCana Corporation 2007 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
CANADA, UNITED STATES AND OTHER
Produced Gas
Financial Results from Continuing Operations
($ millions, except per unit amounts in $ per thousand cubic feet) |
|
2007 |
|
|||||||||||||||||
|
|
Canada |
|
United States |
|
Total |
|
|||||||||||||
|
|
|
|
$/Mcf |
|
|
|
$/Mcf |
|
|
|
$/Mcf |
|
|||||||
Revenues, Net of Royalties / Price |
|
$ |
5,058 |
|
$ |
6.20 |
|
$ |
2,641 |
|
$ |
5.38 |
|
$ |
7,699 |
|
$ |
5.89 |
|
|
Realized Financial Hedging Gain |
|
613 |
|
|
|
1,124 |
|
|
|
1,737 |
|
|
|
|||||||
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Production and mineral taxes |
|
70 |
|
0.09 |
|
167 |
|
0.34 |
|
237 |
|
0.18 |
|
|||||||
Transportation and selling |
|
285 |
|
0.35 |
|
307 |
|
0.62 |
|
592 |
|
0.45 |
|
|||||||
Operating |
|
744 |
|
0.92 |
|
323 |
|
0.65 |
|
1,067 |
|
0.82 |
|
|||||||
Operating Cash Flow / Netback (1) |
|
$ |
4,572 |
|
$ |
4.84 |
|
$ |
2,968 |
|
$ |
3.77 |
|
$ |
7,540 |
|
$ |
4.44 |
|
|
Netback including Realized Financial Hedging |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
5.77 |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Gas Production Volumes (MMcf/d) |
|
|
|
2,221 |
|
|
|
1,345 |
|
|
|
3,566 |
|
|
|
2006 |
|
|||||||||||||||||
|
|
Canada |
|
United States |
|
Total |
|
|||||||||||||
|
|
|
|
$/Mcf |
|
|
|
$/Mcf |
|
|
|
$/Mcf |
|
|||||||
Revenues, Net of Royalties / Price |
|
$ |
4,968 |
|
$ |
6.20 |
|
$ |
2,742 |
|
$ |
6.35 |
|
$ |
7,710 |
|
$ |
6.25 |
|
|
Realized Financial Hedging Gain |
|
472 |
|
|
|
112 |
|
|
|
584 |
|
|
|
|||||||
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Production and mineral taxes |
|
80 |
|
0.10 |
|
213 |
|
0.49 |
|
293 |
|
0.24 |
|
|||||||
Transportation and selling |
|
278 |
|
0.35 |
|
248 |
|
0.54 |
|
526 |
|
0.42 |
|
|||||||
Operating |
|
629 |
|
0.79 |
|
283 |
|
0.65 |
|
912 |
|
0.74 |
|
|||||||
Operating Cash Flow / Netback (1) |
|
$ |
4,453 |
|
$ |
4.96 |
|
$ |
2,110 |
|
$ |
4.67 |
|
$ |
6,563 |
|
$ |
4.85 |
|
|
Netback including Realized Financial Hedging |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
5.32 |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Gas Production Volumes (MMcf/d) |
|
|
|
2,185 |
|
|
|
1,182 |
|
|
|
3,367 |
|
|
|
2005 |
|
|||||||||||||||||
|
|
Canada |
|
United States |
|
Total |
|
|||||||||||||
|
|
|
|
$/Mcf |
|
|
|
$/Mcf |
|
|
|
$/Mcf |
|
|||||||
Revenues, Net of Royalties / Price |
|
$ |
5,669 |
|
$ |
7.27 |
|
$ |
3,126 |
|
$ |
7.82 |
|
$ |
8,795 |
|
$ |
7.46 |
|
|
Realized Financial Hedging Loss |
|
(183 |
) |
|
|
(194 |
) |
|
|
(377 |
) |
|
|
|||||||
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Production and mineral taxes |
|
76 |
|
0.10 |
|
325 |
|
0.81 |
|
401 |
|
0.34 |
|
|||||||
Transportation and selling |
|
283 |
|
0.36 |
|
182 |
|
0.46 |
|
465 |
|
0.40 |
|
|||||||
Operating |
|
521 |
|
0.67 |
|
212 |
|
0.53 |
|
733 |
|
0.62 |
|
|||||||
Operating Cash Flow / Netback (1) |
|
$ |
4,606 |
|
$ |
6.14 |
|
$ |
2,213 |
|
$ |
6.02 |
|
$ |
6,819 |
|
$ |
6.10 |
|
|
Netback including Realized Financial Hedging |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
5.78 |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Gas Production Volumes (MMcf/d) |
|
|
|
2,125 |
|
|
|
1,095 |
|
|
|
3,220 |
|
(1) Netback excludes the impact of realized financial hedging.
9
EnCana Corporation 2007 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Produced Gas Revenue Variances for 2007 Compared to 2006 from Continuing Operations
|
|
2006 Revenues |
|
Revenue |
|
2007 Revenues |
|
|||||||||
|
|
Net of |
|
Variances in: |
|
Net of |
|
|||||||||
($ millions) |
|
Royalties |
|
Price(1) |
|
Volume |
|
Other(2) |
|
Royalties |
|
|||||
Canada |
|
$ |
5,440 |
|
$ |
132 |
|
$ |
91 |
|
$ |
8 |
|
$ |
5,671 |
|
United States |
|
2,854 |
|
455 |
|
456 |
|
- |
|
3,765 |
|
|||||
Total Produced Gas |
|
$ |
8,294 |
|
$ |
587 |
|
$ |
547 |
|
$ |
8 |
|
$ |
9,436 |
|
(1) Includes the impact of realized financial hedging.
(2) Includes Gas-over-Bitumen revenues resulting from wells shut-in or denied production that are received from the Alberta Government.
2007 versus 2006
Revenues, net of royalties, increased in 2007 compared with 2006 due to:
Realized financial hedging gains totaled $1,737 million or $1.33 per Mcf in 2007 compared to gains of $584 million or $0.47 per Mcf in 2006; and
A 6 percent increase in natural gas production volumes offset by a 6 percent decrease in North American natural gas prices, excluding the impact of financial hedging.
Produced gas volumes in the U.S. increased 14 percent in 2007 as a result of drilling and operational success as well as new facilities at Jonah, East Texas, Fort Worth and Piceance. Fourth quarter 2007 produced gas volumes in the U.S. also benefited slightly from incremental volumes from the Deep Bossier acquisition (34 MMcf/d). Produced gas volumes in Canada increased 2 percent in 2007. Drilling success and new facilities in the key resource plays of CBM, Cutbank Ridge and Bighorn were offset by natural declines for conventional properties.
The decrease in EnCanas North American natural gas price in 2007, excluding the impact of financial hedges, reflects the decline in AECO and NYMEX benchmark prices and changes in the basis differentials. Variability in realized prices also reflects the weighting of EnCanas various gas stream volumes at their respective benchmark price, net of applicable basis differential.
Natural gas per unit production and mineral taxes in the U.S. decreased $0.15 per Mcf or 31 percent in 2007 compared to 2006 mainly as a result of lower natural gas prices in the U.S. Rockies and a reduction in the severance and ad valorem effective tax rate for Colorado properties.
Natural gas per unit transportation and selling costs for the U.S. increased 15 percent or $0.08 per Mcf in 2007 compared to 2006 primarily as a result of higher transportation rates in the Piceance area.
Natural gas per unit operating expenses for Canada in 2007 were 16 percent or $0.13 per Mcf higher than in 2006 as a result of the higher U.S./Canadian dollar exchange rate discussed earlier, higher repairs and maintenance expenses and increased property taxes and lease rentals offset partially by decreased electricity costs. Operating costs in both Canada and the U.S. were also impacted by higher long-term compensation costs in 2007 compared to 2006 due to increases in the EnCana share price, which resulted in a $0.03 per Mcf increase in operating costs for North American natural gas.
2006 versus 2005
Revenues, net of royalties, decreased in 2006 compared with 2005 due to:
A 16 percent decrease in North American natural gas prices, excluding the impact of financial hedging; offset by
A 5 percent increase in natural gas production volumes; and
Realized financial hedging gains totaled $584 million or $0.47 per Mcf in 2006 compared to losses of $377 million or $0.32 per Mcf in 2005.
Produced gas volumes in Canada increased 3 percent in 2006, mainly due to drilling success in the key resource plays of CBM, Cutbank Ridge and Bighorn and additional well tie-ins and recompletions in several areas. CBM is the commingled gas volumes from the coal and sand intervals based on regulatory approval. Offsetting the increase were unscheduled maintenance, natural declines, planned turnarounds and weather related delays for the Shallow Gas key resource play and conventional properties, which resulted in lower production volumes. Produced gas volumes in the U.S. increased 8 percent in 2006 as a result of drilling success at Fort Worth, Jonah, Piceance and East Texas as well as the impact of property acquisitions in the Fort Worth Basin in late 2005.
10
EnCana Corporation 2007 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
EnCanas North American natural gas price for 2006, excluding the impact of financial hedges, was $6.25 per Mcf, a decrease of 16 percent from 2005, consistent with the decline in the AECO price of 18 percent and the NYMEX price of 16 percent. North American realized financial hedging gains on natural gas for 2006 were approximately $584 million or $0.47 per Mcf compared to losses of approximately $377 million or $0.32 per Mcf in 2005. The hedging gains in 2006 were a result of put hedging instruments transacted at higher price levels than in 2006, coupled with a decline in North American natural gas prices in 2006 compared to 2005.
Natural gas per unit production and mineral taxes, which are generally calculated as a percentage of revenues, remained flat in Canada for 2006 mainly due to lower natural gas prices offset partially by the higher U.S./Canadian dollar exchange rate. Natural gas per unit production and mineral taxes in the U.S. decreased $0.32 per Mcf or 40 percent in 2006 mainly as a result of a reduction in the effective production and severance tax rates for Colorado properties and lower natural gas prices.
Natural gas per unit transportation and selling costs for the U.S. increased $0.08 per Mcf or 17 percent for 2006 primarily as a result of higher transportation costs on operated wells from Piceance, East Texas and certain Colorado properties.
Natural gas per unit operating expenses in Canada for 2006 were 18 percent or $0.12 per Mcf higher as a result of the higher U.S./Canadian dollar exchange rate, increased industry activity, property taxes and lease rentals, electricity rates and salaries and benefits. Natural gas per unit operating expenses in the U.S. increased 23 percent or $0.12 per Mcf for 2006 mainly as a result of increased industry activity, chemicals, salaries, workovers and repairs and maintenance expenses. Increases in operating costs in both Canada and the U.S. were offset partially by lower long-term compensation costs in 2006 compared to 2005.
Crude Oil and NGLs
Financial Results from Continuing Operations
($ millions) |
|
2007 |
|
|||||||
|
|
Canada(1) |
|
United States |
|
Total |
|
|||
Revenues, Net of Royalties |
|
$ |
1,645 |
|
$ |
309 |
|
$ |
1,954 |
|
Expenses |
|
|
|
|
|
|
|
|||
Production and mineral taxes |
|
32 |
|
22 |
|
54 |
|
|||
Transportation and selling |
|
42 |
|
- |
|
42 |
|
|||
Operating |
|
266 |
|
- |
|
266 |
|
|||
Operating Cash Flow |
|
$ |
1,305 |
|
$ |
287 |
|
$ |
1,592 |
|
|
|
2006 |
|
|||||||
|
|
Canada(1) |
|
United States |
|
Total |
|
|||
Revenues, Net of Royalties |
|
$ |
1,530 |
|
$ |
267 |
|
$ |
1,797 |
|
Expenses |
|
|
|
|
|
|
|
|||
Production and mineral taxes |
|
36 |
|
20 |
|
56 |
|
|||
Transportation and selling |
|
52 |
|
- |
|
52 |
|
|||
Operating |
|
237 |
|
- |
|
237 |
|
|||
Operating Cash Flow |
|
$ |
1,205 |
|
$ |
247 |
|
$ |
1,452 |
|
|
|
2005 |
|
|||||||
|
|
Canada(1) |
|
United States |
|
Total |
|
|||
Revenues, Net of Royalties |
|
$ |
1,297 |
|
$ |
245 |
|
$ |
1,542 |
|
Expenses |
|
|
|
|
|
|
|
|||
Production and mineral taxes |
|
28 |
|
24 |
|
52 |
|
|||
Transportation and selling |
|
17 |
|
- |
|
17 |
|
|||
Operating |
|
206 |
|
- |
|
206 |
|
|||
Operating Cash Flow |
|
$ |
1,046 |
|
$ |
221 |
|
$ |
1,267 |
|
(1) Excludes Foster Creek/Christina Lake, which are discussed under Integrated Oil.
11
EnCana Corporation 2007 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Crude Oil and NGLs Revenue Variances for 2007 Compared to 2006 from Continuing Operations
|
|
2006 Revenues |
|
Revenue |
|
2007 Revenues |
|
||||||||
|
|
Net of |
|
Variances in: |
|
|
Net of |
|
|||||||
($ millions) |
|
Royalties |
|
Price(1) |
|
Volume |
|
Royalties |
|
||||||
Canada(2) |
|
$ |
1,530 |
|
$ |
221 |
|
$ |
(106 |
) |
$ |
1,645 |
|
||
United States |
|
267 |
|
15 |
|
27 |
|
309 |
|
||||||
Total Crude Oil and NGLs |
|
$ |
1,797 |
|
$ |
236 |
|
$ |
(79 |
) |
$ |
1,954 |
|
||
(1) Includes the impact of realized financial hedging.
(2) Excludes Foster Creek/Christina Lake, which are discussed under Integrated Oil.
2007 versus 2006
Revenues, net of royalties, increased in 2007 compared with 2006 due to:
A 13 percent increase in Canada crude oil and 11 percent increase in North American NGLs prices, excluding financial hedges partially offset by a 6 percent decrease in North American liquids production volumes; and
Realized financial hedging losses on liquids totaled $110 million or $3.05 per bbl in 2007 compared to losses of $125 million or $3.32 per bbl in 2006.
Canada crude oil production decreased 9 percent primarily due to natural declines in conventional properties.
2006 versus 2005
Revenues, net of royalties, increased in 2006 compared with 2005 due to:
A 16 percent increase in Canada crude oil and 16 percent increase in North American NGLs prices, excluding financial hedges; and
Realized financial hedging losses on liquids totaled $125 million or $3.32 per bbl in 2006 compared to losses of $218 million or $5.18 per bbl in 2005.
North American crude oil and NGLs volumes decreased 6 percent due to the Pelican Lake royalty payout, unscheduled maintenance, delays in capital programs in southern Alberta and natural declines. EnCanas Pelican Lake property reached payout in April 2006 which increased the royalty payments to the Alberta Government and reduced EnCanas net revenue interest crude oil volumes by approximately 6,000 bbls/d from the point of payout.
Per Unit Results Crude Oil
($ per barrel) |
|
Canada(1) |
|
|||||||
|
|
2007 |
|
2006 |
|
2005 |
|
|||
Price (2) |
|
$ |
50.76 |
|
$ |
44.83 |
|
$ |
38.49 |
|
Expenses |
|
|
|
|
|
|
|
|||
Production and mineral taxes |
|
1.09 |
|
1.11 |
|
0.79 |
|
|||
Transportation and selling |
|
1.32 |
|
0.91 |
|
1.08 |
|
|||
Operating |
|
9.03 |
|
7.69 |
|
5.90 |
|
|||
Netback |
|
$ |
39.32 |
|
$ |
35.12 |
|
$ |
30.72 |
|
|
|
|
|
|
|
|
|
|||
Crude Oil Production Volumes (bbls/d) |
|
82,162 |
|
90,298 |
|
96,846 |
|
(1) Excludes Foster Creek/Christina Lake, which are discussed under Integrated Oil.
(2) Excludes the impact of realized financial hedging.
2007 versus 2006
Canada crude oil prices in 2007 increased 13 percent compared to 2006. This increase reflects the changes in benchmark WTI and WCS crude oil prices compared to 2006. Total realized financial hedging losses on crude oil for Canada were approximately $96 million or $3.20 per bbl in 2007 compared to losses of approximately $110 million or $3.43 per bbl in 2006.
Canada crude oil per unit transportation and selling costs increased 45 percent or $0.41 per bbl in 2007 compared to 2006 due to increased clean oil trucking costs at Weyburn, the higher U.S./Canadian dollar exchange rate and additional marketing costs.
12
EnCana Corporation 2007 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Canada crude oil per unit operating costs in 2007 increased 17 percent or $1.34 per bbl compared to 2006 mainly due to the higher U.S./Canadian dollar exchange rate, increased workovers, higher long-term compensation costs due to the increase in the EnCana share price and increased chemicals offset partially by decreased electricity costs.
2006 versus 2005
The increase in EnCanas Canada crude oil price for 2006, excluding the impact of financial hedges, reflects the 17 percent increase in the benchmark WTI crude oil price compared to 2005. Canada realized financial hedging losses on crude oil were approximately $110 million or $3.43 per bbl for 2006 compared to losses of approximately $218 million or $6.21 per bbl for 2005. The reduced hedging losses in 2006 were a result of fixed price and put hedging instruments transacted at higher price levels than in 2005, coupled with an increase in benchmark oil prices in 2006 compared to 2005.
Canada crude oil production in 2006 decreased 7 percent from 2005 as a result of the Pelican Lake royalty payout in April 2006, property dispositions and declining production on conventional properties.
Canada crude oil per unit production and mineral taxes increased 41 percent or $0.32 per bbl in 2006 primarily due to increased production from the Weyburn and Senlac properties in Saskatchewan, which are subject to freehold production tax and Saskatchewan resource tax, the higher U.S./Canadian dollar exchange rate and the impact of higher overall prices.
Canada crude oil per unit transportation and selling costs decreased 16 percent or $0.17 per bbl in 2006 primarily due to lower transportation costs resulting from the disposition of properties with higher rates and costs in 2005.
Canada crude oil per unit operating costs for 2006 increased 30 percent or $1.79 per bbl mainly due to the higher U.S./Canadian dollar exchange rate, increased electricity rates, a prior period adjustment for a non-operated property, increased industry activity and lower production from Pelican Lake as a result of the royalty payout in the second quarter of 2006.
Per Unit Results NGLs
NGLs are a byproduct obtained through the production of natural gas. As a result, operating costs associated with the production of NGLs are included with produced gas. Costs directly associated with NGLs production such as production and mineral taxes and transportation and selling costs totaled $26 million in 2007 compared to $22 million in 2006.
Upstream Depreciation, Depletion and Amortization
EnCana uses full cost accounting and calculates DD&A on a country-by-country cost centre basis. Accordingly, the DD&A rate for Canada and Foster Creek/Christina Lake are the same.
2007 versus 2006
Upstream DD&A expenses of $3,423 million in 2007 increased $555 million or 19 percent compared to 2006 due to:
North American production volumes excluding Foster Creek/Christina Lake increased 4 percent;
DD&A rates in 2007 were higher than 2006 primarily as a result of increased future development costs and the higher U.S./Canadian dollar exchange rate; and
DD&A in 2007 included impairments of $44 million and $24 million related to exploration prospects in France and Oman, respectively compared to $6 million in 2006.
2006 versus 2005
Upstream DD&A expenses of $2,868 million in 2006 increased $296 million or 12 percent compared to 2005 due to:
North American production volumes excluding Foster Creek/Christina Lake increased 2 percent;
DD&A rates in 2006 were higher than 2005 as a result of the higher U.S./Canadian dollar exchange rate and an increase in future development costs partially reduced by the effect of the Gulf of Mexico sale in May 2005; and
DD&A in 2006 included impairments of $6 million related to exploration prospects in the Middle East compared to $7 million in 2005.
13
EnCana Corporation 2007 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
INTEGRATED OIL
Foster Creek/Christina Lake Operations
Financial Results from Continuing Operations
($ millions) |
|
Foster Creek/Christina Lake |
|
|||||||
|
|
2007 |
|
2006 |
|
2005 |
|
|||
Revenues, Net of Royalties |
|
$ |
738 |
|
$ |
941 |
|
$ |
529 |
|
Expenses |
|
|
|
|
|
|
|
|||
Transportation and selling |
|
366 |
|
476 |
|
350 |
|
|||
Operating |
|
159 |
|
194 |
|
137 |
|
|||
Operating Cash Flow |
|
$ |
213 |
|
$ |
271 |
|
$ |
42 |
|
Crude Oil Revenue Variances for 2007 Compared to 2006 from Continuing Operations
|
|
2006 Revenues |
|
Revenue |
|
2007 Revenues |
|
|||||
|
|
Net of |
|
Variances in: |
|
Net of |
|
|||||
($ millions) |
|
Royalties |
|
Price(1) |
|
Volume |
|
Other(2) |
|
Royalties |
|
|
Foster Creek/ Christina Lake |
|
$ |
941 |
|
66 |
|
(168 |
) |
(101 |
) |
738 |
|
(1) Includes the impact of realized financial hedging.
(2) Revenue dollars reported include the value of condensate sold as bitumen blend. Condensate costs are recorded in transportation expense.
2007 versus 2006
Revenues, net of royalties, decreased in 2007 compared with 2006 due to:
A 37 percent decrease in Foster Creek/Christina Lake crude oil production volumes as a result of the joint venture with ConocoPhillips partially offset by a 10 percent increase in crude oil prices, excluding financial hedges. Production volumes on a pro forma basis, after reflecting 100 percent of Foster Creek and Christina Lake production, grew 25 percent to 53,628 bbls/d in 2007 compared to 2006;
Realized financial hedging losses totaled $43 million or $3.88 per bbl in 2007 compared to losses of $62 million or $3.98 per bbl in 2006; and
Lower condensate purchased for bitumen blending at Foster Creek/Christina Lake as a result of the joint venture with ConocoPhillips.
2006 versus 2005
Revenues, net of royalties, increased in 2006 compared with 2005 due to:
A 66 percent increase in Foster Creek/Christina Lake crude oil prices, excluding financial hedges combined with a 24 percent increase in crude oil production volumes primarily as a result of continued development at Foster Creek; and
Realized financial hedging losses totaled $62 million or $3.98 per bbl in 2006 compared to losses of $77 million or $6.16 per bbl in 2005.
14
EnCana Corporation 2007 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Per Unit Results Crude Oil
($ per barrel) |
|
Foster Creek/Christina Lake |
|
|||||||
|
|
2007 |
|
2006 |
|
2005 |
|
|||
Price (1) |
|
$ |
40.14 |
|
$ |
36.49 |
|
$ |
22.02 |
|
Expenses |
|
|
|
|
|
|
|
|||
Transportation and selling |
|
2.88 |
|
2.64 |
|
1.54 |
|
|||
Operating |
|
14.46 |
|
12.38 |
|
10.94 |
|
|||
Netback |
|
$ |
22.80 |
|
$ |
21.47 |
|
$ |
9.54 |
|
|
|
|
|
|
|
|
|
|||
Crude Oil Production Volumes (bbls/d) |
|
26,814 |
|
42,768 |
|
34,379 |
|
|||
Pro forma Production Volumes (bbls/d)(2) |
|
26,814 |
|
21,384 |
|
17,190 |
|
(1) Excludes the impact of realized financial hedging.
(2) 2005 and 2006 production volumes adjusted on a pro forma basis to reflect the 50 percent contribution of Foster Creek and Christina Lake to the business venture with ConocoPhillips in 2007.
2007 versus 2006
Foster Creek/Christina Lake crude oil prices in 2007 increased 10 percent compared to 2006. This increase reflects the changes in benchmark WTI and WCS crude oil prices compared to 2006.
Foster Creek/Christina Lake crude oil per unit transportation and selling costs in 2007 increased 9 percent or $0.24 per bbl compared to 2006 due to a higher percentage of volumes being delivered to the U.S. Gulf Coast in 2007 compared to 2006 and the higher U.S./Canadian dollar exchange rate.
Foster Creek/Christina Lake crude oil per unit operating costs increased 17 percent or $2.08 per bbl in 2007 compared to 2006. This reflected increased purchased fuel costs at Foster Creek to steam new well pairs prior to commencing production, increased repairs and maintenance, salaries and benefits and chemicals. In addition, operating costs for 2007 compared to 2006 were impacted by the higher U.S./Canadian dollar exchange rate and higher long-term compensation costs due to the increase in the EnCana share price.
2006 versus 2005
The increase in Foster Creek/Christina Lake crude oil price for 2006, excluding the impact of financial hedges, reflects the 17 percent increase in the benchmark WTI crude oil price compared to 2005 and greater access to markets in the U.S. Gulf Coast. Foster Creek/Christina Lake realized financial hedging losses on crude oil were approximately $62 million or $3.98 per bbl for 2006 compared to losses of approximately $77 million or $6.16 per bbl for 2005. The reduced hedging losses in 2006 were a result of fixed price and put hedging instruments transacted at higher price levels than in 2005, coupled with an increase in benchmark oil prices in 2006 compared to 2005.
Per unit transportation and selling costs increased 71 percent or $1.10 per bbl in 2006 primarily due to a higher proportion of oil volumes being delivered to the U.S. Gulf Coast to capture higher selling prices and the higher U.S./Canadian dollar exchange rate. Crude oil transportation and selling costs also include costs of condensate purchased for blending of bitumen, totaling $435 million (2005 $330 million), which are not included in the transportation and selling per unit calculations.
Foster Creek/Christina Lake crude oil per unit operating costs for 2006 increased 13 percent or $1.44 per bbl mainly due to workovers at Foster Creek, the higher U.S./Canadian dollar, increased electricity rates, chemicals, repair and maintenance and increased industry activity.
Foster Creek/Christina Lake Depreciation, Depletion and Amortization
EnCana uses full cost accounting and calculates DD&A on a country-by-country cost centre basis. Accordingly, the DD&A rate for Canada and Foster Creek/Christina Lake are the same.
2007 versus 2006
Foster Creek/Christina Lake DD&A expenses of $125 million in 2007 decreased $32 million or 20 percent compared to 2006 due to:
Production volumes decreased 37 percent; offset partially by
Unit of production DD&A rates were higher than 2006 primarily as a result of increased future development costs and the higher U.S./Canadian dollar exchange rate.
15
EnCana Corporation 2007 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
2006 versus 2005
Foster Creek/Christina Lake DD&A expenses of $157 million in 2006 increased $41 million or 35 percent compared to 2005 due to:
Production volumes increased 24 percent; and
Unit of production DD&A rates were higher than 2005 as a result of the higher U.S./Canadian dollar exchange rate and an increase in future development costs.
Downstream Operations
Financial Results
($ millions) |
|
2007 |
|
|
Revenues |
|
$ |
7,315 |
|
Expenses |
|
|
|
|
Operating |
|
428 |
|
|
Purchased product |
|
5,813 |
|
|
Operating Cash Flow |
|
$ |
1,074 |
|
The downstream business commenced on January 2, 2007 when EnCana became a 50 percent partner in the entity that owns the Wood River and Borger refineries operated by ConocoPhillips.
The Borger refinery, located in Borger, Texas, has a current capacity of approximately 146,000 bbls/d of crude oil and approximately 45,000 bbls/d of NGLs (on a 100 percent basis). In July 2007, a new coker with a capacity of approximately 25,000 bbls/d was brought into service along with a new vacuum unit and revamped gas oil and distillate hydrotreaters.
The Wood River refinery, located in Roxana, Illinois, has a current capacity of approximately 306,000 bbls/d of crude oil (on a 100 percent basis). In early 2007, the refinery completed the construction and start-up of a facility utilizing proprietary sulphur removal technology for the production of low sulphur gasoline.
The goal of Borger and Wood River refineries are to refine approximately 275,000 bbls/d of bitumen (on a 100 percent basis) by 2015 to primarily motor fuels. Currently, the refineries have processing capability to refine up to approximately 70,000 bbls/d of bitumen.
Revenues reflect EnCanas 50 percent share of the sale of refined petroleum products in the U.S. Operating Cash Flow during 2007 benefited from strong refining margins as evidenced by the Chicago 3-2-1 Crack Spread, which is disclosed in the Business Environment section of this MD&A. The Chicago 3-2-1 Crack Spread increased 32 percent to $17.67 per bbl compared to $13.38 per bbl in 2006. On a 100 percent basis, the two refineries have a combined crude oil refining capacity of 452,000 bbls/d and operated at an average 96 percent of that capacity during 2007. Refined products averaged 457,000 bbls/d through 2007.
Purchased products, consisting mainly of crude oil, represented 93 percent of total expenses in 2007. Operating costs for labour, utilities and supplies comprised the balance of expenses for 2007.
Downstream refining DD&A was $159 million in 2007 with no comparative amount in 2006.
MARKET OPTIMIZATION
Financial Results
($ millions) |
|
2007 |
|
2006 |
|
2005 |
|
|||
Revenues |
|
$ |
2,944 |
|
$ |
3,007 |
|
$ |
4,267 |
|
Expenses |
|
|
|
|
|
|
|
|||
Transportation and selling |
|
10 |
|
16 |
|
13 |
|
|||
Operating |
|
37 |
|
62 |
|
85 |
|
|||
Purchased product |
|
2,858 |
|
2,862 |
|
4,159 |
|
|||
Operating Cash Flow |
|
39 |
|
67 |
|
10 |
|
|||
Depreciation, depletion and amortization |
|
17 |
|
12 |
|
8 |
|
|||
Segment Income |
|
$ |
22 |
|
$ |
55 |
|
$ |
2 |
|
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.
16
EnCana Corporation 2007 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
On January 1, 2006, EnCana adopted Emerging Issues Task Force (EITF) Abstract No. 04-13 Accounting for Purchases and Sales of Inventory with the Same Counterparty. The effect is to record purchases and sales of inventory that are entered into in contemplation of each other with the same counterparty on a net basis in the Consolidated Statement of Earnings. This change was adopted prospectively and has no effect on the earnings of the reported periods. These purchases and sales are used to optimize transportation or fulfill marketing arrangements. As a result of the adoption of this policy, reported revenues and purchased product costs for 2007 included offsets of $3,863 million (2006 $3,238 million; 2005 nil).
2007 versus 2006
Revenues and Purchased products were basically flat in 2007 compared with 2006, with slight decreases in prices being offset by increases in volumes required for optimization activities.
2006 versus 2005
Purchased product and revenues before the EITF 04-13 netting increased in 2006 due to third party purchases and sales as a result of the sale of the Empress NGL plant to a third party at the end of 2005. For 2006, this incremental activity to facilitate the movement of EnCana gas through the Empress plant totaled approximately $1.9 billion. This was offset by the EITF 04-13 netting which was applied prospectively for 2006 and was not applied to the 2005 values.
CORPORATE
Financial Results
($ millions) |
|
2007 |
|
2006 |
|
2005 |
|
|||
Revenues |
|
$ |
(1,239 |
) |
$ |
2,050 |
|
$ |
(466 |
) |
Expenses |
|
|
|
|
|
|
|
|||
Operating |
|
(5 |
) |
(12 |
) |
2 |
|
|||
Depreciation, depletion and amortization |
|
92 |
|
75 |
|
73 |
|
|||
Segment Income (Loss) |
|
$ |
(1,326 |
) |
$ |
1,987 |
|
$ |
(541 |
) |
Revenues represent unrealized mark-to-market gains or losses related to financial natural gas and crude oil hedge contracts.
DD&A includes provisions for corporate assets, such as computer equipment, office furniture and leasehold improvements.
Consolidated Corporate Expenses
($ millions) |
|
2007 |
|
2006 |
|
2005 |
|
|||
Administrative |
|
$ |
384 |
|
$ |
271 |
|
$ |
268 |
|
Interest, net |
|
428 |
|
396 |
|
524 |
|
|||
Accretion of asset retirement obligation |
|
64 |
|
50 |
|
37 |
|
|||
Foreign exchange (gain) loss, net |
|
(164 |
) |
14 |
|
(24 |
) |
|||
Stock-based compensation - options |
|
- |
|
- |
|
15 |
|
|||
(Gain) loss on divestitures |
|
(65 |
) |
(323 |
) |
- |
|
|||
2007 versus 2006
Administrative expenses increased $113 million in 2007 compared to 2006 primarily due to higher long-term compensation expenses of $56 million as a result of the increase in the EnCana share price. The higher U.S./Canadian dollar exchange rate added an additional $18 million and the remaining increase was due to increased staff levels, higher salaries, and other related expenses. Administrative expenses in 2007 were $0.24 per Mcfe compared with $0.17 per Mcfe in 2006. Fourth quarter administrative expenses increased $37 million in 2007 compared to 2006 primarily due to higher long-term compensation expenses of $23 million and increased costs of $13 million due to the higher U.S./Canadian dollar exchange rate.
Net interest expense in 2007 increased $32 million from 2006 primarily as a result of higher average outstanding debt. EnCanas total long-term debt, including current portion, increased $2,709 million to $9,543 million at December 31, 2007 compared with $6,834 million at December 31, 2006. EnCanas 2007 weighted average interest rate on outstanding debt was 5.6 percent compared to 5.7 percent in 2006.
The foreign exchange gain of $164 million in 2007 is primarily due to the effects of the U.S./Canadian dollar exchange rate applied to U.S. dollar denominated debt issued from Canada and settlement of foreign denominated intercompany transactions offset by revaluation of the partnership contribution receivable. Fourth quarter 2007 foreign exchange gain of $233 million is primarily due to the effects of the U.S./Canadian dollar exchange rate on settlement of foreign currency denominated intercompany transactions.
17
EnCana Corporation 2007 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
The gain on divestitures in 2007 relates primarily to the divestiture of interests in Chad and assets in Australia. The gain on divestitures in 2006 relates to the divestitures of the Chinook heavy oil discovery offshore Brazil and the Entrega Pipeline.
2006 versus 2005
Administrative expenses in 2006 were comparable with 2005 due to increases for office expenses, the higher U.S./Canadian dollar exchange rate and increased general costs offset by lower long-term compensation expenses, which were tied to EnCanas Common Share price. Administrative expenses in 2006 were $0.17 per Mcfe compared with $0.18 per Mcfe in 2005.
Interest expense in 2006 decreased by $128 million mainly as a result of a $121 million one time charge incurred in 2005 to retire certain medium term notes and lower average outstanding debt in 2006 due to repayments using the sales proceeds from the Entrega Pipeline, Ecuador, Brazil and gas storage divestitures.
Summary of Unrealized Mark-to-Market Gains (Losses) from Continuing Operations
($millions) |
|
2007 |
|
2006 |
|
2005 |
|
|||
Revenues |
|
|
|
|
|
|
|
|||
Natural Gas |
|
$ |
(1,049 |
) |
$ |
1,910 |
|
$ |
(494 |
) |
Crude Oil |
|
(190 |
) |
140 |
|
28 |
|
|||
|
|
(1,239 |
) |
2,050 |
|
(466 |
) |
|||
Expenses |
|
(4 |
) |
(10 |
) |
3 |
|
|||
|
|
(1,235 |
) |
2,060 |
|
(469 |
) |
|||
Income Tax Expense (Recovery) |
|
(424 |
) |
703 |
|
(158 |
) |
|||
Unrealized Mark-to-Market Gains (Losses), after-tax |
|
$ |
(811 |
) |
$ |
1,357 |
|
$ |
(311 |
) |
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 curve commodity price market and changes in the balance of unsettled contracts. Further information regarding financial instrument agreements can be found in Note 18 to the Consolidated Financial Statements.
Income Tax
2007 versus 2006
The effective tax rate for 2007 was 19.4 percent compared to 27.3 percent in 2006. The 2007 rate reflects the effect of a Canadian federal corporate tax legislative change ($179 million) and a reduction in the Canadian federal corporate tax rate ($301 million). The legislative change relates to phase in of the deductibility of Crown royalties which is now complete and will not recur in the future. The Canadian federal tax rate is to be reduced from 19.5 percent to 15 percent between 2008 and 2012. The 2006 effective rate also reflects the effect of reductions in the Canadian federal and Alberta corporate tax rates ($457 million).
Cash taxes were $1,554 million in 2007 compared to $942 million in 2006. The largest component of the increase of $612 million is $519 million of higher U.S. taxes in 2007 offset by the cash tax benefit of the legislative change ($179 million) referred to above. The increase in U.S. tax is due to the cash flows from U.S. downstream refinery operations and increased income from U.S. upstream operations.
2006 versus 2005
The effective tax rate for 2006 was 27.3 percent compared to 30.8 percent for 2005. The decrease was largely due to a decrease in future income tax expense of $457 million as a result of reductions in the Canadian federal and Alberta corporate tax rates, which were enacted in the second quarter of 2006.
Cash taxes excluding cash taxes related to divestitures were $893 million in 2006 compared to $626 million in 2005. The increase in cash tax expense over 2005 primarily reflects higher Canadian income resulting from higher prices in 2005, which was recognized for income tax purposes in 2006. An additional $49 million of cash tax was incurred in 2006, resulting from the divestiture of certain assets in Brazil, compared to $578 million of cash tax in the second quarter of 2005 as a result of the divestiture of the Gulf of Mexico operations. These amounts are included in investing activities in the Consolidated Statement of Cash Flows.
Further information regarding EnCanas effective tax rate can be found in Note 9 to the Consolidated Financial Statements. EnCanas effective rate in any year is a function of the relationship between the amount of net earnings before income taxes for the year and the magnitude of the items representing permanent differences that are excluded from the earnings, which are subject to tax, either current or future. There are a variety of items of this type, including:
The effects of asset divestitures where the tax values of the assets sold differ from their accounting values;
18
EnCana Corporation 2007 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Adjustments for changes to tax rates and other tax legislation, which have an impact on future income tax obligations;
The non-taxable half of Canadian capital gains or losses; and
Items where the income tax treatment is different from the accounting treatment.
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.
NET CAPITAL INVESTMENT
Capital Summary
($ millions) |
|
2007 |
|
2006 |
|
2005 |
|
|||
|
|
|
|
|
|
|
|
|||
Canada |
|
$ |
3,330 |
|
$ |
3,352 |
|
$ |
3,702 |
|
United States |
|
1,919 |
|
2,061 |
|
1,982 |
|
|||
Other |
|
106 |
|
106 |
|
125 |
|
|||
Integrated Oil |
|
580 |
|
632 |
|
393 |
|
|||
Market Optimization |
|
6 |
|
44 |
|
197 |
|
|||
Corporate |
|
94 |
|
74 |
|
78 |
|
|||
Total Capital Investment |
|
6,035 |
|
6,269 |
|
6,477 |
|
|||
Acquisitions |
|
2,702 |
|
331 |
|
448 |
|
|||
Divestitures |
|
(481 |
) |
(689 |
) |
(2,523 |
) |
|||
Discontinued Operations |
|
- |
|
(2,647 |
) |
(305 |
) |
|||
Net Capital Investment |
|
$ |
8,256 |
|
$ |
3,264 |
|
$ |
4,097 |
|
EnCanas Total Capital Investment for the year ended December 31, 2007 was funded by Cash Flow and debt.
2007 versus 2006
Capital investment during 2007 was primarily focused on continued development of EnCanas North American key resource plays and expansion of the Companys downstream heavy oil processing capacity through its joint venture with ConocoPhillips. As disclosed in the Foreign Exchange section of this MD&A, capital expenditures were also influenced by the rise in the average U.S./Canadian dollar exchange rate and increased Total Capital Investment by $199 million.
The $164 million decrease in Canada and United States capital investment in 2007 compared to 2006 was primarily due to:
Canada capital investment of $3,330 million in 2007 decreased $22 million primarily due to:
Drilling and completion costs decreased due to increased efficiencies through the use of fit-for-purpose rigs. In addition, the Company drilled a larger number of lower cost wells in the Shallow Gas and CBM key resource plays. In Canada, the Company drilled 3,810 net wells in 2007 or 27 percent more compared to 3,001 net wells in 2006; and
Facility costs decreased $204 million or 19 percent mainly due to higher costs in 2006 resulting from the construction of the Steeprock and Kakwa gas plants at Cutbank Ridge and Bighorn, respectively.
Offsetting the decreases in capital expenditures was the rise in the average U.S./Canadian dollar exchange rate which increased Canada capital by $168 million.
U.S. capital investment decreased $142 million to $1,919 million primarily due to lower drilling and completion costs resulting from increased efficiencies through the use of additional fit-for-purpose rigs. EnCana employed an average of 22 fit-for-purpose rigs during 2007 compared to 5 during 2006. The number of net wells drilled increased slightly to 644 from 639 in 2006.
2006 versus 2005
Capital investment during 2006 was primarily focused on continued development of EnCanas North American key resource plays. Natural gas capital expenditures were focused on continued development of the Companys key resource plays in Cutbank Ridge and Bighorn in Canada and Piceance, Jonah, East Texas and Fort Worth in the U.S. Crude oil capital spending in 2006 was concentrated on expansion of the Companys steam-assisted gravity drainage (SAGD) projects located at Foster Creek and Christina Lake and developing the new resource play at Borealis.
19
EnCana Corporation 2007 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
The $32 million decrease in Canada, United States and Integrated Oil capital investment in 2006 was primarily due to:
· Canada and Integrated Oil capital investment decreased $366 million offset by an increase in foreign exchange of $255 million for a net reported decrease of $111 million. The overall decrease was due to:
· Crown land sales and other land costs were $260 million or 68 percent lower than the prior year mainly due to large land purchases in 2005;
· Drilling and completion costs decreased $307 million or 13 percent due to a decrease in the total number of wells drilled compared to 2005;
· Facility costs increased $199 million or 16 percent mainly due to the costs resulting from the continued expansion of Foster Creek and Christina Lake facilities and the construction of the Steeprock and Kakwa gas plants at Cutbank Ridge and Bighorn, respectively;
· In Canada, the Company drilled 3,009 net wells (Canada 3,001; Integrated Oil 8) in 2006 compared to 4,038 net wells (Canada 3,999; Integrated Oil 39) in 2005. The decrease resulted from the Companys decision to decrease drilling activity in response to higher industry costs and new regulations related to CBM water well testing, which delayed drilling. In various locations, the Company redirected capital spending to recompletion and tie-in of existing wells instead of drilling new wells in the current price environment.
· U.S. capital investment increased $79 million to $2,061 million primarily due to additional drilling and completion costs at Fort Worth related to the development of the Barnett Shale play, increased activity at Jonah after receipt of the Bureau of Land Management Record of Decision approving further development of the field and the drilling of several deep gas wells in the Deep Bossier play in East Texas. The number of net wells drilled increased slightly to 639 from 617 in 2005.
Integrated Oil Capital Investment
Capital investment during 2007 was primarily focused on continued development of the Foster Creek and Christina Lake resource plays and on capacity maintenance and bitumen expansion projects at the Wood River and Borger refineries.
Market Optimization Capital Investment
Expenditures in 2006 and 2005 were mostly focused on the completion of construction for the Entrega Pipeline prior to the sale in February 2006.
Corporate Capital Investment
Corporate capital investment in 2007 and 2006 included land purchases and costs related to the development of a Calgary office complex. On February 9, 2007, EnCana announced that it had completed the next phase in the development of The Bow office project with the sale of certain project assets and entered into a 25 year lease agreement with a third party developer. In addition, capital investment has been directed to business information systems and leasehold improvements.
Acquisitions, Divestitures and Discontinued Operations
Acquisitions in 2007 included the purchase of interests in the Deep Bossier play in East Texas. EnCana acquired all of the Deep Bossier natural gas and land interests of privately owned Leor Energy group in East Texas for approximately $2.55 billion before closing adjustments, increasing EnCanas interest to 100 percent in these lands. Acquisitions in 2006 were comprised of minor property acquisitions.
Divestitures in 2007 primarily included the sale of assets in Australia, assets in the Mackenzie Delta and Beaufort Sea, interests in Chad and The Bow office project assets. In 2006, divestitures included the sale of interests in the Chinook heavy oil discovery offshore Brazil and the Entrega Pipeline in Colorado.
Included in Discontinued Operations in 2006 is the divestiture of EnCanas Ecuador assets and gas storage business (discussed in Note 5 to the Consolidated Financial Statements) with the proceeds reduced by capital spending prior to the sale.
20
EnCana Corporation 2007 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Proved Oil and Gas Reserves |
Proved Reserves by Country
|
|
Natural Gas |
|
Crude Oil and NGLs(1) |
|
||||||||
Constant Prices After Royalties |
|
(billions of cubic feet) |
|
(millions of barrels) |
|
||||||||
As at December 31 |
|
2007 |
|
2006 |
|
2005 |
|
2007 |
|
2006 |
|
2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada(2) |
|
7,292 |
|
7,028 |
|
6,517 |
|
868.9 |
|
1,079.4 |
|
932.5 |
|
United States |
|
6,008 |
|
5,390 |
|
5,267 |
|
58.3 |
|
54.0 |
|
53.1 |
|
Ecuador |
|
- |
|
- |
|
- |
|
- |
|
- |
|
135.0 |
|
Total |
|
13,300 |
|
12,418 |
|
11,784 |
|
927.2 |
|
1,133.4 |
|
1,120.6 |
|
(1) Crude Oil and NGLs include condensate.
(2) Includes Foster Creek/Christina Lake.
Each year, EnCana engages independent qualified reserves evaluators to prepare reports on 100 percent of the Companys oil and natural gas reserves. The Company has a Reserves Committee of independent Board members, which reviews the qualifications and appointment of the independent qualified reserves evaluators. The Committee also reviews the procedures for providing information to the evaluators. EnCanas disclosure of reserves data is covered by National Instrument 51-101 (NI 51-101) of the Canadian Securities Administrators as amended by a Mutual Reliance Review System Decision Document dated December 16, 2003 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 (FASB) reserves reporting requirements. These standards require that reserves be estimated employing the single day field price of the commodity at the effective date of the valuation - in this case, December 31, 2007.
Proved Reserves Reconciliation by Country
|
|
Natural Gas |
|
Crude Oil and NGLs(1) |
|
||||||||
Constant Prices After Royalties |
|
(billions of cubic feet) |
|
(millions of barrels) |
|
||||||||
As at December 31, 2007 |
|
Canada |
|
United States |
|
Total |
|
Canada(2) |
|
United States |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year |
|
7,028 |
|
5,390 |
|
12,418 |
|
1,079.4 |
|
54.0 |
|
1,133.4 |
|
FCCL Partnership contribution(2) |
|
- |
|
- |
|
- |
|
(398.0 |
) |
- |
|
(398.0 |
) |
Effective Jan 2, 2007 |
|
7,028 |
|
5,390 |
|
12,418 |
|
681.4 |
|
54.0 |
|
735.4 |
|
Revisions and improved recovery |
|
87 |
|
78 |
|
165 |
|
75.5 |
|
3.6 |
|
79.1 |
|
Extensions and discoveries |
|
949 |
|
827 |
|
1,776 |
|
155.8 |
|
5.9 |
|
161.7 |
|
Acquisitions |
|
63 |
|
211 |
|
274 |
|
0.2 |
|
- |
|
0.2 |
|
Divestitures |
|
(24 |
) |
(7 |
) |
(31 |
) |
(0.2 |
) |
- |
|
(0.2 |
) |
Production |
|
(811 |
) |
(491 |
) |
(1,302 |
) |
(43.8 |
) |
(5.2 |
) |
(49.0 |
) |
End of year |
|
7,292 |
|
6,008 |
|
13,300 |
|
868.9 |
|
58.3 |
|
927.2 |
|
(1) Crude Oil and NGLs include condensate.
(2) Effective January 2, 2007, the Companys Foster Creek and Christina Lake operations were contributed to a 50/50 upstream partnership with ConocoPhillips. The Companys ownership in reserves associated with these properties was reduced by 398 million barrels.
Natural Gas
EnCanas proved natural gas reserves at December 31, 2007 totaled 13,300 Bcf. Approximately 170 percent of production was replaced by reserves additions during 2007. Extensions and discoveries resulting from successful exploration and development capital programs amounted to 1,776 Bcf. Positive revisions of 165 Bcf were 1 percent of natural gas reserves at the beginning of 2007. In Canada, positive revisions of 87 Bcf (or 1 percent of the opening balance) were largely associated with the Cutbank Ridge and Shallow Gas key resource plays. Upward revisions in the U.S. amounted to 78 Bcf (or 1 percent of the opening balance), mainly due to better performance in the Jonah key resource play. In total, EnCanas key resource plays accounted for over 80 percent of extensions and discoveries. Acquisitions net of divestitures account for approximately 2 percent of the opening natural gas reserves balance. The Leor transaction accounted for 75 percent of additions via acquisitions in 2007.
Crude Oil and NGLs
EnCanas proved crude oil and NGLs reserves at December 31, 2007 totaled 927 MMbbls. Approximately 490 percent of production was replaced by reserves additions during 2007, post the contribution to the FCCL Partnership. Extensions and discoveries amounted to 162 MMbbls, while revisions were positive 79 MMbbls (or 7 percent of the opening balance). Christina Lake accounted for approximately 140 MMbbls or more than 85 percent of extensions and discoveries. Foster Creek accounted for approximately 60 MMbbls or 75 percent of positive revisions, due to an expanded resource base. Reserves changes due to acquisitions and divestitures in continuing operations during 2007 were not significant. With the creation of the integrated oil business, effective January 2, 2007, ConocoPhillips and EnCana each own a 50 percent interest in the Foster Creek and Christina Lake upstream operations and the Wood
21
EnCana Corporation 2007 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
River and Borger refineries. As a result of this transaction, the Companys estimated proved oil reserves were reduced by 398 MMbbls.
EnCana continues to evaluate the impact of the Alberta Governments new Alberta Royalty Framework on the Companys proved oil and gas reserves.
Discontinued Operations |
In keeping with EnCanas North American resource play and refining operations strategy, the Company has made a number of divestitures over the years that are accounted for as discontinued operations. EnCanas 2007 Net Earnings from Discontinued Operations were $75 million (2006 $601 million; 2005 $597 million).
Midstream
The $75 million gain on discontinuance in 2007 is the result of an expired obligation included in the December 2005 sale of the Companys Midstream NGLs processing operations. The obligation provided potential market price support, which was not used for the facilities and was accrued for in 2005.
During 2006, EnCana completed, in two separate transactions with a single purchaser, the sale of its natural gas storage operations in Canada and the U.S. Total proceeds received were approximately $1.5 billion and an after-tax gain on sale of $829 million was recorded.
On December 13, 2005, EnCana completed the sale of its NGLs processing operations for proceeds of $625 million and recorded an after-tax gain on sale of $370 million.
Ecuador
On February 28, 2006, EnCana completed the sale of its Ecuador operations for proceeds of $1.4 billion before indemnifications. A loss of $279 million, including the impact of indemnifications, was recorded.
EnCana agreed to indemnify the purchaser of its Ecuador interests against losses that may arise in certain circumstances which are defined in the share sale agreements. The obligation to indemnify will arise should losses exceed amounts specified in the sale agreements and is limited to maximum amounts which are set forth in the share sale agreements.
During the second quarter of 2006, the Government of Ecuador seized the Block 15 assets, in relation to which EnCana previously held a 40 percent economic interest, from the operator which is an event requiring indemnification under the terms of EnCanas sale agreement with the purchaser. The purchaser requested payment and EnCana paid the maximum amount calculated in accordance with the terms of the agreements, approximately $265 million. EnCana does not expect that any further significant indemnification payments relating to any other business matters addressed in the share sale agreements will be required to be made to the purchaser.
Amounts recorded as DD&A in 2006 and 2005 represent provisions that were recorded against the net book value of the Ecuador operations to recognize Managements best estimate of the difference between the selling price and the underlying accounting value of the related investments, as required by Canadian GAAP.
Additional information on discontinued operations can be found in Note 5 to the Consolidated Financial Statements.
Liquidity and Capital Resources |
($ millions) |
|
2007 |
|
2006 |
|
2005 |
|
|||
Net cash provided by (used in) |
|
|
|
|
|
|
|
|||
Operating activities |
|
$ |
8,429 |
|
$ |
7,973 |
|
$ |
7,430 |
|
Investing activities |
|
(8,175 |
) |
(3,382 |
) |
(4,520 |
) |
|||
Financing activities |
|
(119 |
) |
(4,294 |
) |
(3,396 |
) |
|||
Foreign exchange gain (loss) on cash and cash equivalents held in foreign currency |
|
16 |
|
- |
|
(2 |
) |
|||
Increase (decrease) in cash and cash equivalents |
|
$ |
151 |
|
$ |
297 |
|
$ |
(488 |
) |
22
EnCana Corporation 2007 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Operating Activities
Cash Flow from Continuing Operations was $8,453 million in 2007 compared to $7,043 million in 2006. Reasons for this increase are discussed under the Cash Flow section of this MD&A.
Investing Activities
Net cash used for investing activities in 2007 increased $4,793 million compared to 2006. The 2006 investing activities include proceeds received from divestitures of the Ecuador assets ($1.4 billion) and the gas storage business ($1.5 billion). Capital expenditures, including property acquisitions, in 2007 increased $2,137 million compared to 2006 primarily due to the Deep Bossier acquisition, offsetting otherwise lower capital expenditures.
Financing Activities
Net issuance of long-term debt in 2007 was $2,333 million compared to net issuance of $61 million in 2006. EnCanas debt adjusted for working capital (net debt) was $10,726 million as at December 31, 2007 compared with $6,566 million as at December 31, 2006. EnCana maintains numerous capital resources including committed bank credit facilities and shelf prospectuses.
On March 12, 2007, EnCana completed a public offering in Canada of senior unsecured medium term notes in the aggregate principal amount of C$500 million. The notes have a coupon rate of 4.3 percent and mature on March 12, 2012. The net proceeds of the offering were used to repay a portion of EnCanas existing bank and commercial paper indebtedness.
On May 24, 2007, EnCana filed 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. The shelf prospectus replaces EnCanas C$1.0 billion shelf prospectus which was fully drawn.
On August 13, 2007, EnCana completed a public offering in the U.S. of senior unsecured notes in the aggregate principal amount of $500 million. The notes have a coupon rate of 6.625 percent and mature on August 15, 2037. The net proceeds of the offering were used to repay a portion of EnCanas existing bank and commercial paper indebtedness.
On December 4, 2007, EnCana completed a public offering in the U.S. of senior unsecured notes in the aggregate principal amount of $1.5 billion in two series. The first series of $700 million have a coupon rate of 5.90 percent and mature on December 1, 2017. The second series of $800 million have a coupon rate of 6.50 percent and mature on February 1, 2038. The net proceeds of the offering were used to repay a portion of the credit facilities used to acquire the Deep Bossier natural gas and land interests in East Texas.
As at December 31, 2007, EnCana had available unused committed bank credit facilities in the amount of $3.2 billion and unused capacity under shelf prospectuses, the availability of which is dependent on market conditions, for up to $4.0 billion.
Subsequent to year end, on January 18, 2008, EnCana completed a public offering in Canada of senior unsecured medium term notes in the aggregate principal amount of C$750 million. The notes have a coupon rate of 5.80 percent and mature on January 18, 2018. The net proceeds of the offering were used to repay a portion of EnCanas existing bank and commercial paper indebtedness.
EnCana maintains investment grade credit ratings on its senior unsecured debt. Standard & Poors Ratings Service has assigned a rating of A- with a Stable outlook, DBRS Limited has assigned a rating of A(low) with a Stable trend and Moodys Investors Service has assigned a rating of Baa2 with a Positive outlook.
EnCana has obtained regulatory approval under Canadian securities laws to purchase Common Shares under six consecutive NCIBs. During 2007, EnCana purchased 38.9 million of its Common Shares for total consideration of $2,025 million compared with 85.6 million Common Shares for total consideration of $4,219 million in 2006. As of December 31, 2007, the number of Common Shares that EnCana will be permitted to purchase in 2008 under the current NCIB is 75.1 million. During January 2008, EnCana purchased 3.0 million Common Shares under the NCIB for total consideration of $191 million.
EnCana pays quarterly dividends to shareholders at the discretion of the Board of Directors. EnCana doubled its quarterly dividend to 20 cents per share in the first quarter of 2007 and payments for 2007 totaled $603 million compared with $304 million in 2006. These dividends were funded by Cash Flow. Consistent with the Companys focus on shareholder value creation, EnCanas Board of Directors intends to double the quarterly dividend in 2008 to $0.40 per share. On February 13, 2008, the Companys Board of Directors declared a dividend for the first quarter of 2008 in the amount of $0.40 per share.
23
EnCana Corporation 2007 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Financial Metrics
|
|
2007 |
|
2006 |
|
2005 |
|
|
|
|
|
|
|
|
|
Net Debt to Capitalization (1) |
|
34% |
|
27% |
|
33% |
|
Net Debt to Adjusted EBITDA (2) |
|
1.2x |
|
0.6x |
|
1.1x |
|
(1) Net Debt is a non-GAAP measure defined as Long-Term Debt plus Current Liabilities less Current Assets. Capitalization is a non-GAAP measure defined as Net Debt plus Shareholders Equity.
(2) Adjusted EBITDA is a non-GAAP measure defined as Net Earnings from Continuing Operations before gain on divestitures, income taxes, foreign exchange gains or losses, interest net, accretion of asset retirement obligation, and depreciation, depletion and amortization.
Net Debt to Capitalization and Net Debt to Adjusted EBITDA are two ratios Management uses to steward the Companys overall debt position as measures of the Companys overall financial strength. The Net Debt to Capitalization ratio is higher compared to December 31, 2006 as a result of higher net debt primarily due to the Deep Bossier acquisition.
Free Cash Flow
EnCanas 2007 Free Cash Flow increased $1,526 million compared to 2006, which resulted from a combination of increased total Cash Flow and reduced total capital investment.
($ millions) |
|
2007 |
|
2006 |
|
2005 |
|
|||
|
|
|
|
|
|
|
|
|||
Cash Flow (1) |
|
$ |
8,453 |
|
$ |
7,161 |
|
$ |
7,426 |
|
Total Capital Investment |
|
6,035 |
|
6,269 |
|
6,477 |
|
|||
Free Cash Flow (2) |
|
$ |
2,418 |
|
$ |
892 |
|
$ |
949 |
|
(1) Cash Flow is a non-GAAP measure and is defined under the Cash Flow section of this MD&A.
(2) Free Cash Flow is a non-GAAP measure that EnCana defines as Cash Flow in excess of Total Capital Investment and is used by Management to determine the funds available for other investing and/or financing activities.
Outstanding Share Data
(millions) |
|
2007 |
|
2006 |
|
2005 |
|
Common Shares outstanding, beginning of year |
|
777.9 |
|
854.9 |
|
900.6 |
|
Common Shares issued under option plans |
|
8.3 |
|
8.6 |
|
15.0 |
|
Common Shares purchased |
|
(36.0 |
) |
(85.6 |
) |
(60.7 |
) |
Common Shares outstanding, end of year |
|
750.2 |
|
777.9 |
|
854.9 |
|
Weighted average Common Shares outstanding diluted |
|
764.6 |
|
836.5 |
|
889.2 |
|
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. There were no Preferred Shares outstanding as at December 31, 2007 and 2006.
Employees and directors have been granted options to purchase Common Shares under various plans. At December 31, 2007, approximately 3.4 million options without Tandem Share Appreciation Rights (TSAR) attached were outstanding, all of which are exercisable.
Long-term incentives may be granted to EnCana employees in the form of stock options and Performance Share Units (PSUs). Stock options granted after December 31, 2003 have an associated TSAR attached and employees may elect to exercise either the stock option or the associated Share Appreciation Right (SAR). Stock option exercises result in the issuance of new Common Shares while TSAR exercises result in cash payments by the Company. PSUs will not result in the issuance of new Common Shares by the Company as shares are purchased through a trust for payment, should performance considerations be met. In 2007, vesting provisions for the PSUs granted in 2004 were met and the Company distributed 2.9 million shares from the trust. At December 31, 2007, there were approximately 2.6 million shares held in trust for distribution upon vesting of outstanding PSUs.
24
EnCana Corporation 2007 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Contractual Obligations and Contingencies |
Contractual Obligations (1)
|
|
Expected Payment Date |
|
|||||||||||||
($ millions) |
|
2008 |
|
2009 to 2010 |
|
2011 to 2012 |
|
2013+ |
|
Total |
|
|||||
Long-Term Debt (2) |
|
$ |
703 |
|
$ |
450 |
|
$ |
3,007 |
|
$ |
5,400 |
|
$ |
9,560 |
|
Partnership Contribution Payable(3) |
|
288 |
|
631 |
|
711 |
|
1,821 |
|
3,451 |
|
|||||
Asset Retirement Obligation |
|
166 |
|
62 |
|
73 |
|
7,094 |
|
7,395 |
|
|||||
Pipeline Transportation |
|
527 |
|
933 |
|
902 |
|
2,222 |
|
4,584 |
|
|||||
Purchase of Goods and Services |
|
404 |
|
387 |
|
252 |
|
621 |
|
1,664 |
|
|||||
Product Purchases |
|
24 |
|
48 |
|
23 |
|
98 |
|
193 |
|
|||||
Operating Leases (4) |
|
70 |
|
152 |
|
419 |
|
3,402 |
|
4,043 |
|
|||||
Capital Commitments |
|
54 |
|
13 |
|
133 |
|
39 |
|
239 |
|
|||||
Other Long-Term Commitments |
|
18 |
|
16 |
|
3 |
|
1 |
|
38 |
|
|||||
Total |
|
$ |
2,254 |
|
$ |
2,692 |
|
$ |
5,523 |
|
$ |
20,698 |
|
$ |
31,167 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Product Sales |
|
$ |
51 |
|
$ |
96 |
|
$ |
106 |
|
$ |
244 |
|
$ |
497 |
|
Partnership Contribution Receivable(3) |
|
297 |
|
643 |
|
713 |
|
1,791 |
|
3,444 |
|
(1) In addition, the Company has made commitments related to its risk management program. See Note 18 to the Consolidated Financial Statements. The Company has an obligation to fund its Pension Plan and Other Post-Employment Benefits as disclosed in Note 17 to the Consolidated Financial Statements.
(2) Principal component only. See Note 14 to the Consolidated Financial Statements.
(3) Principal component only. See Note 10 to the Consolidated Financial Statements.
(4) Related to office space.
EnCana has entered into various commitments primarily related to debt, demand charges on firm transportation agreements, capital commitments and marketing agreements.
Included in EnCanas total long-term debt commitments of $9,560 million at December 31, 2007 are $2,001 million in commitments related to Bankers Acceptances, Commercial Paper and LIBOR loans. These amounts are fully supported and Management expects that they will continue to be supported by revolving credit and term loan facilities that have no repayment requirements within the next year. Further details regarding EnCanas long-term debt are described in Note 14 to the Consolidated Financial Statements.
As at December 31, 2007, EnCana remained a party to long-term, fixed price, physical contracts with a current delivery of approximately 38 MMcf/d, with varying terms and volumes through 2017. The total volume to be delivered within the terms of these contracts is 111 Bcf at a weighted average price of $4.42 per Mcf. At December 31, 2007, these transactions had an unrealized loss of $309 million.
Leases
In the normal course of business, EnCana leases office space for personnel who support field operations and for corporate purposes.
Deep Panuke
In October 2007, EnCana received regulatory approval from the Canada-Nova Scotia Offshore Petroleum Board to develop the Deep Panuke natural gas project located about 175 kilometres offshore Nova Scotia. Expected to start production in 2010, the $700 million project is expected to deliver between 200 MMcf/d and 300 MMcf/d to markets in Canada and the northeast U.S.
In late November 2007, EnCana signed a Letter of Agreement pertaining to the Production Facility Center (PFC) for the Deep Panuke project. The agreement is for Single Buoy Moorings to construct a production facility that EnCana will lease upon delivery, expected in late 2010. EnCana also has the option to purchase the facility. EnCana has determined that it has substantially all the construction period risk and consequently is reporting the PFC as an asset under construction during the construction period. Once in service, the asset will be classified as a capital lease.
The Bow
On February 9, 2007, EnCana announced that it had completed the next phase in the development of The Bow office project with the sale of project assets and has entered into a 25 year lease agreement with a third party developer. Cost of design changes to the building requested by EnCana and leasehold improvements will be the responsibility of the Company.
25
EnCana Corporation 2007 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Variable Interest Entities (VIEs)
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 holds the majority of the assets in trust for the Company in anticipation of a qualifying like kind exchange for U.S. tax purposes. Pursuant to the agreement with Brown Kilgore, EnCana operates the properties, receives all of the revenue and pays all of the expenses associated with the properties. The arrangement with Brown Kilgore will be complete on May 18, 2008 and the assets will be transferred to EnCana at that time. EnCana has determined that the relationship with Brown Kilgore represents an interest in a VIE and that EnCana is the primary beneficiary of the VIE. EnCana has consolidated Brown Kilgore from the date of acquisition.
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. The lawsuits allege that the defendants engaged in a conspiracy with unnamed competitors in the natural gas markets in California in violation of U.S. and California anti-trust and unfair competition laws.
Without admitting any liability in the lawsuits, WD agreed to settle all of the class action lawsuits in both state and federal court, for payment, of $20.5 million and $2.4 million, respectively. Also, as previously disclosed, without admitting any liability whatsoever, WD concluded settlements with the U.S. Commodity Futures Trading Commission (CFTC) for $20 million and of a previously disclosed consolidated class action lawsuit in the United States District Court in New York for $8.2 million.
The remaining lawsuits were commenced by individual plaintiffs, one of which is E. & J. Gallo Winery (Gallo). The Gallo lawsuit claims damages in excess of $30 million. The other remaining lawsuits do not specify the precise amount of damages claimed. California law allows for the possibility that the amount of damages assessed could be tripled.
The Company and WD intend to vigorously defend against the outstanding claims; however, the Company cannot predict the outcome of these proceedings or any future proceedings against the Company, whether these proceedings would lead to monetary damages which could have a material adverse effect on the Companys financial position, or whether there will be other proceedings arising out of these allegations.
Accounting Policies and Estimates |
Changes in Accounting Policies and Practices
On January 1, 2007, the Company adopted the CICA Handbook Section 1530 Comprehensive Income, Section 3251 Equity, Section 3855 Financial Instruments Recognition and Measurement, and Section 3865 Hedges. As required by the new standards, prior periods have not been restated, except to reclassify the foreign currency translation adjustment balance as described under Comprehensive Income.
The adoption of these standards has had no material impact on the Companys net earnings or cash flows. The other effects of the implementation of the new standards are discussed below.
Comprehensive Income
The new standards introduce comprehensive income, which consists of net earnings and other comprehensive income (OCI). The Companys Consolidated Financial Statements now include a Statement of Comprehensive Income, which includes the components of comprehensive income. For EnCana, OCI is currently comprised of the changes in the foreign currency translation adjustment balance.
The cumulative changes in OCI are included in accumulated other comprehensive income (AOCI), which is presented as a new category within shareholders equity in the Consolidated Balance Sheet. The accumulated foreign currency translation adjustment, formerly presented as a separate category within shareholders equity, is now included in AOCI. The Companys Consolidated Financial Statements now include a Statement of Accumulated Other Comprehensive Income, which provides the continuity of the AOCI balance.
The adoption of comprehensive income has been made in accordance with the applicable transitional provisions. Accordingly, the December 31, 2007 period end accumulated foreign currency translation adjustment balance of $3,063 million is now included in AOCI (2006 $1,375 million; 2005 $1,262). In addition, the change in the accumulated foreign currency translation adjustment balance for the year ended December 31, 2007 of $1,688 million is now included in OCI in the Statement of Comprehensive Income (2006 $113 million; 2005 $226).
26
EnCana Corporation 2007 Annual Report |
Managements Discussion and Analysis (prepared in US$) |
Financial Instruments
The financial instruments standard establishes the recognition and measurement criteria for financial assets, financial liabilities and derivatives. EnCanas accounting policies for financial instruments are described in Note 1 to the Consolidated Financial Statements.
The adoption of the financial instruments standard has been made in accordance with its transitional provisions. Accordingly, at January 1, 2007, $52 million of other assets were reclassified to long-term debt to reflect the adopted policy of capitalizing long-term debt transaction costs, premiums and discounts within long-term debt. The costs capitalized within long-term debt will be amortized using the effective interest method. Previously, the Company deferred these costs within other assets and amortized them straight-line over the life of the related long-term debt. The adoption of the effective interest method of amortization had no effect on opening retained earnings.
Recent Accounting Pronouncements
The Company has assessed new and revised accounting pronouncements that have been issued that are not yet effective and determined that the following may have an impact on the Company:
· As of January 1, 2008, EnCana will be required to adopt the CICA Handbook Section 3031 Inventories, which will replace the existing inventories standard. The new standard requires inventory to be valued on a first-in, first-out or weighted average basis, which is consistent with EnCanas current treatment. The adoption of this standard should not have a material impact on EnCanas Consolidated Financial Statements.
· As of January 1, 2008, EnCana will be required to adopt two new CICA standards, Section 3862 Financial Instruments Disclosures and Section 3863 Financial Instruments Presentation, which will replace Section 3861 Financial Instruments Disclosure and Presentation. The new disclosure standard will increase EnCanas disclosure regarding the risks associated with financial instruments and how those risks are managed.
· As of January 1, 2008, EnCana will be required to adopt CICA Handbook Section 1535 Capital Disclosures, which will require EnCana to disclose its objectives, policies and processes for managing capital.
· In January 2006, the CICA Accounting Standards Board (AcSB) adopted a strategic plan for the direction of accounting standards in Canada. As part of that plan, accounting standards in Canada for public companies are expected to converge with International Financial Reporting Standards (IFRSs). In March 2007, the AcSB released an Implementation Plan for Incorporating IFRSs into Canadian GAAP, which assumes a convergence date of January 1, 2011. Following a progress review, the AcSB is expected to confirm this date by March 31, 2008. The Company continues to monitor and assess the impact of convergence of Canadian GAAP and IFRS.
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
EnCana follows the CICA guideline on full cost accounting in the oil and gas industry to account for oil and gas properties. Under this method, all costs including internal costs and asset retirement costs, directly associated with the acquisition of, exploration for and development of natural gas and crude oil reserves are capitalized on a country-by-country cost centre basis and costs associated with production are expensed. The capitalized costs, including estimated future development costs, are depreciated, depleted and amortized using the unit-of-production method based on estimated proved reserves. Reserves estimates can have a significant impact on earnings, as they are a key component in the calculation of DD&A. A downward revision in reserves estimate could result in a higher DD&A charge to earnings. In addition, if net capitalized costs are determined to be in excess of the calculated ceiling, which is based largely on reserves estimates (see asset impairment discussion below), the excess must be written off as an expense charged against earnings. In the event of a property divestiture, proceeds are normally deducted from the full cost pool without recognition of a gain or loss unless there is a change in the DD&A rate of 20 percent or greater.
Oil and Gas Reserves
All of EnCanas oil and gas reserves 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.
Asset Impairments
Under full cost accounting, a ceiling test is performed to ensure that unamortized capitalized costs in each cost centre do not exceed their fair value. An impairment loss is recognized in net earnings when the carrying amount of a cost centre is not recoverable and the
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carrying amount of the cost centre exceeds its fair value. The carrying amount of the cost centre is not recoverable if the carrying amount exceeds the sum of the undiscounted cash flows from proved reserves. If the sum of the cash flows is less than the carrying amount, the impairment loss is limited to an 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.
An impairment loss is recognized on refining property, plant and equipment when the carrying amount is not recoverable and exceeds its fair value. 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 discounted future cash flows from the refinery asset.
Asset Retirement Obligations
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, natural gas processing plants, and refining facilities. These obligations also include items for which the Company has made promissory estoppel. The asset retirement cost, equal to the initially estimated fair value of the asset retirement obligation, is capitalized as part of the cost of the related long-lived asset. 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. Amounts recorded for asset retirement obligations are based on estimates of reserves and on retirement costs, which will not be incurred for several years. Actual payments to settle the obligations may differ from estimated amounts.
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. Goodwill was allocated to the business segments based on their respective book values compared to fair values. If it is determined that the fair value of the assets and liabilities of the business segment is less than the book value of the business segment at the time of assessment, an impairment amount is determined by deducting the fair value from the book value and applying it against the book balance of goodwill. The offset is charged to the Consolidated Statement of Earnings as additional DD&A.
Derivative Financial Instruments
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.
The Company enters into financial transactions to help reduce its exposure to price fluctuations with respect to commodity purchase and sale transactions to achieve targeted investment returns and growth objectives, while maintaining prescribed financial metrics. These transactions generally are swaps, collars, or options and are generally entered into with major financial institutions or commodities trading institutions.
EnCana may also use derivative financial instruments, such as interest rate swap agreements, to manage the fixed and floating interest rate mix of its total debt portfolio and related overall cost of borrowing. The interest rate swap agreements involve the periodic exchange of payments, without the exchange of the normal principal amount upon which the payments are based, and are recorded as an adjustment of interest expense on the hedged debt instrument.
EnCana may enter into hedges of its foreign currency exposures on foreign currency denominated long-term debt by entering into offsetting forward exchange contracts. Foreign exchange translation gains and losses on these instruments are accrued under other current, or non-current, assets or liabilities on the balance sheet and recognized in foreign exchange in the period to which they relate, offsetting the respective translation losses and gains recognized on the underlying foreign currency long-term debt. Premiums or discounts on these forward instruments are amortized as an adjustment of interest expense over the term of the contract.
EnCana also may purchase foreign exchange forward contracts to hedge anticipated sales to customers in the United States. Foreign exchange translation gains and losses on these instruments are recognized as an adjustment of the revenues when the sale is recorded.
Derivative instruments that do not qualify as hedges, or are not designated as hedges, are recorded using the mark-to-market method of accounting 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 the Companys natural gas and crude oil financial derivatives 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 reporting period. The estimate of fair value of all derivative instruments is based on quoted market prices or, in their absence, third party market indicators. In 2005, 2006, and 2007, the Company elected not to designate any of its current price risk management activities as accounting hedges and, accordingly, accounts for all derivatives using the mark-to-market accounting method.
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Pensions and Other Post-Employment Benefits
EnCana accrues for its obligations under its employee benefit plans and the related costs, net of plan assets.
The cost of pensions and other 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 obligation is discounted using a market interest rate at the beginning of the year on high quality corporate debt instruments.
Pension expense 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. The amortization period covers the expected average remaining service lives of employees covered by the plans.
Pension expense for the defined contribution pension plans is recorded as the benefits are earned by the employees covered by the plan. Pension costs are a component of compensation costs.
Performance Share Units and Performance Tandem Share Appreciation Rights
The PSU and Performance TSAR plans provide for a range of payouts, based on EnCanas performance relative to certain peers or key predetermined performance measures. EnCana expenses the cost of PSUs and Performance TSARs based on expected payouts; however, the amounts to be paid, if any, may vary from the current estimate. Further details on these plans are disclosed in Note 17 to the Consolidated Financial Statements.
Risk Management |
EnCanas results are affected by:
· financial risks (including commodity price, foreign exchange, interest rate and credit risks);
· operational risks;
· environmental, health, safety and security risks; and
· reputational risks.
EnCana takes a proactive approach in the identification and management of risks that can affect the Company.
FINANCIAL RISKS
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. As a means of mitigating exposure to commodity price risk volatility, the Company has entered into various financial instrument agreements. The details of these instruments, including any unrealized gains or losses, as of December 31, 2007, are disclosed in Note 18 to the Consolidated Financial Statements.
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.
Commodity Price
To partially mitigate the natural gas commodity price risk, the Company enters 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.
EnCana has also entered into contracts to purchase and sell natural gas as part of its daily ongoing operations of the Companys proprietary production management. Physical contracts associated with this activity had an unrecognized gain of $12 million at December 31, 2007.
For crude oil price risk, the Company has partially mitigated its exposure to the WTI NYMEX price for approximately 17 percent of its expected 2008 oil production with fixed price swaps and put options.
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To manage its electricity consumption costs, EnCana has entered into two derivative contracts for a term of 11 years, commencing January 1, 2007.
Foreign Exchange
As a means of mitigating the exposure to fluctuations in the U.S. to Canadian dollar exchange rate, EnCana may enter into foreign exchange contracts. The Company also enters into foreign exchange contracts in conjunction with crude oil marketing transactions. 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.
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 has entered into cross currency swaps on a portion of its debt as a means of managing the U.S./Canadian dollar debt mix.
Interest Rates
The Company partially mitigates its exposure to interest rate changes by maintaining a mix of both fixed and floating rate debt. EnCana has entered into interest rate swap transactions from time to time as an additional means of managing the fixed/floating rate debt portfolio mix.
Credit Risk
EnCana is exposed to credit related losses in the event of default by counterparties. 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. A substantial portion of EnCanas accounts receivable is with customers in the oil and gas industry.
OPERATIONAL RISKS
EnCana mitigates operational risk through a number of policies and processes. 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 process called Lookback and Learning. In this process, each asset team undertakes a thorough review of their 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 Lookback 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.
EnCana also partially mitigates operational risks by maintaining a comprehensive insurance program.
Alberta Royalty Framework
On October 25, 2007, the Alberta Government announced a new Alberta Royalty Framework (ARF). The ARF establishes new royalties for conventional oil, natural gas and bitumen that are linked to price and production levels and apply to both new and existing conventional oil and gas activities and oil sands projects. The changes introduced by the ARF are to be effective January 1, 2009.
The significant changes to the royalty regime require new legislation, changes to existing legislation and regulation and development of proprietary software by the Alberta Government to support the calculation and collection of royalties. Additionally, certain proposed changes contemplate further public and/or industry consultation. There may be modifications introduced to the ARF prior to the implementation thereof.
ENVIRONMENT, HEALTH, SAFETY AND SECURITY RISKS
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 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 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 strategies are utilized to restore the environment.
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.
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Climate Change
A number of federal, provincial and state governments have announced intentions to regulate greenhouse gases (GHG) and other air pollutants, and it is anticipated that other jurisdictions will announce emissions reduction plans in the future.
The Canadian Federal Government has announced its intention to regulate greenhouse gases and other air pollutants. It is currently developing a framework that outlines its clean air and climate change action plan, including a target to reduce GHG emissions by 20 percent by 2020, and a commitment to regulate industry on an emissions intensity basis in the short term. Currently there are few technical details regarding the implementation of the governments plan, but they have made a commitment to work with industry to develop the specifics.
In March 2007, the Alberta Government amended the Climate Change and Emissions Management Act (CCEMA) requiring facilities that emit more than 100,000 tonnes of GHG per year to reduce their emissions intensity by 12 percent from a regulated baseline starting on July 1, 2007. The companies that operate these facilities have options to comply with this requirement including making operating improvements, buying offsets to apply against their emission total or making contributions at C$15/tonne to an Alberta Climate Change and Emissions Management Fund. EnCana has submitted its baseline data for the covered facilities per the regulation and will be submitting its first compliance report by March 31, 2008. This requirement is not expected to have a material impact.
On February 13, 2007 British Columbia announced a target to reduce provincial greenhouse gas emissions by 33 percent below current levels by 2020 and enacted this target into law through the Greenhouse Gas Reduction Targets Act released on November 20, 2007. EnCana is monitoring these developments and is in the process of working with the province on the emerging regulations.
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 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.
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:
· our significant weighting in natural gas;
· our recognition as an industry leader in CO2 sequestration;
· our focus on energy efficiency and the development of technology to reduce GHG emissions;
· our involvement in the creation of industry best practices; and
· our industry leading steam to oil ratio, which translates directly into lower emissions intensity.
EnCanas strategy for addressing the implications of emerging carbon regulations is proactive and is comprised of three principal elements:
1. 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, attention to fuel consumption, and a focus on minimizing our steam to oil ratio help to support and drive our focus on cost reduction.
2. Respond to Price Signals
As regulatory regimes for GHGs develop in the jurisdictions where we work inevitably price signals begin to emerge. We have initiated an Energy Efficiency Initiative in an effort to improve the energy efficiency of our 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, where appropriate, EnCana is also attempting to realize the associated value of its reduction projects.
3. 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 we gain useful knowledge that allows us to explore different strategies for managing our emissions and costs. These scenarios inform our long range planning and our analyses on the implications of regulatory trends.
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 our website at www.encana.com.
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REPUTATIONAL RISKS
EnCana takes a proactive approach to the identification and management of issues that affect the Companys reputation and has established consistent and clear procedures, guidelines and responsibility for identifying and managing these issues. Issues affecting, or with the potential to affect, EnCanas reputation are generally either emerging issues that can be identified early and then managed or unforeseen issues that arise unexpectedly and must be managed on an urgent basis.
Outlook |
EnCana plans to continue to focus principally on growing natural gas and crude oil production from unconventional resource plays in North America and on developing its high quality in-situ oil resources and expanding the Companys downstream heavy oil processing capacity through its joint venture with ConocoPhillips.
Volatility in crude oil prices is expected to continue throughout 2008 as a result of market uncertainties over supply and refining disruptions, continued demand growth in China, OPEC actions, demand destruction from high energy prices and the overall state of the world economies. Canadian crude prices will face added uncertainty due to the risk of refinery disruptions in an already tight U.S. Midwest market and growing domestic production could result in pipeline constraints out of Western Canada.
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 North American conventional gas supply has peaked and that unconventional resource plays can offset conventional gas production declines over the next few years. Past this period, the industrys ability to continue to grow gas supply is expected to be challenged in North America by land access and regulatory issues.
The Company expects its 2008 capital investment program to be funded from Cash Flow and debt.
EnCanas results are affected by external market 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 EnCanas 2008 results is available in the Corporate Guidance on our website at www.encana.com. EnCanas news release dated February 14, 2008 and financial statements are available on www.sedar.com.
Advisories |
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 MD&A 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 MD&A include, but are not limited to, statements with respect to: the potential impact of implementation of the Alberta Royalty Framework on EnCanas financial condition and projected 2008 capital investments; the expected timing of, and closing of, the sale of the Companys interests in Brazil; projections with respect to growth of natural gas production from unconventional resource plays and in-situ oil resources; the expansion of the Companys downstream heavy oil processing capacity; the projected impact of land access and regulatory issues; projections relating to the volatility of crude oil prices in 2008 and beyond and the reasons therefor; the Companys projected capital investment levels for 2008 and the source of funding therefor; the effect of the Companys risk management program, including the impact of derivative financial instruments; the Companys defence of lawsuits; the impact of the climate change initiatives on operating costs; the impact of Western Canada pipeline constraints and potential refinery disruptions on future Canadian crude oil prices; projections that the Companys Bankers Acceptances and Commercial Paper Program will continue to be fully supported by committed credit facilities and term loan facilities; and projections relating to North American conventional natural gas supplies and the ability of unconventional resource plays to offset future conventional gas production declines over the next few years. 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, bitumen, 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 oil and gas reserves; the ability of the Company and
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ConocoPhillips to successfully manage and operate the North American integrated heavy oil business and the ability of the parties to obtain necessary regulatory approvals; refining and marketing margins; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; potential failure of new products to achieve acceptance in the market; unexpected cost increases or technical difficulties in constructing or modifying manufacturing or refining facilities; unexpected difficulties in manufacturing, transporting or refining synthetic crude oil; risks associated with technology; the 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 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 international 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. Statements relating to reserves or resources or resource potential are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the resources and reserves described exist in the quantities predicted or estimated, and can be profitably produced in the future. 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 MD&A are made as of the date of this MD&A, 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 MD&A are expressly qualified by this cautionary statement.
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 which permits it to provide such disclosure in accordance with U.S. disclosure requirements. The information provided by EnCana may differ from the corresponding information prepared in accordance with Canadian disclosure standards under 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.
Crude Oil, NGLs and Natural Gas Conversions
In this MD&A, 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 and Estimated Ultimate Recovery
EnCana uses the terms resource play and estimated ultimate recovery. 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. As used by EnCana, estimated ultimate recovery (EUR) has the meaning set out jointly by the Society of Petroleum Engineers and World Petroleum Congress in the year 2000, being those quantities of petroleum which are estimated, on a given date, to be potentially recoverable from an accumulation, plus those quantities already produced therefrom.
CURRENCY, NON-GAAP MEASURES AND REFERENCES TO ENCANA
All information included in this MD&A and the Consolidated Financial Statements and comparative information is shown on a U.S. dollar, after-royalties basis unless otherwise noted. Sales forecasts reflect the mid-point of current public guidance on an after royalties basis. Current Corporate Guidance assumes a U.S. dollar exchange rate of $1.00 for every Canadian dollar.
Non-GAAP Measures
Certain measures in this MD&A do not have any standardized meaning as prescribed by Canadian GAAP such as Cash Flow from Continuing Operations, Cash Flow, Cash Flow per share diluted, Free Cash Flow, Operating Earnings and Operating Earnings per share diluted, Operating Earnings from Continuing Operations and Adjusted EBITDA and therefore are considered non-GAAP measures. Therefore, these measures may not be comparable to similar measures presented by other issuers. These measures have been described and presented in this MD&A in order to provide shareholders and potential investors with additional information regarding the Companys liquidity and its ability to generate funds to finance its operations. Managements use of these measures has been disclosed further in this MD&A as these measures are discussed and presented.
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References to EnCana
For convenience, references in this MD&A to EnCana, the Company, we, us and our may, where applicable, refer only to or include any relevant direct and indirect subsidiary corporations and partnerships (Subsidiaries) of EnCana Corporation, and the assets, activities and initiatives of such Subsidiaries.
ADDITIONAL INFORMATION
Further information regarding EnCana Corporation can be accessed under the Companys public filings found at www.sedar.com and on the Companys website at www.encana.com.
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EnCana Corporation
CONSOLIDATED
FINANCIAL
STATEMENTS
Prepared in US$
For the Year Ended December 31, 2007
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 effectiveness of the Companys internal control over financial reporting as at December 31, 2007. 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 effective 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, 2007, as stated in their Auditors Report. PricewaterhouseCoopers LLP has provided such opinions.
(signed) |
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(signed) |
Randall K. Eresman |
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Brian C. Ferguson |
President & |
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Executive Vice-President & |
Chief Executive Officer |
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Chief Financial Officer |
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February 21, 2008 |
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1
Auditors Report
To the Shareholders of EnCana Corporation
We have completed integrated audits of the consolidated financial statements and internal control over financial reporting of EnCana Corporation as of December 31, 2007 and 2006 and an audit of its 2005 consolidated financial statements. 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, 2007 and December 31, 2006, and the related consolidated statements of earnings, retained earnings, comprehensive income, accumulated other comprehensive income, and cash flows for each of the years in the three year period ended December 31, 2007. 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 as at December 31, 2007 and December 31, 2006 and for each of the years then ended in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). We conducted our audit of the Companys financial statements for the year ended December 31, 2005 in accordance with Canadian generally accepted auditing standards. 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, 2007 and December 31, 2006 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2007 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 of December 31, 2007, 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 effectiveness of 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 generally accepted accounting principles. A companys internal control over financial reporting includes those policies and procedures that (i) pertain to the
2
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 of December 31, 2007 based on criteria established in Internal Control Integrated Framework issued by the COSO.
(signed)
PricewaterhouseCoopers LLP
Chartered Accountants
Calgary, Alberta
Canada
February 21, 2008
3
EnCana Corporation
Consolidated Statement of Earnings
For the years ended December 31 (US$ millions, except per share amounts) |
|
|
|
2007 |
|
2006 |
|
2005 |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Revenues, Net of Royalties |
|
(Note 4 |
) |
|
|
|
|
|
|
|||
Upstream |
|
|
|
$ |
11,758 |
|
$ |
10,369 |
|
$ |
10,218 |
|
Integrated Oil |
|
|
|
7,983 |
|
973 |
|
554 |
|
|||
Market Optimization |
|
|
|
2,944 |
|
3,007 |
|
4,267 |
|
|||
Corporate Unrealized gain (loss) on risk management |
|
(Note 18 |
) |
(1,239 |
) |
2,050 |
|
(466 |
) |
|||
|
|
|
|
21,446 |
|
16,399 |
|
14,573 |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Expenses |
|
(Note 4 |
) |
|
|
|
|
|
|
|||
Production and mineral taxes |
|
|
|
291 |
|
349 |
|
453 |
|
|||
Transportation and selling |
|
|
|
1,010 |
|
1,070 |
|
845 |
|
|||
Operating |
|
|
|
2,278 |
|
1,655 |
|
1,438 |
|
|||
Purchased product |
|
|
|
8,583 |
|
2,862 |
|
4,159 |
|
|||
Depreciation, depletion and amortization |
|
|
|
3,816 |
|
3,112 |
|
2,769 |
|
|||
Administrative |
|
|
|
384 |
|
271 |
|
268 |
|
|||
Interest, net |
|
(Note 7 |
) |
428 |
|
396 |
|
524 |
|
|||
Accretion of asset retirement obligation |
|
(Note 15 |
) |
64 |
|
50 |
|
37 |
|
|||
Foreign exchange (gain) loss, net |
|
(Note 8 |
) |
(164 |
) |
14 |
|
(24 |
) |
|||
Stock-based compensation options |
|
(Note 16 |
) |
- |
|
- |
|
15 |
|
|||
(Gain) loss on divestitures |
|
(Note 6 |
) |
(65 |
) |
(323 |
) |
- |
|
|||
|
|
|
|
16,625 |
|
9,456 |
|
10,484 |
|
|||
Net Earnings Before Income Tax |
|
|
|
4,821 |
|
6,943 |
|
4,089 |
|
|||
Income tax expense |
|
(Note 9 |
) |
937 |
|
1,892 |
|
1,260 |
|
|||
Net Earnings From Continuing Operations |
|
|
|
3,884 |
|
5,051 |
|
2,829 |
|
|||
Net Earnings From Discontinued Operations |
|
(Note 5 |
) |
75 |
|
601 |
|
597 |
|
|||
Net Earnings |
|
|
|
$ |
3,959 |
|
$ |
5,652 |
|
$ |
3,426 |
|
|
|
|
|
|
|
|
|
|
|
|||
Net Earnings From Continuing Operations per Common Share |
|
(Note 19 |
) |
|
|
|
|
|
|
|||
Basic |
|
|
|
$ |
5.13 |
|
$ |
6.16 |
|
$ |
3.26 |
|
Diluted |
|
|
|
$ |
5.08 |
|
$ |
6.04 |
|
$ |
3.18 |
|
|
|
|
|
|
|
|
|
|
|
|||
Net Earnings per Common Share |
|
(Note 19 |
) |
|
|
|
|
|
|
|||
Basic |
|
|
|
$ |
5.23 |
|
$ |
6.89 |
|
$ |
3.95 |
|
Diluted |
|
|
|
$ |
5.18 |
|
$ |
6.76 |
|
$ |
3.85 |
|
See accompanying Notes to Consolidated Financial Statements
4
EnCana Corporation
Consolidated Statement of Retained Earnings
For the years ended December 31 (US$ millions) |
|
|
|
2007 |
|
2006 |
|
2005 |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Retained Earnings, Beginning of Year |
|
|
|
$ |
11,344 |
|
$ |
9,481 |
|
$ |
7,935 |
|
Net Earnings |
|
|
|
3,959 |
|
5,652 |
|
3,426 |
|
|||
Dividends on Common Shares |
|
|
|
(603 |
) |
(304 |
) |
(238 |
) |
|||
Charges for Normal Course Issuer Bid |
|
(Note 16 |
) |
(1,618 |
) |
(3,485 |
) |
(1,642 |
) |
|||
Retained Earnings, End of Year |
|
|
|
$ |
13,082 |
|
$ |
11,344 |
|
$ |
9,481 |
|
Consolidated Statement of Comprehensive Income
For the years ended December 31 (US$ millions) |
|
|
|
2007 |
|
2006 |
|
2005 |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Net Earnings |
|
|
|
$ |
3,959 |
|
$ |
5,652 |
|
$ |
3,426 |
|
Other Comprehensive Income, Net of Tax |
|
|
|
|
|
|
|
|
|
|||
Foreign Currency Translation Adjustment |
|
|
|
1,688 |
|
113 |
|
226 |
|
|||
Comprehensive Income |
|
|
|
$ |
5,647 |
|
$ |
5,765 |
|
$ |
3,652 |
|
Consolidated Statement of Accumulated Other Comprehensive Income
For the years ended December 31 (US$ millions) |
|
|
|
2007 |
|
2006 |
|
2005 |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Accumulated Other Comprehensive Income, Beginning of Year |
|
|
|
$ |
1,375 |
|
$ |
1,262 |
|
$ |
1,036 |
|
Foreign Currency Translation Adjustment |
|
|
|
1,688 |
|
113 |
|
226 |
|
|||
Accumulated Other Comprehensive Income, End of Year |
|
|
|
$ |
3,063 |
|
$ |
1,375 |
|
$ |
1,262 |
|
See accompanying Notes to Consolidated Financial Statements
5
EnCana Corporation
Consolidated Balance Sheet
As at December 31 (US$ millions) |
|
|
|
|
|
2007 |
|
2006 |
|
||
|
|
|
|
|
|
|
|
|
|
||
Assets |
|
|
|
|
|
|
|
|
|
||
Current Assets |
|
|
|
|
|
|
|
|
|
||
Cash and cash equivalents |
|
|
|
|
|
$ |
553 |
|
$ |
402 |
|
Accounts receivable and accrued revenues |
|
|
|
|
|
2,381 |
|
1,721 |
|
||
Current portion of partnership contribution receivable |
|
|
|
(Notes 3, 10 |
) |
297 |
|
- |
|
||
Risk management |
|
|
|
(Note 18 |
) |
385 |
|
1,403 |
|
||
Inventories |
|
|
|
(Note 11 |
) |
828 |
|
176 |
|
||
|
|
|
|
|
|
4,444 |
|
3,702 |
|
||
|
|
|
|
|
|
|
|
|
|
||
Property, Plant and Equipment, net |
|
|
|
(Notes 4, 12 |
) |
35,865 |
|
28,213 |
|
||
Investments and Other Assets |
|
|
|
(Note 13 |
) |
607 |
|
533 |
|
||
Partnership Contribution Receivable |
|
|
|
(Notes 3, 10 |
) |
3,147 |
|
- |
|
||
Risk Management |
|
|
|
(Note 18 |
) |
18 |
|
133 |
|
||
Goodwill |
|
|
|
(Note 4 |
) |
2,893 |
|
2,525 |
|
||
|
|
|
|
(Note 4 |
) |
$ |
46,974 |
|
$ |
35,106 |
|
|
|
|
|
|
|
|
|
|
|
||
Liabilities and Shareholders Equity |
|
|
|
|
|
|
|
|
|
||
Current Liabilities |
|
|
|
|
|
|
|
|
|
||
Accounts payable and accrued liabilities |
|
|
|
|
|
$ |
3,982 |
|
$ |
2,494 |
|
Income tax payable |
|
|
|
|
|
1,150 |
|
926 |
|
||
Current portion of partnership contribution payable |
|
|
|
(Notes 3, 10 |
) |
288 |
|
- |
|
||
Risk management |
|
|
|
(Note 18 |
) |
207 |
|
14 |
|
||
Current portion of long-term debt |
|
|
|
(Note 14 |
) |
703 |
|
257 |
|
||
|
|
|
|
|
|
6,330 |
|
3,691 |
|
||
|
|
|
|
|
|
|
|
|
|
||
Long-Term Debt |
|
|
|
(Note 14 |
) |
8,840 |
|
6,577 |
|
||
Other Liabilities |
|
|
|
|
|
242 |
|
79 |
|
||
Partnership Contribution Payable |
|
|
|
(Notes 3, 10 |
) |
3,163 |
|
- |
|
||
Risk Management |
|
|
|
(Note 18 |
) |
29 |
|
2 |
|
||
Asset Retirement Obligation |
|
|
|
(Note 15 |
) |
1,458 |
|
1,051 |
|
||
Future Income Taxes |
|
|
|
(Note 9 |
) |
6,208 |
|
6,240 |
|
||
|
|
|
|
|
|
26,270 |
|
17,640 |
|
||
Commitments and Contingencies |
|
|
|
(Note 20 |
) |
|
|
|
|
||
|
|
|
|
|
|
|
|
|
|
||
Shareholders Equity |
|
|
|
|
|
|
|
|
|
||
Share capital |
|
|
|
(Note 16 |
) |
4,479 |
|
4,587 |
|
||
Paid in surplus |
|
|
|
(Note 16 |
) |
80 |
|
160 |
|
||
Retained earnings |
|
|
|
|
|
13,082 |
|
11,344 |
|
||
Accumulated other comprehensive income |
|
|
|
|
|
3,063 |
|
1,375 |
|
||
Total Shareholders Equity |
|
|
|
|
|
20,704 |
|
17,466 |
|
||
|
|
|
|
|
|
$ |
46,974 |
|
$ |
35,106 |
|
See accompanying Notes to Consolidated Financial Statements
Approved by the Board
(signed) |
|
(signed) |
David P. OBrien |
|
Barry W. Harrison |
Director |
|
Director |
6
EnCana Corporation
Consolidated Statement of Cash Flows
For the years ended December 31 (US$ millions) |
|
|
|
2007 |
|
2006 |
|
2005 |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Operating Activities |
|
|
|
|
|
|
|
|
|
|||
Net earnings from continuing operations |
|
|
|
$ |
3,884 |
|
$ |
5,051 |
|
$ |
2,829 |
|
Depreciation, depletion and amortization |
|
|
|
3,816 |
|
3,112 |
|
2,769 |
|
|||
Future income taxes |
|
(Note 9 |
) |
(617 |
) |
950 |
|
56 |
|
|||
Cash tax on sale of assets |
|
(Note 9 |
) |
- |
|
49 |
|
578 |
|
|||
Unrealized (gain) loss on risk management |
|
(Note 18 |
) |
1,235 |
|
(2,060 |
) |
469 |
|
|||
Unrealized foreign exchange (gain) loss |
|
|
|
41 |
|
- |
|
(126 |
) |
|||
Accretion of asset retirement obligation |
|
(Note 15 |
) |
64 |
|
50 |
|
37 |
|
|||
(Gain) loss on divestitures |
|
(Note 6 |
) |
(65 |
) |
(323 |
) |
- |
|
|||
Other |
|
|
|
95 |
|
214 |
|
350 |
|
|||
Cash flow from discontinued operations |
|
|
|
- |
|
118 |
|
464 |
|
|||
Net change in other assets and liabilities |
|
|
|
(16 |
) |
138 |
|
(281 |
) |
|||
Net change in non-cash working capital from continuing operations |
|
(Note 19 |
) |
(8 |
) |
3,343 |
|
497 |
|
|||
Net change in non-cash working capital from discontinued operations |
|
|
|
- |
|
(2,669 |
) |
(212 |
) |
|||
Cash From Operating Activities |
|
|
|
8,429 |
|
7,973 |
|
7,430 |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Investing Activities |
|
|
|
|
|
|
|
|
|
|||
Capital expenditures |
|
(Note 4 |
) |
(8,737 |
) |
(6,600 |
) |
(6,925 |
) |
|||
Proceeds from divestitures |
|
(Note 6 |
) |
481 |
|
689 |
|
2,523 |
|
|||
Cash tax on sale of assets |
|
(Note 9 |
) |
- |
|
(49 |
) |
(578 |
) |
|||
Net change in investments and other |
|
|
|
(5 |
) |
2 |
|
(109 |
) |
|||
Net change in non-cash working capital from continuing operations |
|
(Note 19 |
) |
86 |
|
19 |
|
330 |
|
|||
Discontinued operations |
|
|
|
- |
|
2,557 |
|
239 |
|
|||
Cash (Used in) Investing Activities |
|
|
|
(8,175 |
) |
(3,382 |
) |
(4,520 |
) |
|||
|
|
|
|
|
|
|
|
|
|
|||
Financing Activities |
|
|
|
|
|
|
|
|
|
|||
Net issuance (repayment) of revolving long-term debt |
|
|
|
181 |
|
134 |
|
(538 |
) |
|||
Issuance of long-term debt |
|
(Note 14 |
) |
2,409 |
|
- |
|
429 |
|
|||
Repayment of long-term debt |
|
(Note 14 |
) |
(257 |
) |
(73 |
) |
(1,104 |
) |
|||
Issuance of common shares |
|
(Note 16 |
) |
176 |
|
179 |
|
294 |
|
|||
Purchase of common shares |
|
(Note 16 |
) |
(2,025 |
) |
(4,219 |
) |
(2,114 |
) |
|||
Dividends on common shares |
|
|
|
(603 |
) |
(304 |
) |
(238 |
) |
|||
Other |
|
|
|
- |
|
(11 |
) |
(125 |
) |
|||
Cash (Used in) From Financing Activities |
|
|
|
(119 |
) |
(4,294 |
) |
(3,396 |
) |
|||
|
|
|
|
|
|
|
|
|
|
|||
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency |
|
|
|
16 |
|
- |
|
(2 |
) |
|||
|
|
|
|
|
|
|
|
|
|
|||
Increase (Decrease) in Cash and Cash Equivalents |
|
|
|
151 |
|
297 |
|
(488 |
) |
|||
Cash and Cash Equivalents, Beginning of Year |
|
|
|
402 |
|
105 |
|
593 |
|
|||
Cash and Cash Equivalents, End of Year |
|
|
|
$ |
553 |
|
$ |
402 |
|
$ |
105 |
|
|
|
|
|
|
|
|
|
|
|
|||
Supplemental Cash Flow Information |
|
(Note 19 |
) |
|
|
|
|
|
|
See accompanying Notes to Consolidated Financial Statements
7
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, 2007
NOTE 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 exploration for, production and marketing of natural gas, crude oil and natural gas liquids (NGLs), refining operations and power generation operations.
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. Information prepared in accordance with generally accepted accounting principles in the United States is included in Note 22.
Investments in jointly controlled partnerships and unincorporated joint ventures carry on EnCanas exploration, production and crude oil refining businesses and are accounted for using the proportionate consolidation method, whereby EnCanas proportionate share of revenues, expenses, assets and liabilities are included in the accounts.
Investments in companies and partnerships in which EnCana does not have direct or joint control over the strategic operating, investing and financing decisions, but does have significant influence on them, are accounted for using the equity method.
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.
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 generally accepted accounting principles 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 and costs, and the
8
related future cash flows are subject to measurement uncertainty, and the impact in the Consolidated Financial Statements of future periods could be material.
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.
The amount of compensation expense accrued for long-term performance-based compensation arrangements are subject to managements best estimate of whether or not the performance criteria will be met and what the ultimate payout will be.
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.
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. Natural gas and crude oil produced and sold by EnCana below or above its working interest share in the related resource properties results in production underliftings or overliftings. Underliftings are recorded as inventory and overliftings are recorded as deferred revenue. Realized gains and losses from the 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 inventory with the same counterparty that are entered into in contemplation of each other are recorded on a net basis. Revenues associated with the services provided where EnCana acts as agent are recorded as the services are provided. Revenues associated with the sale of natural gas storage services are recognized when the services are provided. Sales of electric power are recognized when power is provided to the customer.
Unrealized gains and losses from the 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 retirement and 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 obligation is discounted using a market interest rate at the beginning of the year on high quality corporate debt instruments.
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
9
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.
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 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, including petroleum and chemical products, are valued at the lower of average cost and net realizable value on a first-in, first-out 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, exploration for, and the development of natural gas and crude oil reserves, are capitalized on a country-by-country cost centre basis.
Costs accumulated within each cost centre are depreciated, depleted and amortized using the unit-of-production method based on estimated proved reserves determined using estimated future prices and costs. For purposes of this calculation, oil is converted to gas on an energy equivalent basis. Capitalized costs subject to depletion include estimated future costs to be incurred in developing proved reserves. Proceeds from the divestiture of properties are normally deducted from the full cost pool without recognition of gain or loss unless that deduction would result in a change to the rate of depreciation, depletion and amortization of 20 percent or greater, in which case a gain or loss is recorded. Costs of major development projects and costs of acquiring and evaluating significant unproved properties are excluded, on a cost centre basis, from the costs subject to depletion until it is determined whether or not proved reserves are attributable to the properties, or impairment has occurred. Costs that have been impaired are included in the costs subject to depreciation, depletion and amortization.
10
An impairment loss is recognized in net earnings when the carrying amount of a cost centre is not recoverable and the carrying amount of the cost centre exceeds its fair value. The carrying amount of the cost centre is not recoverable if the carrying amount exceeds the sum of the undiscounted cash flows from proved reserves. If the sum of the cash flows is less than the carrying amount, the impairment loss is limited to the amount by which the carrying amount exceeds the sum of:
i. the fair value of proved and probable reserves; and
ii. the costs of unproved properties that have been subject to a separate impairment test.
Downstream
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 and exceeds its fair value. 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 discounted future cash flows from the refinery asset.
Market Optimization
Midstream facilities, including natural gas storage facilities, natural gas liquids extraction plant facilities and power generation facilities, are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets, which range from 20 to 25 years. Capital assets related to pipelines are carried at cost and depreciated 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
Amortization of deferred items included in Investments and Other Assets is provided for 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. Goodwill and all other assets and liabilities have been allocated to business levels, within the Companys segments, 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
11
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.
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, natural gas processing plants, and refining facilities. These obligations also include items for which the Company has made promissory estoppel. The asset retirement cost, equal to the initially estimated fair value of the asset retirement obligation, is capitalized as part of the cost of the related long-lived asset. Changes in the estimated obligation resulting from revisions to estimated timing or amount of undiscounted cash flows are recognized as a change 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
EnCana records compensation expense in the Consolidated Financial Statements for stock options that do not have tandem share appreciation rights attached to them granted to employees and directors using the fair value method. Fair values are determined using the Black-Scholes-Merton option-pricing model. Compensation costs are recognized over the vesting period.
Obligations for payments, cash or common shares, under the Companys share appreciation rights, stock options with tandem share appreciation rights attached, deferred share units and performance share units plans are accrued as compensation expense over the vesting period. Fluctuations in the price of EnCanas common shares change the accrued compensation expense and are recognized when they occur.
R) Financial Instruments
On January 1, 2007, the Company adopted the CICA Handbook Section 3855, Financial Instruments Recognition and Measurement (See Note 2).
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 are designated as held-for-trading and are measured at fair value. Accounts receivable and accrued revenues and the partnership contribution receivable are designated as loans and receivables. Accounts payable and accrued liabilities, the partnership contribution payable and long-term debt are designated as other financial liabilities. 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.
12
Derivative Financial Instruments
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 using the mark-to-market method of accounting 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
The Company has assessed new and revised accounting pronouncements that have been issued that are not yet effective and determined that the following may have an impact on the Company:
· As of January 1, 2008, EnCana will be required to adopt the CICA Handbook Section 3031, Inventories, which will replace the existing inventories standard. The new standard requires inventory to be valued on a first-in, first-out or weighted average basis, which is consistent with EnCanas current treatment. The adoption of this standard should not have a material impact on EnCanas Consolidated Financial Statements.
· As of January 1, 2008, EnCana will be required to adopt two new CICA standards, Section 3862, Financial Instruments Disclosures and Section 3863, Financial Instruments Presentation, which will replace Section 3861, Financial Instruments Disclosure and Presentation. The new disclosure standard will increase EnCanas disclosure regarding the risks associated with financial instruments and how those risks are managed.
· As of January 1, 2008, EnCana will be required to adopt CICA Handbook Section 1535, Capital Disclosures, which will require EnCana to disclose its objectives, policies and processes for managing capital.
· In January 2006, the CICA Accounting Standards Board (AcSB) adopted a strategic plan for the direction of accounting standards in Canada. As part of that plan, accounting standards in Canada for public companies are expected to converge with International Financial Reporting Standards (IFRSs). In March 2007, the AcSB released an Implementation Plan for Incorporating IFRSs into Canadian GAAP, which assumes a convergence date of January 1, 2011. Following a progress review, the AcSB is expected to confirm this date by March 31, 2008. The Company continues to monitor and assess the impact of convergence of Canadian GAAP and IFRS.
13
T) Reclassification
Certain information provided for prior years has been reclassified to conform to the presentation adopted in 2007.
NOTE 2. Changes in Accounting Policies and Practices
On January 1, 2007, the Company adopted the CICA Handbook Section 1530, Comprehensive Income, Section 3251, Equity, Section 3855, Financial Instruments Recognition and Measurement, and Section 3865, Hedges. As required by the new standards, prior periods have not been restated, except to reclassify the foreign currency translation adjustment balance as described under Comprehensive Income.
The adoption of these standards has had no material impact on the Companys net earnings or cash flows. The other effects of the implementation of the new standards are discussed below.
Comprehensive Income
The new standards introduce comprehensive income, which consists of net earnings and OCI. The Companys Consolidated Financial Statements now include a Statement of Comprehensive Income, which includes the components of comprehensive income. For EnCana, OCI is currently comprised of the changes in the foreign currency translation adjustment balance.
The cumulative changes in OCI are included in AOCI, which is presented as a new category within shareholders equity in the Consolidated Balance Sheet. The accumulated foreign currency translation adjustment, formerly presented as a separate category within shareholders equity, is now included in AOCI. The Companys Consolidated Financial Statements now include a Statement of Accumulated Other Comprehensive Income, which provides the continuity of the AOCI balance.
The adoption of comprehensive income has been made in accordance with the applicable transitional provisions. Accordingly, the December 31, 2007 period end accumulated foreign currency translation adjustment balance of $3,063 million is now included in AOCI (2006 $1,375 million; 2005 $1,262 million). In addition, the change in the accumulated foreign currency translation adjustment balance for the year ended December 31, 2007 of $1,688 million is now included in OCI in the Statement of Comprehensive Income (2006 $113 million; 2005 $226 million).
Financial Instruments
The financial instruments standard establishes the recognition and measurement criteria for financial assets, financial liabilities and derivatives. EnCanas accounting policies for financial instruments are described in Note 1.
The adoption of the financial instruments standard has been made in accordance with its transitional provisions. Accordingly, at January 1, 2007, $52 million of other assets were reclassified to long-term debt to reflect the adopted policy of capitalizing long-term debt transaction costs, premiums and discounts within long-term debt. The costs capitalized within long-term debt will be amortized using the effective interest method. Previously, the Company deferred these costs within other assets and amortized them straight-line over the life of the related long-term debt. The adoption of the effective interest method of amortization had no effect on opening retained earnings.
NOTE 3. Joint Venture with ConocoPhillips
On January 2, 2007, EnCana became a 50 percent partner in an integrated, North American oil business with ConocoPhillips which consists 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
14
billion and EnCana contributed a note payable of $7.5 billion. Further information about these notes is included in Note 10.
In accordance with Canadian generally accepted accounting principles, these entities have been accounted for using the proportionate consolidation method with the results of operations shown in a separate business segment, Integrated Oil (See Note 4).
NOTE 4. Segmented Information
The Company has defined its continuing operations into the following segments:
· Canada, United States and Other includes the Companys upstream exploration for, and development and production of natural gas, crude oil and natural gas liquids and other related activities. The majority of the Companys upstream operations are located in Canada and the United States. Offshore and international exploration is mainly focused on opportunities in Atlantic Canada, the Middle East and Europe.
· Integrated Oil is focused on two lines of business: the exploration for, and development and production of bitumen in Canada using in-situ recovery methods; and the refining of crude oil into petroleum and chemical products located in the United States. This segment represents EnCanas 50 percent interest in the joint venture with ConocoPhillips.
· Market Optimization is conducted by the Midstream & Marketing division. The Marketing groups primary responsibility is the sale of the Companys proprietary production. The results are included in the Canada, United States and Integrated Oil segments. Correspondingly, the Marketing groups also undertake market optimization activities which comprise third-party purchases and sales of product that provide operational flexibility for transportation commitments, product type, delivery points and customer diversification. These activities are reflected in the Market Optimization segment.
· Corporate includes unrealized gains or losses recorded on derivative financial instruments. Once amounts are settled, the realized gains and losses are recorded in the operating segment to which the derivative instrument relates.
Market Optimization markets substantially all of the Companys upstream production to third-party customers. Transactions between business segments are based on market values and eliminated on consolidation. The tables in this note present financial information on an after eliminations basis.
In 2007, as a result of the joint venture with ConocoPhillips, EnCana redefined its business segments to those described above. All prior periods have been restated to conform with the current presentation.
Operations that have been discontinued are disclosed in Note 5.
15
Results of Continuing Operations
|
|
Upstream |
|
|||||||||||||||||||||||||
|
|
Canada |
|
United States |
|
Other |
|
|||||||||||||||||||||
For the years ended December 31 |
|
2007 |
|
2006 |
|
2005 |
|
2007 |
|
2006 |
|
2005 |
|
2007 |
|
2006 |
|
2005 |
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Revenues, Net of Royalties |
|
$ |
7,316 |
|
$ |
6,970 |
|
$ |
6,783 |
|
$ |
4,074 |
|
$ |
3,121 |
|
$ |
3,177 |
|
$ |
368 |
|
$ |
278 |
|
$ |
258 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Production and mineral taxes |
|
102 |
|
116 |
|
104 |
|
189 |
|
233 |
|
349 |
|
- |
|
- |
|
- |
|
|||||||||
Transportation and selling |
|
327 |
|
330 |
|
300 |
|
307 |
|
248 |
|
182 |
|
- |
|
- |
|
- |
|
|||||||||
Operating |
|
1,010 |
|
866 |
|
727 |
|
323 |
|
283 |
|
212 |
|
315 |
|
235 |
|
246 |
|
|||||||||
Purchased product |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
|||||||||
Depreciation, depletion and amortization |
|
2,171 |
|
1,989 |
|
1,815 |
|
1,158 |
|
848 |
|
682 |
|
94 |
|
31 |
|
75 |
|
|||||||||
Segment Income (Loss) |
|
$ |
3,706 |
|
$ |
3,669 |
|
$ |
3,837 |
|
$ |
2,097 |
|
$ |
1,509 |
|
$ |
1,752 |
|
$ |
(41 |
) |
$ |
12 |
|
$ |
(63 |
) |
|
|
Total Upstream |
|
Integrated Oil |
|
Market Optimization |
|
|||||||||||||||||||||
|
|
2007 |
|
2006 |
|
2005 |
|
2007 |
|
2006 |
|
2005 |
|
2007 |
|
2006 |
|
2005 |
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Revenues, Net of Royalties |
|
$ |
11,758 |
|
$ |
10,369 |
|
$ |
10,218 |
|
$ |
7,983 |
|
$ |
973 |
|
$ |
554 |
|
$ |
2,944 |
|
$ |
3,007 |
|
$ |
4,267 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Production and mineral taxes |
|
291 |
|
349 |
|
453 |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
|||||||||
Transportation and selling |
|
634 |
|
578 |
|
482 |
|
366 |
|
476 |
|
350 |
|
10 |
|
16 |
|
13 |
|
|||||||||
Operating |
|
1,648 |
|
1,384 |
|
1,185 |
|
598 |
|
221 |
|
166 |
|
37 |
|
62 |
|
85 |
|
|||||||||
Purchased product |
|
- |
|
- |
|
- |
|
5,725 |
|
- |
|
- |
|
2,858 |
|
2,862 |
|
4,159 |
|
|||||||||
Depreciation, depletion and amortization |
|
3,423 |
|
2,868 |
|
2,572 |
|
284 |
|
157 |
|
116 |
|
17 |
|
12 |
|
8 |
|
|||||||||
Segment Income (Loss) |
|
$ |
5,762 |
|
$ |
5,190 |
|
$ |
5,526 |
|
$ |
1,010 |
|
$ |
119 |
|
$ |
(78 |
) |
$ |
22 |
|
$ |
55 |
|
$ |
2 |
|
|
|
Corporate |
|
Consolidated |
|
||||||||||||||
|
|
2007 |
|
2006 |
|
2005 |
|
2007 |
|
2006 |
|
2005 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Revenues, Net of Royalties |
|
$ |
(1,239 |
) |
$ |
2,050 |
|
$ |
(466 |
) |
$ |
21,446 |
|
$ |
16,399 |
|
$ |
14,573 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Production and mineral taxes |
|
- |
|
- |
|
- |
|
291 |
|
349 |
|
453 |
|
||||||
Transportation and selling |
|
- |
|
- |
|
- |
|
1,010 |
|
1,070 |
|
845 |
|
||||||
Operating |
|
(5 |
) |
(12 |
) |
2 |
|
2,278 |
|
1,655 |
|
1,438 |
|
||||||
Purchased product |
|
- |
|
- |
|
- |
|
8,583 |
|
2,862 |
|
4,159 |
|
||||||
Depreciation, depletion and amortization |
|
92 |
|
75 |
|
73 |
|
3,816 |
|
3,112 |
|
2,769 |
|
||||||
Segment Income (Loss) |
|
$ |
(1,326 |
) |
$ |
1,987 |
|
$ |
(541 |
) |
5,468 |
|
7,351 |
|
4,909 |
|
|||
Administrative |
|
|
|
|
|
|
|
384 |
|
271 |
|
268 |
|
||||||
Interest, net |
|
|
|
|
|
|
|
428 |
|
396 |
|
524 |
|
||||||
Accretion of asset retirement obligation |
|
|
|
|
|
|
|
64 |
|
50 |
|
37 |
|
||||||
Foreign exchange (gain) loss, net |
|
|
|
|
|
|
|
(164 |
) |
14 |
|
(24 |
) |
||||||
Stock-based compensation options |
|
|
|
|
|
|
|
- |
|
- |
|
15 |
|
||||||
(Gain) loss on divestitures |
|
|
|
|
|
|
|
(65 |
) |
(323 |
) |
- |
|
||||||
|
|
|
|
|
|
|
|
647 |
|
408 |
|
820 |
|
||||||
Net Earnings Before Income Tax |
|
|
|
|
|
|
|
4,821 |
|
6,943 |
|
4,089 |
|
||||||
Income tax expense |
|
|
|
|
|
|
|
937 |
|
1,892 |
|
1,260 |
|
||||||
Net Earnings From Continuing Operations |
|
|
|
|
|
|
|
$ |
3,884 |
|
$ |
5,051 |
|
$ |
2,829 |
|
16
Geographic and Product Information (Continuing Operations)
|
|
Produced Gas |
|
|||||||||||||||||||||||||
|
|
Canada |
|
United States |
|
Total |
|
|||||||||||||||||||||
For the years ended December 31 |
|
2007 |
|
2006 |
|
2005 |
|
2007 |
|
2006 |
|
2005 |
|
2007 |
|
2006 |
|
2005 |
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Revenues, Net of Royalties |
|
$ |
5,671 |
|
$ |
5,440 |
|
$ |
5,486 |
|
$ |
3,765 |
|
$ |
2,854 |
|
$ |
2,932 |
|
$ |
9,436 |
|
$ |
8,294 |
|
$ |
8,418 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
70 |
|
80 |
|
76 |
|
167 |
|
213 |
|
325 |
|
237 |
|
293 |
|
401 |
|
|||||||||
Transportation and selling |
|
285 |
|
278 |
|
283 |
|
307 |
|
248 |
|
182 |
|
592 |
|
526 |
|
465 |
|
|||||||||
Operating |
|
744 |
|
629 |
|
521 |
|
323 |
|
283 |
|
212 |
|
1,067 |
|
912 |
|
733 |
|
|||||||||
Operating Cash Flow |
|
$ |
4,572 |
|
$ |
4,453 |
|
$ |
4,606 |
|
$ |
2,968 |
|
$ |
2,110 |
|
$ |
2,213 |
|
$ |
7,540 |
|
$ |
6,563 |
|
$ |
6,819 |
|
|
|
Oil and NGLs |
|
|||||||||||||||||||||||||
|
|
Canada |
|
United States |
|
Total |
|
|||||||||||||||||||||
|
|
2007 |
|
2006 |
|
2005 |
|
2007 |
|
2006 |
|
2005 |
|
2007 |
|
2006 |
|
2005 |
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Revenues, Net of Royalties |
|
$ |
1,645 |
|
$ |
1,530 |
|
$ |
1,297 |
|
$ |
309 |
|
$ |
267 |
|
$ |
245 |
|
$ |
1,954 |
|
$ |
1,797 |
|
$ |
1,542 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
32 |
|
36 |
|
28 |
|
22 |
|
20 |
|
24 |
|
54 |
|
56 |
|
52 |
|
|||||||||
Transportation and selling |
|
42 |
|
52 |
|
17 |
|
- |
|
- |
|
- |
|
42 |
|
52 |
|
17 |
|
|||||||||
Operating |
|
266 |
|
237 |
|
206 |
|
- |
|
- |
|
- |
|
266 |
|
237 |
|
206 |
|
|||||||||
Operating Cash Flow |
|
$ |
1,305 |
|
$ |
1,205 |
|
$ |
1,046 |
|
$ |
287 |
|
$ |
247 |
|
$ |
221 |
|
$ |
1,592 |
|
$ |
1,452 |
|
$ |
1,267 |
|
|
|
Integrated Oil |
|
|||||||||||||||||||||||||
|
|
Oil |
|
Downstream Refining |
|
Other |
|
|||||||||||||||||||||
|
|
2007 |
|
2006 |
|
2005 |
|
2007 |
|
2006 |
|
2005 |
|
2007 |
|
2006 |
|
2005 |
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Revenues, Net of Royalties |
|
$ |
738 |
|
$ |
941 |
|
$ |
529 |
|
$ |
7,315 |
|
$ |
- |
|
$ |
- |
|
$ |
(70 |
) |
$ |
32 |
|
$ |
25 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Transportation and selling |
|
366 |
|
476 |
|
350 |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
|||||||||
Operating |
|
159 |
|
194 |
|
137 |
|
428 |
|
- |
|
- |
|
11 |
|
27 |
|
29 |
|
|||||||||
Purchased product |
|
- |
|
- |
|
- |
|
5,813 |
|
- |
|
- |
|
(88 |
) |
- |
|
- |
|
|||||||||
Operating Cash Flow |
|
$ |
213 |
|
$ |
271 |
|
$ |
42 |
|
$ |
1,074 |
|
$ |
- |
|
$ |
- |
|
$ |
7 |
|
$ |
5 |
|
$ |
(4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Integrated Oil |
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
2005 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Revenues, Net of Royalties |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
7,983 |
|
$ |
973 |
|
$ |
554 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Transportation and selling |
|
|
|
|
|
|
|
|
|
|
|
|
|
366 |
|
476 |
|
350 |
|
|||
Operating |
|
|
|
|
|
|
|
|
|
|
|
|
|
598 |
|
221 |
|
166 |
|
|||
Purchased product |
|
|
|
|
|
|
|
|
|
|
|
|
|
5,725 |
|
- |
|
- |
|
|||
Operating Cash Flow |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,294 |
|
$ |
276 |
|
$ |
38 |
|
17
Capital Expenditures (Continuing Operations)
For the years ended December 31 |
|
2007 |
|
2006 |
|
2005 |
|
|||
|
|
|
|
|
|
|
|
|||
Capital |
|
|
|
|
|
|
|
|||
Canada |
|
$ |
3,330 |
|
$ |
3,352 |
|
$ |
3,702 |
|
United States |
|
1,919 |
|
2,061 |
|
1,982 |
|
|||
Other |
|
106 |
|
106 |
|
125 |
|
|||
Integrated Oil |
|
580 |
|
632 |
|
393 |
|
|||
Market Optimization |
|
6 |
|
44 |
|
197 |
|
|||
Corporate |
|
94 |
|
74 |
|
78 |
|
|||
|
|
6,035 |
|
6,269 |
|
6,477 |
|
|||
|
|
|
|
|
|
|
|
|||
Acquisition Capital |
|
|
|
|
|
|
|
|||
Canada |
|
75 |
|
11 |
|
30 |
|
|||
United States |
|
2,613 |
|
284 |
|
418 |
|
|||
Other |
|
- |
|
15 |
|
- |
|
|||
Integrated Oil |
|
14 |
|
21 |
|
- |
|
|||
|
|
2,702 |
|
331 |
|
448 |
|
|||
Total |
|
$ |
8,737 |
|
$ |
6,600 |
|
$ |
6,925 |
|
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 holds the majority of the assets in trust for the Company in anticipation of a qualifying like kind exchange for U.S. tax purposes. Pursuant to the agreement with Brown Kilgore, EnCana operates the properties, receives all the revenue and pays all of the expenses associated with the properties. The arrangement with Brown Kilgore will be complete on May 18, 2008 and the assets will be transferred to EnCana at that time. EnCana has determined that the relationship with Brown Kilgore represents an interest in a Variable Interest Entity (VIE) and that EnCana is the primary beneficiary of the VIE. EnCana has consolidated Brown Kilgore from the date of acquisition.
Additions to Goodwill
There were no additions to goodwill during 2007 or 2006.
Property, Plant and Equipment and Total Assets by Segment
|
|
Property, Plant and |
|
Total Assets |
|
||||||||
As at December 31 |
|
2007 |
|
2006 |
|
2007 |
|
2006 |
|
||||
|
|
|
|
|
|
|
|
|
|
||||
Canada |
|
$ |
17,631 |
|
$ |
16,783 |
|
$ |
21,429 |
|
$ |
20,188 |
|
United States |
|
11,879 |
|
8,494 |
|
12,948 |
|
9,509 |
|
||||
Other |
|
1,104 |
|
1,182 |
|
1,135 |
|
1,224 |
|
||||
Integrated Oil |
|
4,721 |
|
1,322 |
|
9,597 |
|
1,379 |
|
||||
Market Optimization |
|
171 |
|
154 |
|
478 |
|
468 |
|
||||
Corporate |
|
359 |
|
278 |
|
1,387 |
|
2,338 |
|
||||
Total |
|
$ |
35,865 |
|
$ |
28,213 |
|
$ |
46,974 |
|
$ |
35,106 |
|
Property, Plant and Equipment, Goodwill and Total Assets by Geographic Region
|
|
Goodwill |
|
Property, Plant and |
|
Total Assets |
|
||||||||||||
As at December 31 |
|
2007 |
|
2006 |
|
2007 |
|
2006 |
|
2007 |
|
2006 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Canada |
|
$ |
2,420 |
|
$ |
2,052 |
|
$ |
20,143 |
|
$ |
19,456 |
|
$ |
28,774 |
|
$ |
25,268 |
|
United States |
|
473 |
|
473 |
|
15,585 |
|
8,494 |
|
17,963 |
|
9,481 |
|
||||||
Other Countries |
|
- |
|
- |
|
137 |
|
263 |
|
237 |
|
357 |
|
||||||
Total |
|
$ |
2,893 |
|
$ |
2,525 |
|
$ |
35,865 |
|
$ |
28,213 |
|
$ |
46,974 |
|
$ |
35,106 |
|
On February 9, 2007, EnCana announced that it had completed the next phase in the development of The Bow office project with the sale of project assets and has entered into a 25 year lease agreement with a third-party developer. Corporate Property, Plant and Equipment and Total Assets include EnCanas accrual to date of $147 million related to this office project as an asset under construction. A corresponding liability is included in Other Liabilities in the Consolidated Balance
18
Sheet. There is no effect on the Companys net earnings or cash flows related to the capitalization of The Bow office project.
Export Sales
Sales of natural gas, crude oil and NGLs produced or purchased in Canada delivered to customers outside of Canada were $1,362 million (2006 $1,814 million; 2005 $1,784 million).
Major Customers
In connection with the marketing and sale of EnCanas own and purchased natural gas, crude oil and refined products for the year ended December 31, 2007, the Company had two customers (2006 one; 2005 one) which individually accounted for more than 10 percent of its consolidated revenues, net of royalties. Sales to these customers, major international integrated energy companies with a high quality investment grade credit rating, were approximately $7,652 million (2006 $1,951 million; 2005 $2,056 million).
NOTE 5. Discontinued Operations
As EnCana has focused its continuing operations on North American Upstream and Downstream operations, a number of divestitures have been made which are accounted for as discontinued operations.
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.
During 2006, EnCana completed, in two separate transactions with a single purchaser, the sale of its natural gas storage operations in Canada and the United States. Total proceeds received were approximately $1.5 billion and an after-tax gain on sale of $829 million was recorded.
On December 13, 2005, EnCana completed the sale of its natural gas liquids processing operations for proceeds of $625 million (C$720 million) and recorded an after-tax gain on sale of $370 million.
Ecuador
On February 28, 2006, EnCana completed the sale of its Ecuador operations for proceeds of $1.4 billion before indemnifications. A loss of $279 million, including the impact of indemnifications, was recorded. Indemnifications are discussed further in this note.
Amounts recorded as depreciation, depletion and amortization in 2006 and 2005 represent provisions which were recorded against the net book value of the Ecuador operations to recognize Managements best estimate of the difference between the selling price and the underlying accounting value of the related investments, as required by Canadian generally accepted accounting principles.
United Kingdom
On December 1, 2004, EnCana completed the sale of its 100 percent interest in EnCana (U.K.) Limited, holder of its U.K. operations, for net cash consideration of approximately $2.1 billion. A gain on sale of approximately $1.4 billion was recorded.
19
Consolidated Statement of Earnings
The following tables present the effect of the discontinued operations in the Consolidated Statement of Earnings:
|
|
Midstream |
|
Ecuador |
|
United Kingdom |
|
|||||||||||||||
For the years ended December 31 |
|
2007 |
|
2006 |
|
2005 |
|
2006 |
|
2005 |
|
2006 |
|
2005 |
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Revenues, Net of Royalties* |
|
$ |
- |
|
$ |
482 |
|
$ |
1,570 |
|
$ |
200 |
|
$ |
965 |
|
$ |
- |
|
$ |
- |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Production and mineral taxes |
|
- |
|
- |
|
- |
|
23 |
|
131 |
|
- |
|
- |
|
|||||||
Transportation and selling |
|
- |
|
- |
|
9 |
|
10 |
|
58 |
|
- |
|
- |
|
|||||||
Operating |
|
- |
|
37 |
|
301 |
|
25 |
|
138 |
|
- |
|
- |
|
|||||||
Purchased product |
|
- |
|
356 |
|
1,100 |
|
- |
|
- |
|
- |
|
- |
|
|||||||
Depreciation, depletion and amortization |
|
- |
|
- |
|
28 |
|
84 |
|
234 |
|
- |
|
- |
|
|||||||
Administrative |
|
- |
|
- |
|
30 |
|
- |
|
- |
|
- |
|
- |
|
|||||||
Interest, net |
|
- |
|
- |
|
(2 |
) |
(2 |
) |
(2 |
) |
- |
|
- |
|
|||||||
Accretion of asset retirement obligation |
|
- |
|
- |
|
- |
|
- |
|
1 |
|
- |
|
- |
|
|||||||
Foreign exchange (gain) loss, net |
|
- |
|
4 |
|
(2 |
) |
1 |
|
(4 |
) |
(1 |
) |
(40 |
) |
|||||||
(Gain) loss on discontinuance |
|
(75 |
) |
(807 |
) |
(364 |
) |
279 |
|
- |
|
- |
|
- |
|
|||||||
|
|
(75 |
) |
(410 |
) |
1,100 |
|
420 |
|
556 |
|
(1 |
) |
(40 |
) |
|||||||
Net Earnings (Loss) Before Income Tax |
|
75 |
|
892 |
|
470 |
|
(220 |
) |
409 |
|
1 |
|
40 |
|
|||||||
Income tax expense (recovery) |
|
- |
|
17 |
|
39 |
|
59 |
|
278 |
|
(4 |
) |
5 |
|
|||||||
Net Earnings (Loss) From Discontinued Operations |
|
$ |
75 |
|
$ |
875 |
|
$ |
431 |
|
$ |
(279 |
) |
$ |
131 |
|
$ |
5 |
|
$ |
35 |
|
* Revenues, net of royalties in Ecuador for 2006 include realized losses of $1 million related to derivative financial instruments.
|
|
Consolidated Total |
|
|||||||
For the years ended December 31 |
|
2007 |
|
2006 |
|
2005 |
|
|||
|
|
|
|
|
|
|
|
|||
Revenues, Net of Royalties |
|
$ |
- |
|
$ |
682 |
|
$ |
2,535 |
|
Expenses |
|
|
|
|
|
|
|
|||
Production and mineral taxes |
|
- |
|
23 |
|
131 |
|
|||
Transportation and selling |
|
- |
|
10 |
|
67 |
|
|||
Operating |
|
- |
|
62 |
|
439 |
|
|||
Purchased product |
|
- |
|
356 |
|
1,100 |
|
|||
Depreciation, depletion and amortization |
|
- |
|
84 |
|
262 |
|
|||
Administrative |
|
- |
|
- |
|
30 |
|
|||
Interest, net |
|
- |
|
(2 |
) |
(4 |
) |
|||
Accretion of asset retirement obligation |
|
- |
|
- |
|
1 |
|
|||
Foreign exchange (gain) loss, net |
|
- |
|
4 |
|
(46 |
) |
|||
(Gain) loss on discontinuance |
|
(75 |
) |
(528 |
) |
(364 |
) |
|||
|
|
(75 |
) |
9 |
|
1,616 |
|
|||
Net Earnings (Loss) Before Income Tax |
|
75 |
|
673 |
|
919 |
|
|||
Income tax expense (recovery) |
|
- |
|
72 |
|
322 |
|
|||
Net Earnings (Loss) From Discontinued Operations |
|
$ |
75 |
|
$ |
601 |
|
$ |
597 |
|
|
|
|
|
|
|
|
|
|||
Net Earnings (Loss) From Discontinued Operations per Common Share |
|
|
|
|
|
|
|
|||
Basic |
|
$ |
0.10 |
|
$ |
0.73 |
|
$ |
0.69 |
|
Diluted |
|
$ |
0.10 |
|
$ |
0.72 |
|
$ |
0.67 |
|
There were no assets and liabilities related to discontinued operations as at December 31, 2007.
Commitments and Contingencies
EnCana agreed to indemnify the purchaser of its Ecuador interests against losses that may arise in certain circumstances which are defined in the share sale agreements. The obligation to indemnify will arise should losses exceed amounts specified in the sale agreements and is limited to maximum amounts which are set forth in the share sale agreements.
During the second quarter of 2006, the Government of Ecuador seized the Block 15 assets, in relation to which EnCana previously held a 40 percent economic interest, from the operator which is an event requiring indemnification under the terms of EnCanas sale agreement with the purchaser. The purchaser requested payment and EnCana paid the maximum amount calculated in accordance with the terms of the agreements, approximately $265 million. EnCana does not expect that any further significant indemnification payments relating to any other business matters addressed in the share sale agreements will be required to be made to the purchaser.
20
NOTE 6. Divestitures
For the years ended December 31 |
|
2007 |
|
2006 |
|
2005 |
|
|||
|
|
|
|
|
|
|
|
|||
Canada |
|
$ |
54 |
|
$ |
59 |
|
$ |
447 |
|
United States |
|
10 |
|
19 |
|
2,074 |
|
|||
Other |
|
360 |
|
367 |
|
- |
|
|||
Market Optimization |
|
- |
|
244 |
|
- |
|
|||
Corporate |
|
57 |
|
- |
|
2 |
|
|||
|
|
$ |
481 |
|
$ |
689 |
|
$ |
2,523 |
|
Proceeds received on the sale of assets and investments in 2007 were $481 million (2006 $689 million; 2005 $2,523 million) as described below:
Canada and United States
In 2007, EnCana completed the divestiture of mature conventional oil and natural gas assets for proceeds of $64 million (2006 $78 million; 2005 $471 million).
In May 2005, EnCana completed the sale of its Gulf of Mexico assets for approximately $2.1 billion resulting in net proceeds of approximately $1.5 billion after deducting $578 million in tax plus other adjustments. In accordance with full cost accounting for oil and gas activities, proceeds were credited to property, plant and equipment.
Other
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 May 2007, the Company completed the sale of its assets in the Mackenzie Delta and Beaufort Sea for proceeds of $159 million, which were credited to property, plant and equipment.
In January 2007, the Company completed the sale of its interests in Chad, properties that were in the pre-production stage, for proceeds of $208 million which resulted in a gain on sale of $59 million.
In August 2006, EnCana completed the sale of its 50 percent interest in the Chinook heavy oil discovery offshore Brazil for approximately $367 million which resulted in a gain on sale of $304 million. After recording income tax of $49 million, EnCana recorded an after-tax gain of $255 million.
Market Optimization
In February 2006, the Company sold its investment in Entrega Gas Pipeline LLC for approximately $244 million which resulted in a gain on sale of $17 million.
Corporate
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.
21
NOTE 7. Interest, Net
For the years ended December 31 |
|
2007 |
|
2006 |
|
2005 |
|
|||
|
|
|
|
|
|
|
|
|||
Interest Expense Long-Term Debt |
|
$ |
460 |
|
$ |
366 |
|
$ |
417 |
|
Early Retirement of Long-Term Debt |
|
- |
|
- |
|
121 |
|
|||
Interest Expense Other* |
|
244 |
|
76 |
|
18 |
|
|||
Interest Income* |
|
(276 |
) |
(46 |
) |
(32 |
) |
|||
|
|
$ |
428 |
|
$ |
396 |
|
$ |
524 |
|
* In 2007, Interest Expense Other and Interest Income are primarily due to the Partnership Contribution Payable and Receivable, respectively. See Note 10.
During 2005, EnCana redeemed a number of unsecured notes with a principal of C$1,150 million. The $121 million before tax ($79 million after-tax) charge is due to the early retirement of these medium term notes.
EnCana has entered into a series of one or more interest rate swaps, foreign exchange swaps and option transactions detailed below (See Note 14). The net effect of these transactions reduced interest costs in 2007 by $4 million (2006 $7 million; 2005 $16 million).
Swap Positions
As at December 31, 2007 |
|
Principal Amount |
|
Indenture Interest |
|
Net Swap To |
|
Effective Rate |
|
|
|
|
|
|
|
|
|
|
|
5.80% due June 2, 2008 |
|
US$71 million |
|
C $Fixed |
|
US $Fixed * |
|
4.80% |
|
C$225 million |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
C$125 million |
|
C $Fixed |
|
C $Floating |
|
3 month Bankers |
|
|
|
|
|
|
|
|
|
Acceptance less |
|
|
|
|
|
|
|
|
|
5 basis points |
|
* This instrument has been subject to multiple swap transactions.
NOTE 8. Foreign Exchange (Gain) Loss, Net
For the years ended December 31 |
|
2007 |
|
2006 |
|
2005 |
|
|||
|
|
|
|
|
|
|
|
|||
Unrealized Foreign Exchange (Gain) Loss on: |
|
|
|
|
|
|
|
|||
Translation of U.S. dollar debt issued from Canada |
|
$ |
(683 |
) |
$ |
- |
|
$ |
(113 |
) |
Translation of U.S. dollar partnership contribution receivable issued from Canada |
|
617 |
|
- |
|
- |
|
|||
Other Foreign Exchange (Gain) Loss |
|
(98 |
) |
14 |
|
89 |
|
|||
|
|
$ |
(164 |
) |
$ |
14 |
|
$ |
(24 |
) |
NOTE 9. Income Taxes
The provision for income taxes is as follows:
For the years ended December 31 |
|
2007 |
|
2006 |
|
2005 |
|
|||
|
|
|
|
|
|
|
|
|||
Current |
|
|
|
|
|
|
|
|||
Canada |
|
$ |
900 |
|
$ |
764 |
|
$ |
493 |
|
United States |
|
647 |
|
128 |
|
719 |
|
|||
Other |
|
7 |
|
50 |
|
(8 |
) |
|||
Total Current Tax |
|
1,554 |
|
942 |
|
1,204 |
|
|||
Future |
|
(316 |
) |
1,407 |
|
56 |
|
|||
Future Tax Rate Reductions |
|
(301 |
) |
(457 |
) |
- |
|
|||
Total Future Tax |
|
(617 |
) |
950 |
|
56 |
|
|||
|
|
$ |
937 |
|
$ |
1,892 |
|
$ |
1,260 |
|
Included in current tax for 2006 is $49 million related to the sale of assets in Brazil (2005 $578 million related to the sale of the Gulf of Mexico assets).
22
The following table reconciles income taxes calculated at the Canadian statutory rate with the actual income taxes:
For the years ended December 31 |
|
2007 |
|
2006 |
|
2005 |
|
|||
|
|
|
|
|
|
|
|
|||
Net Earnings Before Income Tax |
|
$ |
4,821 |
|
$ |
6,943 |
|
$ |
4,089 |
|
Canadian Statutory Rate |
|
32.3 |
% |
34.7 |
% |
37.9 |
% |
|||
Expected Income Tax |
|
1,557 |
|
2,407 |
|
1,550 |
|
|||
Effect on Taxes Resulting from: |
|
|
|
|
|
|
|
|||
Non-deductible Canadian Crown payments |
|
- |
|
97 |
|
207 |
|
|||
Canadian resource allowance |
|
- |
|
(16 |
) |
(202 |
) |
|||
Statutory and other rate differences |
|
76 |
|
(98 |
) |
(235 |
) |
|||
Effect of tax rate changes |
|
(301 |
) |
(457 |
) |
- |
|
|||
Effect of legislative changes |
|
(179 |
) |
- |
|
- |
|
|||
Non-taxable downstream partnership income |
|
(70 |
) |
- |
|
- |
|
|||
Non-taxable capital gains |
|
(124 |
) |
(1 |
) |
(24 |
) |
|||
Tax basis retained on divestitures |
|
- |
|
- |
|
(68 |
) |
|||
Large corporations tax |
|
- |
|
- |
|
25 |
|
|||
Other |
|
(22 |
) |
(40 |
) |
7 |
|
|||
|
|
$ |
937 |
|
$ |
1,892 |
|
$ |
1,260 |
|
|
|
|
|
|
|
|
|
|||
Effective Tax Rate |
|
19.4 |
% |
27.3 |
% |
30.8 |
% |
The net future income tax liability is comprised of:
As at December 31 |
|
2007 |
|
2006 |
|
||
|
|
|
|
|
|
||
Future Tax Liabilities |
|
|
|
|
|
||
Property, plant and equipment in excess of tax values |
|
$ |
5,401 |
|
$ |
4,695 |
|
Timing of partnership items |
|
961 |
|
1,251 |
|
||
Other |
|
- |
|
305 |
|
||
Future Tax Assets |
|
|
|
|
|
||
Non-capital and net operating losses carried forward |
|
(6 |
) |
(11 |
) |
||
Other |
|
(148 |
) |
- |
|
||
Net Future Income Tax Liability |
|
$ |
6,208 |
|
$ |
6,240 |
|
The approximate amounts of tax pools available are as follows:
As at December 31 |
|
2007 |
|
2006 |
|
||
|
|
|
|
|
|
||
Canada |
|
$ |
11,014 |
|
$ |
9,352 |
|
United States |
|
7,101 |
|
3,409 |
|
||
|
|
$ |
18,115 |
|
$ |
12,761 |
|
Included in the above tax pools are $23 million (2006 $39 million) related to non-capital and net operating losses available for carry forward to reduce taxable income in future years. These losses expire between 2008 and 2027.
The current income tax provision includes amounts payable or recoverable in respect of Canadian partnership earnings included in the Consolidated Financial Statements for partnerships that have a year end that is after that of EnCana Corporation.
NOTE 10. Partnership Contribution Receivable / Payable
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 partnership contribution receivable shown in the Consolidated Balance Sheet represents EnCanas 50 percent share of this promissory note, net of payments to date.
23
Mandatory Receipts
|
|
2008 |
|
2009 |
|
2010 |
|
2011 |
|
2012 |
|
Thereafter |
|
Total |
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Partnership Contribution Receivable |
|
$ |
297 |
|
$ |
313 |
|
$ |
330 |
|
$ |
347 |
|
$ |
366 |
|
$ |
1,791 |
|
$ |
3,444 |
|
Partnership Contribution Payable
On January 2, 2007, upon the creation of the Integrated Oil joint venture, EnCana issued a promissory note to the downstream entity in the amount of $7.5 billion in exchange for a 50 percent interest. The note bears interest at a rate of 6.0 percent per annum. Equal payments of principal and interest are payable quarterly, with final payment due January 2, 2017. The current and long-term partnership contribution payable amounts shown in the Consolidated Balance Sheet represents EnCanas 50 percent share of this promissory note, net of payments to date.
Mandatory Payments
|
|
2008 |
|
2009 |
|
2010 |
|
2011 |
|
2012 |
|
Thereafter |
|
Total |
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Partnership Contribution Payable |
|
$ |
288 |
|
$ |
306 |
|
$ |
325 |
|
$ |
345 |
|
$ |
366 |
|
$ |
1,821 |
|
$ |
3,451 |
|
NOTE 11. Inventories
As at December 31 |
|
2007 |
|
2006 |
|
||
|
|
|
|
|
|
||
Product |
|
|
|
|
|
||
Canada |
|
$ |
- |
|
$ |
1 |
|
United States |
|
2 |
|
- |
|
||
Integrated Oil |
|
646 |
|
49 |
|
||
Market Optimization |
|
180 |
|
126 |
|
||
|
|
$ |
828 |
|
$ |
176 |
|
NOTE 12. Property, Plant and Equipment, Net
As at December 31 |
|
|
|
2007 |
|
|
|
|
|
2006 |
|
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
|
|
|
Accumulated |
|
|
|
|
|
Accumulated |
|
|
|
||||||
|
|
Cost |
|
DD&A |
* |
Net |
|
Cost |
|
DD&A |
* |
Net |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Canada |
|
$ |
36,618 |
|
$ |
(18,987 |
) |
$ |
17,631 |
|
$ |
30,852 |
|
$ |
(14,069 |
) |
$ |
16,783 |
|
United States |
|
15,681 |
|
(3,802 |
) |
11,879 |
|
11,105 |
|
(2,611 |
) |
8,494 |
|
||||||
Other |
|
1,466 |
|
(362 |
) |
1,104 |
|
1,450 |
|
(268 |
) |
1,182 |
|
||||||
Integrated Oil Upstream |
|
1,131 |
|
(116 |
) |
1,015 |
|
1,347 |
|
(25 |
) |
1,322 |
|
||||||
Integrated Oil Downstream |
|
3,855 |
|
(149 |
) |
3,706 |
|
- |
|
- |
|
- |
|
||||||
Market Optimization |
|
253 |
|
(82 |
) |
171 |
|
207 |
|
(53 |
) |
154 |
|
||||||
Corporate |
|
817 |
|
(458 |
) |
359 |
|
616 |
|
(338 |
) |
278 |
|
||||||
|
|
$ |
59,821 |
|
$ |
(23,956 |
) |
$ |
35,865 |
|
$ |
45,577 |
|
$ |
(17,364 |
) |
$ |
28,213 |
|
* Depreciation, depletion and amortization
Canada, United States, Other and Integrated Oil Upstream property, plant and equipment include internal costs directly related to exploration, development and construction activities of $469 million (2006 $365 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. Integrated Oil Downstream assets not put into use are excluded from depreciable costs. At the end of the year these costs were:
As at December 31 |
|
2007 |
|
2006 |
|
2005 |
|
|||
|
|
|
|
|
|
|
|
|||
Canada |
|
$ |
1,381 |
|
$ |
1,449 |
|
$ |
1,689 |
|
United States |
|
1,852 |
|
956 |
|
870 |
|
|||
Other Countries |
|
137 |
|
263 |
|
248 |
|
|||
Integrated Oil Downstream |
|
139 |
|
- |
|
- |
|
|||
|
|
$ |
3,509 |
|
$ |
2,668 |
|
$ |
2,807 |
|
24
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, 2007, the Company completed its impairment review of pre-production cost centres and determined that $68 million of costs should be charged to depreciation, depletion, and amortization in the Consolidated Statement of Earnings (2006 $6 million; 2005 $7 million).
Integrated Oil Downstream expenditures capitalized during the construction phase are not subject to depreciation until put in use and total $139 million at December 31, 2007.
The prices used in the ceiling test evaluation of the Companys crude oil and natural gas reserves at December 31, 2007 were:
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative |
|
|
|
|
|
|
|
|
|
|
|
|
|
% Increase |
|
|
|
2008 |
|
2009 |
|
2010 |
|
2011 |
|
2012 |
|
to 2019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas ($/Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
6.55 |
|
6.71 |
|
6.67 |
|
6.60 |
|
6.58 |
|
- |
|
United States |
|
6.52 |
|
6.84 |
|
6.58 |
|
6.66 |
|
6.92 |
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil ($/barrel) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
46.90 |
|
45.40 |
|
45.05 |
|
43.98 |
|
42.98 |
|
(7 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids ($/barrel) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
65.81 |
|
66.26 |
|
67.37 |
|
67.67 |
|
67.76 |
|
- |
|
United States |
|
64.33 |
|
64.73 |
|
64.97 |
|
64.90 |
|
63.52 |
|
(2 |
)% |
NOTE 13. Investments and Other Assets
As at December 31 |
|
|
|
2007 |
|
2006 |
|
||
|
|
|
|
|
|
|
|
||
Prepaid Capital |
|
|
|
$ |
383 |
|
$ |
401 |
|
Deferred Asset Integrated Oil |
|
|
|
159 |
|
- |
|
||
Deferred Pension Plan and Savings Plan |
|
|
|
50 |
|
58 |
|
||
Deferred Financing Costs |
|
(Notes 2, 14 |
) |
- |
|
52 |
|
||
Equity Investment |
|
|
|
- |
|
6 |
|
||
Other |
|
|
|
15 |
|
16 |
|
||
|
|
|
|
$ |
607 |
|
$ |
533 |
|
NOTE 14. Long-Term Debt
As at December 31 |
|
Note |
|
2007 |
|
2006 |
|
||
|
|
|
|
|
|
|
|
||
Canadian Dollar Denominated Debt |
|
|
|
|
|
|
|
||
Revolving credit and term loan borrowings |
|
B |
|
$ |
1,506 |
|
$ |
1,456 |
|
Unsecured notes |
|
C |
|
1,138 |
|
793 |
|
||
|
|
|
|
2,644 |
|
2,249 |
|
||
U.S. Dollar Denominated Debt |
|
|
|
|
|
|
|
||
Revolving credit and term loan borrowings |
|
D |
|
495 |
|
104 |
|
||
Unsecured notes |
|
E |
|
6,421 |
|
4,421 |
|
||
|
|
|
|
6,916 |
|
4,525 |
|
||
|
|
|
|
|
|
|
|
||
Increase in Value of Debt Acquired |
|
F |
|
66 |
|
60 |
|
||
Debt Discounts and Financing Costs |
|
G |
|
(83 |
) |
- |
|
||
Current Portion of Long-Term Debt |
|
H |
|
(703 |
) |
(257 |
) |
||
|
|
|
|
$ |
8,840 |
|
$ |
6,577 |
|
A) Overview
Revolving Credit and Term Loan Borrowings
At December 31, 2007, EnCana Corporation had in place a revolving credit facility for C$4.5 billion or its equivalent amount in U.S. dollars ($4.6 billion). The facility, which matures in October 2012, is fully revolving for a period of five years. The facility is extendible from time to time, but not more
25
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, 2007, one of EnCanas subsidiaries had in place a credit facility totaling $600 million. The facility, which matures in February 2012, is guaranteed by EnCana Corporation and is fully revolving for five years. 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.
Revolving credit and term loan borrowings include Bankers Acceptances, Commercial Paper and LIBOR loans of $2,001 million (2006 $1,560 million) maturing at various dates with a weighted average interest rate of 5.00 percent (2006 4.58 percent). These amounts are fully supported and Management expects that they will continue to be supported by revolving credit and term loan facilities that have no repayment requirements within the next year.
Standby fees paid in 2007 relating to revolving credit and term loan agreements were approximately $4 million (2006 $5 million; 2005 $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 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 renewed in 2007 and expires in June 2009. At December 31, 2007, C$2 billion ($2 billion) of the shelf prospectus remains 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 $2 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 expiry dates, are determined by reference to market conditions at the date of issue. The shelf prospectus was renewed in 2006 and expires in October 2008. At December 31, 2007, the shelf prospectus was fully utilized.
EnCana has an indirect wholly owned subsidiary, EnCana Holdings Finance Corp., which has in place a debt shelf prospectus for U.S. unsecured notes in the amount of $2 billion under the 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 expiry dates, are determined by reference to market conditions at the date of issue. The debt securities issued under this shelf prospectus are fully and unconditionally guaranteed by EnCana Corporation. EnCana has also obtained certain exemption orders from Canadian securities regulatory authorities that allow the filing of certain financial and other information of EnCana to satisfy certain continuous disclosure obligations of EnCana Holdings Finance Corp. The shelf prospectus was renewed in 2006 and expires in July 2008. At December 31, 2007, $2 billion of the shelf prospectus remains unutilized, the availability of which is dependent upon market conditions.
26
B) Canadian Revolving Credit and Term Loan Borrowings
|
|
C$ Principal |
|
2007 |
|
2006 |
|
|||
|
|
|
|
|
|
|
|
|||
Bankers Acceptances |
|
$ |
420 |
|
$ |
425 |
|
$ |
335 |
|
Commercial Paper |
|
1,068 |
|
1,081 |
|
1,121 |
|
|||
|
|
$ |
1,488 |
|
$ |
1,506 |
|
$ |
1,456 |
|
C) Canadian Unsecured Notes
|
|
C$ Principal |
|
2007 |
|
2006 |
|
|||
|
|
|
|
|
|
|
|
|||
5.30% due December 3, 2007 |
|
$ |
- |
|
$ |
- |
|
$ |
257 |
|
5.80% due June 2, 2008 |
|
125 |
|
126 |
|
107 |
|
|||
3.60% due September 15, 2008 |
|
500 |
|
506 |
|
429 |
|
|||
4.30% due March 12, 2012 |
|
500 |
|
506 |
|
- |
|
|||
|
|
$ |
1,125 |
|
$ |
1,138 |
|
$ |
793 |
|
D) U.S. Revolving Credit and Term Loan Borrowings
|
|
|
|
2007 |
|
2006 |
|
||
|
|
|
|
|
|
|
|
||
LIBOR |
|
|
|
$ |
20 |
|
$ |
- |
|
Commercial Paper |
|
|
|
475 |
|
104 |
|
||
|
|
|
|
$ |
495 |
|
$ |
104 |
|
E) U.S. Unsecured Notes
|
|
C$ Amount |
|
2007 |
|
2006 |
|
|||
|
|
|
|
|
|
|
|
|||
5.80% due June 2, 2008 |
|
$ |
70 |
* |
$ |
71 |
|
$ |
71 |
|
4.60% due August 15, 2009 |
|
|
|
250 |
|
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 |
|
- |
|
|||
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 |
|
- |
|
|||
6.50% due February 1, 2038 |
|
|
|
800 |
|
- |
|
|||
|
|
|
|
$ |
6,421 |
|
$ |
4,421 |
|
|
* The Company has entered into a cross-currency and interest rate swap transaction that effectively converts a portion of the Canadian dollar denominated note to U.S. dollars. The effective U.S. dollar principal is shown in the table.
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 date 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 21 years.
G) Debt Discounts and Financing Costs
On January 1, 2007, upon adoption of the financial instruments standard, $52 million of long-term debt transaction costs, premiums and discounts were reclassified from other assets to long-term debt (See Note 2). The costs capitalized within long-term debt are being amortized using the effective interest method. Previously, the Company deferred these costs within other assets and amortized them straight-line over the life of the related long-term debt. During 2007, $25 million in
27
transaction costs and discounts have been capitalized within long-term debt relating to the issuance of Canadian and U.S. unsecured notes.
H) Current Portion of Long-Term Debt
|
|
C$ |
|
2007 |
|
2006 |
|
|||
|
|
|
|
|
|
|
|
|||
5.30% medium term note due December 3, 2007 |
|
$ |
- |
|
$ |
- |
|
$ |
257 |
|
5.80% medium term note due June 2, 2008 |
|
125 |
|
126 |
|
- |
|
|||
5.80% medium term note due June 2, 2008 |
|
- |
|
71 |
|
- |
|
|||
3.60% medium term note due September 15, 2008 |
|
500 |
|
506 |
|
- |
|
|||
|
|
$ |
625 |
|
$ |
703 |
|
$ |
257 |
|
I) Mandatory Debt Payments
|
|
C$ |
|
US$ |
|
Total US$ |
|
|||
|
|
|
|
|
|
|
|
|||
2008 |
|
$ |
625 |
|
$ |
71 |
|
$ |
703 |
|
2009 |
|
- |
|
250 |
|
250 |
|
|||
2010 |
|
- |
|
200 |
|
200 |
|
|||
2011 |
|
- |
|
500 |
|
500 |
|
|||
2012 |
|
1,988 |
|
495 |
|
2,507 |
|
|||
Thereafter |
|
- |
|
5,400 |
|
5,400 |
|
|||
Total |
|
$ |
2,613 |
|
$ |
6,916 |
|
$ |
9,560 |
|
The amount due in 2008 excludes Bankers Acceptances, Commercial Paper and LIBOR loans, which are fully supported by revolving credit and term loan facilities that have no repayment requirements within the next year.
NOTE 15. Asset Retirement Obligation
The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the obligation associated with the retirement of oil and gas assets and refining facilities:
As at December 31 |
|
2007 |
|
2006 |
|
||
|
|
|
|
|
|
||
Asset Retirement Obligation, Beginning of Year |
|
$ |
1,051 |
|
$ |
816 |
|
Liabilities Incurred |
|
89 |
|
68 |
|
||
Liabilities Settled |
|
(100 |
) |
(51 |
) |
||
Change in Estimated Future Cash Flows |
|
184 |
|
172 |
|
||
Accretion Expense |
|
64 |
|
50 |
|
||
Other |
|
170 |
|
(4 |
) |
||
Asset Retirement Obligation, End of Year |
|
$ |
1,458 |
|
$ |
1,051 |
|
The total undiscounted amount of estimated cash flows required to settle the obligation is $7,395 million (2006 $5,334 million), which has been discounted using a weighted average credit-adjusted risk free rate of 5.85 percent (2006 5.66 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.
28
NOTE 16. 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.
Issued and Outstanding
As at December 31 |
|
2007 |
|
2006 |
|
||||||
|
|
Number |
|
Amount |
|
Number |
|
Amount |
|
||
|
|
|
|
|
|
|
|
|
|
||
Common Shares Outstanding, Beginning of Year |
|
777.9 |
|
$ |
4,587 |
|
854.9 |
|
$ |
5,131 |
|
Common Shares Issued under Option Plans |
|
8.3 |
|
176 |
|
8.6 |
|
179 |
|
||
Stock-Based Compensation |
|
- |
|
17 |
|
- |
|
11 |
|
||
Common Shares Purchased |
|
(36.0 |
) |
(301 |
) |
(85.6 |
) |
(734 |
) |
||
Common Shares Outstanding, End of Year |
|
750.2 |
|
$ |
4,479 |
|
777.9 |
|
$ |
4,587 |
|
Normal Course Issuer Bid
In 2007, the Company purchased 38.9 million Common Shares for total consideration of $2,025 million. Of the amount paid, $325 million was charged to Share capital and $1,700 million was charged to Retained earnings. Included in the Common Shares Purchased in 2007 are 2.9 million Common Shares distributed, valued at $24 million, from the EnCana Employee Benefit Plan Trust that vested under EnCanas Performance Share Unit Plan (See Note 17). For these Common Shares distributed, there was an $82 million adjustment to Retained earnings with a reduction to Paid in surplus of $106 million.
EnCana has received regulatory approval each year under Canadian securities laws to purchase Common Shares under six consecutive Normal Course Issuer Bids (Bids). EnCana is entitled to purchase, for cancellation, up to approximately 75.1 million Common Shares under the renewed Bid which commenced on November 13, 2007 and terminates on November 12, 2008. During January 2008, EnCana purchased approximately 3.0 million Common Shares under the Bid for total consideration of $191 million.
Stock Options
EnCana has stock-based compensation plans that allow employees and directors to purchase Common Shares of the Company. Option exercise prices approximate the market price for the Common Shares on the date the options were issued. Options granted under the plans are generally fully exercisable after three years and expire five years after the date granted. Options granted under predecessor and/or related company replacement plans expire up to 10 years from the date the options were granted. All options issued subsequent to December 31, 2003 have an associated Tandem Share Appreciation Right (TSAR) attached to them (See Note 17).
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 on or after November 4, 1999 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, with respect to the February 13, 2007 grant, one third of the stock options granted were service based and two thirds were performance based. The performance based stock options only become exercisable subject to a vesting factor based on EnCanas performance relative to pre-determined key measures (See Note 17).
29
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.
Directors Plan
Effective April 5, 2002, the Company amended the director stock option plan. Under the terms of the plan, new non-employee directors were given an initial grant of 15,000 options to purchase Common Shares of the Company. Thereafter, there was an annual grant of 7,500 options to each non-employee director. Options, which expire five years after the grant date, are 100 percent exercisable on the earlier of the next annual general meeting following the grant date and the first anniversary of the grant date. On October 23, 2003, issuances of stock options under this plan were discontinued and on October 25, 2005, the Company terminated the plan.
The following tables summarize the information about options to purchase Common Shares that do not have a TSAR attached to them:
As at December 31 |
|
2007 |
|
2006 |
|
2005 |
|
||||||
|
|
Stock |
|
Weighted Average Exercise Price(C$) |
|
Stock |
|
Weighted Average
Exercise |
|
Stock |
|
Weighted Average
Exercise |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, Beginning of Year |
|
11.8 |
|
23.17 |
|
20.7 |
|
23.36 |
|
36.2 |
|
23.15 |
|
Exercised |
|
(8.3 |
) |
23.73 |
|
(8.6 |
) |
23.60 |
|
(14.9 |
) |
22.90 |
|
Forfeited |
|
(0.1 |
) |
22.53 |
|
(0.3 |
) |
23.80 |
|
(0.6 |
) |
21.71 |
|
Outstanding, End of Year |
|
3.4 |
|
21.82 |
|
11.8 |
|
23.17 |
|
20.7 |
|
23.36 |
|
Exercisable, End of Year |
|
3.4 |
|
21.82 |
|
11.8 |
|
23.17 |
|
16.8 |
|
23.21 |
|
As at December 31, 2007 |
|
|
|
Outstanding Options |
|
Exercisable Options |
|
||||||
Range of Exercise Price (C$) |
|
|
|
Number of |
|
Weighted |
|
Weighted |
|
Number of |
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11.00 to 21.99 |
|
|
|
0.6 |
|
1.8 |
|
11.58 |
|
0.6 |
|
11.58 |
|
22.00 to 23.99 |
|
|
|
2.6 |
|
0.3 |
|
23.86 |
|
2.6 |
|
23.86 |
|
24.00 to 25.99 |
|
|
|
0.2 |
|
0.7 |
|
25.04 |
|
0.2 |
|
25.04 |
|
|
|
|
|
3.4 |
|
0.6 |
|
21.82 |
|
3.4 |
|
21.82 |
|
At December 31, 2007, there were 12.2 million Common Shares reserved for issuance under stock option plans (2006 20.7 million; 2005 29.3 million).
EnCana has recorded stock-based compensation expense in the Consolidated Statement of Earnings for stock options granted to employees and directors in 2003 using the fair value method. Stock options granted subsequent to December 31, 2003 have an associated TSAR attached. Compensation expense has not been recorded in the Consolidated Statement of Earnings related to stock options granted prior to 2003.
30
The fair value of each option granted is estimated on the date of grant using the Black-Scholes-Merton option-pricing model with weighted average assumptions for grants as follows:
For the year ended December 31 |
|
2003 |
|
|
|
|
|
|
|
Weighted Average Fair Value of Options Granted (C$) |
|
$ |
6.11 |
|
Risk-Free Interest Rate |
|
3.87 |
% |
|
Expected Lives (years) |
|
3.00 |
|
|
Expected Volatility |
|
0.33 |
|
|
Annual Dividend per Share (C$/Common Share) |
|
$ |
0.20 |
|
At December 31, 2007 and 2006, the balance in Paid in surplus relates to stock-based compensation programs.
NOTE 17. Compensation Plans
Where applicable, the amounts below have been restated to reflect the effect of the Common Share split approved in April 2005.
A) 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.
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 is dated December 31, 2005, and the next required filing will be as at December 31, 2008.
Information about defined benefit pension and other post-employment benefit plans, based on actuarial estimations as at December 31, 2007 is as follows:
Accrued Benefit Obligation
|
|
Pension Benefits |
|
OPEB |
|
||||||||
As at December 31 |
|
2007 |
|
2006 |
|
2007 |
|
2006 |
|
||||
|
|
|
|
|
|
|
|
|
|
||||
Accrued Benefit Obligation, Beginning of Year |
|
$ |
308 |
|
$ |
294 |
|
$ |
45 |
|
$ |
39 |
|
Current service cost |
|
8 |
|
9 |
|
8 |
|
7 |
|
||||
Interest cost |
|
16 |
|
15 |
|
3 |
|
2 |
|
||||
Benefits paid |
|
(17 |
) |
(18 |
) |
(1 |
) |
(1 |
) |
||||
Actuarial (gain) loss |
|
(14 |
) |
7 |
|
(5 |
) |
(2 |
) |
||||
Contributions |
|
1 |
|
1 |
|
- |
|
- |
|
||||
Foreign exchange |
|
55 |
|
- |
|
3 |
|
- |
|
||||
Accrued Benefit Obligation, End of Year |
|
$ |
357 |
|
$ |
308 |
|
$ |
53 |
|
$ |
45 |
|
Plan Assets
|
|
Pension Benefits |
|
OPEB |
|
||||||||
As at December 31 |
|
2007 |
|
2006 |
|
2007 |
|
2006 |
|
||||
|
|
|
|
|
|
|
|
|
|
||||
Fair Value of Plan Assets, Beginning of Year |
|
$ |
304 |
|
$ |
284 |
|
$ |
- |
|
$ |
- |
|
Actual return on plan assets |
|
5 |
|
27 |
|
- |
|
- |
|
||||
Employer contributions |
|
8 |
|
10 |
|
- |
|
- |
|
||||
Employees contributions |
|
1 |
|
1 |
|
- |
|
- |
|
||||
Benefits paid |
|
(17 |
) |
(18 |
) |
- |
|
- |
|
||||
Foreign exchange |
|
54 |
|
- |
|
- |
|
- |
|
||||
Fair Value of Plan Assets, End of Year |
|
$ |
355 |
|
$ |
304 |
|
$ |
- |
|
$ |
- |
|
Accrued Benefit Asset (Liability)
|
|
Pension Benefits |
|
OPEB |
|
||||||||
As at December 31 |
|
2007 |
|
2006 |
|
2007 |
|
2006 |
|
||||
|
|
|
|
|
|
|
|
|
|
||||
Funded Status Plan Assets (less) than Benefit Obligation |
|
$ |
(2 |
) |
$ |
(4 |
) |
$ |
(53 |
) |
$ |
(45 |
) |
Amounts Not Recognized: |
|
|
|
|
|
|
|
|
|
||||
Unamortized net actuarial loss (gain) |
|
59 |
|
54 |
|
(3 |
) |
2 |
|
||||
Unamortized past service cost |
|
6 |
|
7 |
|
1 |
|
1 |
|
||||
Net transitional asset |
|
(3 |
) |
(6 |
) |
12 |
|
13 |
|
||||
Accrued Benefit Asset (Liability) |
|
$ |
60 |
|
$ |
51 |
|
$ |
(43 |
) |
$ |
(29 |
) |
31
|
|
Pension Benefits |
|
OPEB |
|
||||||||
As at December 31 |
|
2007 |
|
2006 |
|
2007 |
|
2006 |
|
||||
|
|
|
|
|
|
|
|
|
|
||||
Prepaid Benefit Cost |
|
$ |
60 |
|
$ |
51 |
|
$ |
- |
|
$ |
- |
|
Accrued Benefit Cost |
|
- |
|
- |
|
(43 |
) |
(29 |
) |
||||
Net Amount Recognized |
|
$ |
60 |
|
$ |
51 |
|
$ |
(43 |
) |
$ |
(29 |
) |
The Companys OPEB plans are funded on an as required basis.
The weighted average assumptions used to determine benefit obligations are as follows:
|
|
Pension Benefits |
|
OPEB |
|
||||
As at December 31 |
|
2007 |
|
2006 |
|
2007 |
|
2006 |
|
|
|
|
|
|
|
|
|
|
|
Discount Rate |
|
5.25 |
% |
5.00 |
% |
5.50 |
% |
5.375 |
% |
Rate of Compensation Increase |
|
4.28 |
% |
4.30 |
% |
5.77 |
% |
5.65 |
% |
The weighted average assumptions used to determine periodic expense are as follows:
|
|
Pension Benefits |
|
OPEB |
|
||||
For the years ended December 31 |
|
2007 |
|
2006 |
|
2007 |
|
2006 |
|
|
|
|
|
|
|
|
|
|
|
Discount Rate |
|
5.00 |
% |
5.00 |
% |
5.38 |
% |
5.25 |
% |
Expected Long-Term Rate of Return on Plan Assets: |
|
|
|
|
|
|
|
|
|
Registered pension plans |
|
6.75 |
% |
6.75 |
% |
n/a |
|
n/a |
|
Supplemental pension plans |
|
3.375 |
% |
3.375 |
% |
n/a |
|
n/a |
|
Rate of Compensation Increase |
|
4.34 |
% |
4.50 |
% |
5.77 |
% |
5.65 |
% |
The periodic expense for benefits is as follows:
|
|
Pension Benefits |
|
OPEB |
|
||||||||||||||
For the years ended December 31 |
|
2007 |
|
2006 |
|
2005 |
|
2007 |
|
2006 |
|
2005 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Current Service Cost |
|
$ |
8 |
|
$ |
9 |
|
$ |
6 |
|
$ |
8 |
|
$ |
7 |
|
$ |
5 |
|
Interest Cost |
|
16 |
|
15 |
|
14 |
|
3 |
|
2 |
|
2 |
|
||||||
Actual Return on Plan Assets |
|
(5 |
) |
(27 |
) |
(29 |
) |
- |
|
- |
|
- |
|
||||||
Actuarial (Gain) Loss on Accrued Benefit Obligation |
|
(13 |
) |
6 |
|
29 |
|
- |
|
- |
|
- |
|
||||||
Difference Between Actual and: |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Expected return on plan assets |
|
(14 |
) |
11 |
|
15 |
|
- |
|
- |
|
- |
|
||||||
Recognized actuarial gain (loss) |
|
17 |
|
- |
|
(24 |
) |
- |
|
- |
|
- |
|
||||||
Difference Between Amortization of Past Service Costs and Actual Plan Amendments |
|
2 |
|
2 |
|
2 |
|
- |
|
- |
|
- |
|
||||||
Amortization of Transitional Obligation |
|
(3 |
) |
(3 |
) |
(3 |
) |
1 |
|
2 |
|
1 |
|
||||||
Defined Benefit Plans Expense |
|
$ |
8 |
|
$ |
13 |
|
$ |
10 |
|
$ |
12 |
|
$ |
11 |
|
$ |
8 |
|
Defined Contribution Plans Expense |
|
$ |
34 |
|
$ |
28 |
|
$ |
22 |
|
$ |
- |
|
$ |
- |
|
$ |
- |
|
Net Benefit Plan Expense |
|
$ |
42 |
|
$ |
41 |
|
$ |
32 |
|
$ |
12 |
|
$ |
11 |
|
$ |
8 |
|
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 12 years.
Assumed health care cost trend rates are as follows:
As at December 31 |
|
2007 |
|
2006 |
|
|
|
|
|
|
|
Health Care Cost Trend Rate for Next Year |
|
10.50 |
% |
11.00 |
% |
Rate that the Trend Rate Gradually Trends To |
|
5.00 |
% |
5.00 |
% |
Year that the Trend Rate Reaches the Rate which it is Expected to Remain At |
|
2016 |
|
2015 |
|
32
Assumed health care cost trend rates have an effect on the amounts reported for the OPEB plans. A one percentage point change in assumed health care cost trend rates would have the following effects:
|
|
One Percentage |
|
One Percentage |
|
||
|
|
Point Increase |
|
Point Decrease |
|
||
|
|
|
|
|
|
||
Effect on Total of Service and Interest Cost |
|
$ |
1 |
|
$ |
(1) |
|
Effect on Post-Retirement Benefit Obligation |
|
$ |
5 |
|
$ |
(4) |
|
The Companys pension plan asset allocations are as follows:
Asset Category |
|
Target Allocation % |
|
% of Plan Assets at |
|
Expected Long-Term Rate of |
|
||||
|
|
Normal |
|
Range |
|
2007 |
|
2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic Equity |
|
35 |
|
25-45 |
|
39 |
|
39 |
|
|
|
Foreign Equity |
|
30 |
|
20-40 |
|
27 |
|
30 |
|
|
|
Bonds |
|
30 |
|
20-40 |
|
27 |
|
25 |
|
|
|
Real Estate and Other |
|
5 |
|
0-20 |
|
7 |
|
6 |
|
|
|
Total |
|
100 |
|
|
|
100 |
|
100 |
|
6.75 |
% |
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 objective of the asset allocation policy is to manage the funded status of the plan at an appropriate level of risk, giving consideration to the security of the assets and the potential volatility of market returns and the resulting effect on both contribution requirements and pension expense. The long-term return is expected to achieve or exceed the return from a composite benchmark comprised of passive investments in appropriate market indices. The Supplemental Pension Plan is funded through a retirement compensation arrangement and is subject to the applicable Canada Revenue Agency regulations.
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 pension plans are subject to the results of the actuarial valuation and direction by the Pension Committee. Contributions by the participants to the pension and other benefits plans were $1 million for the year ended December 31, 2007 (2006 $1 million; 2005 $1 million).
Estimated future payment of pension and other benefits are as follows:
|
|
Pension |
|
OPEB |
|
||||
|
|
|
|
|
|
||||
2008 |
|
$ |
18 |
|
|
$ |
2 |
|
|
2009 |
|
|
19 |
|
|
|
2 |
|
|
2010 |
|
|
19 |
|
|
|
2 |
|
|
2011 |
|
|
20 |
|
|
|
3 |
|
|
2012 |
|
|
21 |
|
|
|
3 |
|
|
2013 2017 |
|
|
121 |
|
|
|
22 |
|
|
Total |
|
$ |
218 |
|
|
$ |
34 |
|
|
33
B) Tandem Share Appreciation Rights
Subsequent to December 31, 2003, all options to purchase Common Shares issued under the share option plans described in Note 16 have an associated Tandem Share Appreciation Right (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.
The following tables summarize the information about the TSARs:
As at December 31 |
|
|
|
2007 |
|
2006 |
|
||||
|
|
|
|
Outstanding TSARs |
|
Weighted Average Exercise |
|
Outstanding TSARs |
|
Weighted Average
Exercise |
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Dollar Denominated (C$) |
|
|
|
|
|
|
|
|
|
|
|
Outstanding, Beginning of Year |
|
|
|
17,276,191 |
|
44.99 |
|
8,403,967 |
|
38.41 |
|
Granted |
|
|
|
4,814,338 |
|
57.70 |
|
11,180,800 |
|
49.01 |
|
Exercised SARs |
|
|
|
(2,020,357 |
) |
41.20 |
|
(700,418 |
) |
34.54 |
|
Exercised Options |
|
|
|
(12,235 |
) |
35.04 |
|
(32,948 |
) |
34.46 |
|
Forfeited |
|
|
|
(1,203,796 |
) |
50.02 |
|
(1,575,210 |
) |
43.21 |
|
Outstanding, End of Year |
|
|
|
18,854,141 |
|
50.49 |
|
17,276,191 |
|
44.99 |
|
Exercisable, End of Year |
|
|
|
5,267,550 |
|
43.18 |
|
1,971,467 |
|
38.31 |
|
As at December 31, 2007 |
|
Outstanding TSARs |
|
Exercisable Options with TSARs Attached |
|
||||||
Range of Exercise Price (C$) |
|
Number of TSARs |
|
Weighted Average Remaining Contractual Life (years) |
|
Weighted Average Exercise |
|
Number of TSARs |
|
Weighted Average Exercise |
|
|
|
|
|
|
|
|
|
|
|
|
|
20.00 to 29.99 |
|
346,843 |
|
1.35 |
|
27.54 |
|
346,843 |
|
27.54 |
|
30.00 to 39.99 |
|
4,254,009 |
|
2.12 |
|
38.20 |
|
2,266,281 |
|
38.16 |
|
40.00 to 49.99 |
|
8,278,327 |
|
3.10 |
|
48.15 |
|
2,187,192 |
|
48.08 |
|
50.00 to 59.99 |
|
4,961,922 |
|
4.03 |
|
56.02 |
|
406,584 |
|
55.26 |
|
60.00 to 79.99 |
|
1,013,040 |
|
4.39 |
|
64.32 |
|
60,650 |
|
63.00 |
|
|
|
18,854,141 |
|
3.40 |
|
50.49 |
|
5,267,550 |
|
43.18 |
|
During the year, the Company recorded compensation costs of $225 million related to the outstanding TSARs (2006 $52 million; 2005 $60 million).
C) Performance Tandem Share Appreciation Rights
In 2007, under the terms of the existing Employee Stock Option Plan, EnCana granted Performance Tandem Share Appreciation Rights (Performance TSARs) under which the employee has the right to receive a cash payment equal to the excess of the market price of EnCana Common Shares at the time of exercise over the grant price. Performance TSARs vest and expire under the same terms and service conditions as the underlying option, and vesting is subject to EnCana attaining prescribed performance relative to key pre-determined measures. Performance TSARs that do not vest when eligible are forfeited.
34
The following table summarizes the information about the Performance TSARs:
As at December 31 |
|
|
|
|
|
2007 |
|
||||
|
|
|
|
|
|
Outstanding TSARs |
|
Weighted Average |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Dollar Denominated (C$) |
|
|
|
|
|
|
|
|
|
|
|
Outstanding, Beginning of Year |
|
|
|
|
|
- |
|
|
|
- |
|
Granted |
|
|
|
|
|
7,275,575 |
|
|
|
56.09 |
|
Forfeited |
|
|
|
|
|
(344,650 |
) |
|
|
56.09 |
|
Outstanding, End of Year |
|
|
|
|
|
6,930,925 |
|
|
|
56.09 |
|
Exercisable, End of Year |
|
|
|
|
|
- |
|
|
|
- |
|
As at December 31, 2007 |
|
Outstanding TSARs |
|
Exercisable Options with TSARs Attached |
|
||||||
Range of Exercise Price (C$) |
|
Number of TSARs |
|
Weighted Average Remaining Contractual Life (years) |
|
Weighted Average Exercise |
|
Number of TSARs |
|
Weighted Average Exercise |
|
|
|
|
|
|
|
|
|
|
|
|
|
50.00 to 59.99 |
|
6,930,925 |
|
4.12 |
|
56.09 |
|
- |
|
- |
|
During the year, EnCana recorded compensation costs of $21 million related to the outstanding Performance TSARs (2006 nil).
D) Deferred Share Units
The Company has in place a program whereby Directors and certain key employees are issued Deferred Share Units (DSUs), which are equivalent in value to a Common Share of the Company. DSUs granted to Directors vest immediately. DSUs expire on December 15th of the year following the employees retirement or death.
As at December 31 |
|
|
|
2007 |
|
2006 |
|
||||
|
|
|
|
Outstanding DSUs |
|
Average Share Price |
|
Outstanding DSUs |
|
Average |
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Dollar Denominated (C$) |
|
|
|
|
|
|
|
|
|
|
|
Outstanding, Beginning of Year |
|
|
|
866,577 |
|
29.56 |
|
836,561 |
|
26.81 |
|
Granted, Directors |
|
|
|
79,168 |
|
57.02 |
|
70,000 |
|
56.71 |
|
Units, in Lieu of Dividends |
|
|
|
9,314 |
|
62.80 |
|
12,578 |
|
54.69 |
|
Exercised |
|
|
|
(365,885 |
) |
29.56 |
|
(52,562 |
) |
27.92 |
|
Outstanding, End of Year |
|
|
|
589,174 |
|
33.78 |
|
866,577 |
|
29.56 |
|
Exercisable, End of Year |
|
|
|
589,174 |
|
33.78 |
|
866,577 |
|
29.56 |
|
During the year, the Company recorded compensation costs of $14 million related to the outstanding DSUs (2006 $5 million; 2005 $16 million).
E) Performance Share Units
EnCana has in place a program whereby employees may be granted Performance Share Units (PSUs) which entitle the employee to receive, upon vesting, either a Common Share of EnCana or a cash payment equal to the value of one Common Share of EnCana depending upon the terms of the PSU granted. PSUs vest at the end of a three year period. Their ultimate value will depend upon EnCanas performance measured over three calendar years. Performance will be measured by total shareholder return relative to a fixed comparison group of North American oil and gas companies. If EnCanas performance is below the specified level compared to the comparison group, the units awarded will be forfeited. If EnCanas performance is at or above the specified level compared to the comparison group, the value of the PSUs shall be determined by EnCanas relative ranking, with payments ranging from one half to two times the PSUs granted for the 2004 and 2005 grant. These will be paid in Common Shares.
PSUs granted in 2003 were paid out in cash at 75 percent of the number granted. PSUs granted in 2004 were paid out in Common Shares at 100 percent of the number granted.
35
The following table summarizes the information about the PSUs:
As at December 31 |
|
2007 |
|
2006 |
|
||||
|
|
Outstanding |
|
Average |
|
Outstanding |
|
Average |
|
|
|
|
|
|
|
|
|
|
|
Canadian Dollar Denominated (C$) |
|
|
|
|
|
|
|
|
|
Outstanding, Beginning of Year |
|
4,766,329 |
|
31.24 |
|
5,443,997 |
|
30.65 |
|
Granted |
|
23,097 |
|
62.84 |
|
41,459 |
|
54.82 |
|
Paid out |
|
(2,937,491 |
) |
26.98 |
|
(239,794 |
) |
23.26 |
|
Forfeited |
|
(166,899 |
) |
34.38 |
|
(479,333 |
) |
31.35 |
|
Outstanding, End of Year |
|
1,685,036 |
|
38.79 |
|
4,766,329 |
|
31.24 |
|
During the year, the Company recorded compensation costs of $43 million related to the outstanding PSUs (2006 $27 million; 2005 $91 million).
At December 31, 2007, EnCana had approximately 2.6 million Common Shares held in trust for issuance upon vesting of the PSUs (2006 5.5 million).
F) Share Appreciation Rights
EnCana has in place a program whereby certain employees are granted Share Appreciation Rights (SARs) which entitle the employee to receive a cash payment equal to the excess of the market price of EnCanas Common Shares at the time of exercise over the exercise price of the right. SARs granted generally expire after five years with the exception of a limited number that expire after seven years.
The Company has not granted any SARs after 2002. There are no outstanding SARs at December 31, 2007.
The following tables summarize the information about the SARs:
|
|
2007 |
|
2006 |
|
||||
As at December 31 |
|
Outstanding |
|
Weighted |
|
Outstanding |
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
Canadian Dollar Denominated (C$) |
|
|
|
|
|
|
|
|
|
Outstanding, Beginning of Year |
|
- |
|
- |
|
246,739 |
|
23.13 |
|
Exercised |
|
- |
|
- |
|
(246,739 |
) |
23.13 |
|
Forfeited |
|
- |
|
- |
|
- |
|
- |
|
Outstanding, End of Year |
|
- |
|
- |
|
- |
|
- |
|
Exercisable, End of Year |
|
- |
|
- |
|
- |
|
- |
|
|
|
|
|
|
|
|
|
|
|
U.S. Dollar Denominated (US$) |
|
|
|
|
|
|
|
|
|
Outstanding, Beginning of Year |
|
2,088 |
|
14.21 |
|
319,511 |
|
14.33 |
|
Exercised |
|
(2,088 |
) |
14.21 |
|
(317,423 |
) |
14.33 |
|
Outstanding, End of Year |
|
- |
|
- |
|
2,088 |
|
14.21 |
|
Exercisable, End of Year |
|
- |
|
- |
|
2,088 |
|
14.21 |
|
During the year, the Company has not recorded any compensation costs related to the outstanding SARs (2006 reduction of compensation costs of $1 million; 2005 compensation costs of $17 million).
36
NOTE 18. Financial Instruments and Risk Management
As a means of managing commodity price volatility, EnCana has entered into various financial instrument agreements and physical contracts. The following information presents all positions for financial instruments.
The following tables summarize the realized and unrealized gains and losses on risk management activities:
|
|
|
|
Realized Gain (Loss) |
|
|||||||
For the years ended December 31 |
|
|
|
2007 |
|
2006 |
|
2005 |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Revenues, Net of Royalties |
|
|
|
$ |
1,601 |
|
$ |
393 |
|
$ |
(684 |
) |
Operating Expenses and Other |
|
|
|
3 |
|
5 |
|
31 |
|
|||
Gain (Loss) on Risk Management Continuing Operations |
|
|
|
1,604 |
|
398 |
|
(653 |
) |
|||
Gain (Loss) on Risk Management Discontinued Operations |
|
|
|
- |
|
12 |
|
(155 |
) |
|||
|
|
|
|
$ |
1,604 |
|
$ |
410 |
|
$ |
(808 |
) |
|
|
|
|
Unrealized Gain (Loss) |
|
|||||||
For the years ended December 31 |
|
|
|
2007 |
|
2006 |
|
2005 |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Revenues, Net of Royalties |
|
|
|
$ |
(1,239 |
) |
$ |
2,050 |
|
$ |
(466 |
) |
Operating Expenses and Other |
|
|
|
4 |
|
10 |
|
(3 |
) |
|||
Gain (Loss) on Risk Management Continuing Operations |
|
|
|
(1,235 |
) |
2,060 |
|
(469 |
) |
|||
Gain (Loss) on Risk Management Discontinued Operations |
|
|
|
- |
|
20 |
|
50 |
|
|||
|
|
|
|
$ |
(1,235 |
) |
$ |
2,080 |
|
$ |
(419 |
) |
Fair Value of Outstanding Risk Management Positions
The following table presents a reconciliation of the change in the unrealized amounts during 2007:
|
|
|
|
Fair |
|
Total |
|
||
|
|
|
|
|
|
|
|
||
Fair Value of Contracts, Beginning of Year |
|
|
|
$ |
1,416 |
|
|
|
|
Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered into During 2007 |
|
|
|
353 |
|
$ |
353 |
|
|
Fair Value of Contracts in Place at Transition that Expired During 2007 |
|
|
|
- |
|
16 |
|
||
Foreign Exchange Gains on Canadian Dollar Contracts |
|
|
|
2 |
|
- |
|
||
Fair Value of Contracts Realized During 2007 |
|
|
|
(1,604 |
) |
(1,604 |
) |
||
Fair Value of Contracts, End of Year |
|
|
|
$ |
167 |
|
$ |
(1,235 |
) |
At December 31, 2007, the risk management amounts are recorded in the Consolidated Balance Sheet as follows:
As at December 31 |
|
|
|
2007 |
|
2006 |
|
|||
|
|
|
|
|
|
|
|
|||
Risk Management |
|
|
|
|
|
|
|
|||
Current asset |
|
|
|
$ |
385 |
|
$ |
1,403 |
|
|
Long-term asset |
|
|
|
18 |
|
133 |
|
|||
Current liability |
|
|
|
207 |
|
14 |
|
|||
Long-term liability |
|
|
|
29 |
|
2 |
|
|||
Net Risk Management Asset |
|
|
|
$ |
167 |
|
$ |
|
1,520 |
|
37
Unrealized Fair Value Positions
A summary of all unrealized estimated fair value financial positions is as follows:
As at December 31 |
|
Note |
|
2007 |
|
2006 |
|
||
|
|
|
|
|
|
|
|
||
Commodity Price Risk |
|
A |
|
|
|
|
|
||
Natural gas |
|
|
|
$ |
346 |
|
$ |
1,431 |
|
Crude oil |
|
|
|
(199 |
) |
74 |
|
||
Power |
|
|
|
19 |
|
13 |
|
||
Interest Rate Risk |
|
B |
|
2 |
|
4 |
|
||
Credit Derivatives |
|
C |
|
(1 |
) |
(2 |
) |
||
Total Fair Value |
|
|
|
$ |
167 |
|
$ |
1,520 |
|
A) Commodity Price Risk
Natural Gas
At December 31, 2007 the Companys natural gas risk management activities from financial contracts had an unrealized gain and a fair market value position of $346 million. Details of the contracts are as follows:
|
|
Notional |
|
Term |
|
Average Price |
|
Fair |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Price Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX Fixed Price |
|
1,583 |
|
2008 |
|
8.21 |
|
US$/Mcf |
|
$ |
303 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
191 |
|
2008 |
|
(0.78 |
) |
US$/Mcf |
|
1 |
|
|
United States |
|
1,049 |
|
2008 |
|
(1.02 |
) |
US$/Mcf |
|
65 |
|
|
Canada and United States* |
|
|
|
2009-2011 |
|
|
|
US$/Mcf |
|
(23 |
) |
|
Total Fair Value Positions |
|
|
|
|
|
|
|
|
|
$ |
346 |
|
*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.
Crude Oil
As at December 31, 2007, the Companys crude oil risk management activities from financial contracts had an unrealized loss and a fair market value position of $(199) million. Details of the contracts are as follows:
|
|
Notional |
|
Term |
|
Average Price |
|
Fair |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Price Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX Fixed Price |
|
23,000 |
|
2008 |
|
70.13 |
|
US$/bbl |
|
$ |
(188 |
) |
|
|
|
|
|
|
|
|
|
|
(188 |
) |
|
Other Financial Positions (1) |
|
|
|
|
|
|
|
|
|
(11 |
) |
|
Total Fair Value Positions |
|
|
|
|
|
|
|
|
|
$ |
(199 |
) |
(1) Other financial positions are part of the daily ongoing operations of the Companys proprietary production management.
Power
The Company has in place two Canadian dollar denominated derivative contracts, commencing January 1, 2007 for a period of 11 years, to manage its electricity consumption costs. At December 31, 2007, these contracts had an unrealized gain and a fair market value position of $19 million.
38
B) Interest Rate Risk
The Company has entered into various derivative contracts to manage the Companys interest rate exposure on debt instruments. The impact of these transactions is described in Note 7.
The unrealized gains on the outstanding financial instruments were as follows:
|
|
Unrealized Gain |
|
||||
As at December 31 |
|
2007 |
|
2006 |
|
||
|
|
|
|
|
|
||
5.80% medium term note due June 2, 2008 |
|
$ |
2 |
|
$ |
4 |
|
At December 31, 2007, the increase or decrease in net earnings for each one percent change in interest rates on floating rate debt amounts to $14 million (2006 $11 million; 2005 $10 million).
C) Credit Risk
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. The Board of Directors has approved a credit policy governing the Companys credit portfolio and procedures are in place to ensure adherence to this policy.
With respect to counterparties to financial instruments, the Company partially mitigates associated credit risk by limiting transactions to counterparties with investment grade credit ratings and net settlements where appropriate. At December 31, 2007, EnCana had one counterparty whose net settlement position individually accounts for more than 10 percent of the fair value of the outstanding in-the-money net financial instrument contracts by counterparty.
All foreign currency agreements are with major financial institutions in Canada and the United States or with counterparties having investment grade credit ratings.
D) Fair Value of Financial Assets and Liabilities
The fair values of cash and cash equivalents, accounts receivable and accounts payable approximate their carrying amount due to the short-term maturity of those instruments.
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 that would be available to the Company at year end.
The fair values of the partnership contribution receivable and partnership contribution payable approximate their carrying amount due to the specific nature of these instruments in relation to the creation of the integrated oil joint venture. Further information about these notes is included in Note 10.
As at December 31 |
|
2007 |
|
2006 |
|
||||||||
|
|
Carrying |
|
Fair |
|
Carrying |
|
Fair |
|
||||
|
|
|
|
|
|
|
|
|
|
||||
Financial Assets* |
|
|
|
|
|
|
|
|
|
||||
Held-for-Trading: |
|
|
|
|
|
|
|
|
|
||||
Cash and cash equivalents |
|
$ |
553 |
|
$ |
553 |
|
$ |
402 |
|
$ |
402 |
|
Loans and Receivables: |
|
|
|
|
|
|
|
|
|
||||
Accounts receivable and accrued revenues |
|
2,381 |
|
2,381 |
|
1,721 |
|
1,721 |
|
||||
Partnership Contribution Receivable, including current portion |
|
3,444 |
|
3,444 |
|
- |
|
- |
|
||||
|
|
|
|
|
|
|
|
|
|
||||
Financial Liabilities* |
|
|
|
|
|
|
|
|
|
||||
Other Financial Liabilities: |
|
|
|
|
|
|
|
|
|
||||
Accounts payable and accrued liabilities |
|
$ |
3,982 |
|
$ |
3,982 |
|
$ |
2,494 |
|
$ |
2,494 |
|
Long-Term Debt, including current portion |
|
9,543 |
|
9,763 |
|
6,834 |
|
6,965 |
|
||||
Partnership Contribution Payable, including current portion |
|
3,451 |
|
3,451 |
|
- |
|
- |
|
* Risk management assets and liabilities, which are classified as Held-for-Trading, are previously disclosed in this note.
39
NOTE 19. Supplementary Information
A) Per Share Amounts
The following table summarizes the Common Shares used in calculating Net Earnings per Common Share:
For the years ended December 31 |
|
2007 |
|
2006 |
|
2005 |
|
|
|
|
|
|
|
|
|
Weighted Average Common Shares Outstanding Basic |
|
756.8 |
|
819.9 |
|
868.3 |
|
Effect of Stock Options and Other Dilutive Securities |
|
7.8 |
|
16.6 |
|
20.9 |
|
Weighted Average Common Shares Outstanding Diluted |
|
764.6 |
|
836.5 |
|
889.2 |
|
Information related to Common Shares and stock options has been restated to reflect the effect of the Common Share split approved in April 2005.
B) Net Change in Non-Cash Working Capital from Continuing Operations
For the years ended December 31 |
|
2007 |
|
2006 |
|
2005 |
|
|||
|
|
|
|
|
|
|
|
|||
Operating Activities |
|
|
|
|
|
|
|
|||
Accounts receivable and accrued revenues |
|
$ |
33 |
|
$ |
3,128 |
|
$ |
(146 |
) |
Inventories |
|
42 |
|
(75 |
) |
(34 |
) |
|||
Accounts payable and accrued liabilities |
|
(78 |
) |
(260 |
) |
654 |
|
|||
Income tax payable |
|
(5 |
) |
550 |
|
23 |
|
|||
|
|
$ |
(8 |
) |
$ |
3,343 |
|
$ |
497 |
|
|
|
|
|
|
|
|
|
|||
Investing Activities |
|
|
|
|
|
|
|
|||
Accounts payable and accrued liabilities |
|
$ |
86 |
|
$ |
19 |
|
$ |
330 |
|
C) Supplementary Cash Flow Information Continuing Operations
For the years ended December 31 |
|
2007 |
|
2006 |
|
2005 |
|
|||
|
|
|
|
|
|
|
|
|||
Interest Paid |
|
$ |
422 |
|
$ |
341 |
|
$ |
522 |
|
Income Taxes Paid |
|
$ |
1,423 |
|
$ |
450 |
|
$ |
1,096 |
|
NOTE 20. Commitments and Contingencies
Commitments
As at December 31, 2007 |
|
2008 |
|
2009 |
|
2010 |
|
2011 |
|
2012 |
|
Thereafter |
|
Total |
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Pipeline Transportation |
|
$ |
527 |
|
$ |
479 |
|
$ |
454 |
|
$ |
483 |
|
$ |
419 |
|
$ |
2,222 |
|
$ |
4,584 |
|
Purchases of Goods and Services |
|
404 |
|
240 |
|
147 |
|
144 |
|
108 |
|
621 |
|
1,664 |
|
|||||||
Product Purchases |
|
24 |
|
24 |
|
24 |
|
23 |
|
- |
|
98 |
|
193 |
|
|||||||
Operating Leases* |
|
70 |
|
74 |
|
78 |
|
210 |
|
209 |
|
3,402 |
|
4,043 |
|
|||||||
Capital Commitments |
|
54 |
|
10 |
|
3 |
|
130 |
|
3 |
|
39 |
|
239 |
|
|||||||
Other Long-Term Commitments |
|
18 |
|
10 |
|
6 |
|
3 |
|
- |
|
1 |
|
38 |
|
|||||||
Total |
|
$ |
1,097 |
|
$ |
837 |
|
$ |
712 |
|
$ |
993 |
|
$ |
739 |
|
$ |
6,383 |
|
$ |
10,761 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Product Sales |
|
$ |
51 |
|
$ |
47 |
|
$ |
49 |
|
$ |
51 |
|
$ |
55 |
|
$ |
244 |
|
$ |
497 |
|
*Operating leases consist of building leases, including The Bow (See Note 4).
In addition to the above, the Company has made commitments related to its risk management program (See Note 18).
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.
40
Discontinued Merchant Energy Operations
During the period between 2003 and 2005, EnCana and its indirect wholly owned U.S. marketing subsidiary, WD Energy Services Inc. (WD), along with other energy companies, were named as defendants in several lawsuits, some of which were class action lawsuits, relating to sales of natural gas from 1999 to 2002. The lawsuits allege that the defendants engaged in a conspiracy with unnamed competitors in the natural gas markets in California in violation of U.S. and California anti-trust and unfair competition laws.
Without admitting any liability in the lawsuits, WD agreed to settle all of the class action lawsuits in both state and federal court for payment of $20.5 million and $2.4 million, respectively. Also, as previously disclosed, without admitting any liability whatsoever, WD concluded settlements with the U.S. Commodity Futures Trading Commission (CFTC), for $20 million and of a previously disclosed consolidated class action lawsuit in the United States District Court in New York for $8.2 million.
The remaining lawsuits were commenced by individual plaintiffs, one of which is E. & J. Gallo Winery (Gallo). The Gallo lawsuit claims damages in excess of $30 million. The other remaining lawsuits do not specify the precise amount of damages claimed. California law allows for the possibility that the amount of damages assessed could be tripled.
The Company and WD intend to vigorously defend against the outstanding claims; however, the Company cannot predict the outcome of these proceedings or any future proceedings against the Company, whether these proceedings would lead to monetary damages which could have a material adverse effect on the Companys financial position, or whether there will be other proceedings arising out of these allegations.
Asset Retirement
EnCana is responsible for the retirement of long-lived assets related to its oil and gas properties, refining facilities and Midstream facilities at the end of their useful lives. The Company has recognized a liability of $1,458 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.
NOTE 21. Subsequent Events
On January 18, 2008, EnCana completed a public offering in Canada of senior unsecured medium term notes in the aggregate principal amount of C$750 million. The notes have a coupon rate of 5.80 percent and mature on January 18, 2018. The net proceeds of the offering were used to repay a portion of EnCanas existing bank and commercial paper indebtedness.
NOTE 22. 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.
41
Reconciliation of Net Earnings Under Canadian GAAP to U.S. GAAP
For the years ended December 31 |
|
Note |
|
2007 |
|
2006 |
|
2005 |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Net Earnings Canadian GAAP |
|
|
|
$ |
3,959 |
|
$ |
5,652 |
|
$ |
3,426 |
|
Less: |
|
|
|
|
|
|
|
|
|
|||
Net Earnings From Discontinued Operations Canadian GAAP |
|
|
|
75 |
|
601 |
|
597 |
|
|||
Net Earnings From Continuing Operations Canadian GAAP |
|
|
|
3,884 |
|
5,051 |
|
2,829 |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Increase (Decrease) in Net Earnings From Continuing Operations Under U.S. GAAP: |
|
|
|
|
|
|
|
|
|
|||
Revenues, net of royalties |
|
A |
|
(15 |
) |
179 |
|
(217 |
) |
|||
Operating |
|
A, D ii) |
|
3 |
|
(15 |
) |
1 |
|
|||
Depreciation, depletion and amortization |
|
B, D ii) |
|
86 |
|
95 |
|
55 |
|
|||
Administrative |
|
D ii) |
|
1 |
|
(8 |
) |
- |
|
|||
Interest, net |
|
A |
|
(2 |
) |
(15 |
) |
(16 |
) |
|||
Stock-based compensation options |
|
C |
|
(5 |
) |
- |
|
(12 |
) |
|||
Income tax expense |
|
E |
|
(204 |
) |
(80 |
) |
59 |
|
|||
Net Earnings From Continuing Operations U.S. GAAP |
|
|
|
3,748 |
|
5,207 |
|
2,699 |
|
|||
Net Earnings From Discontinued Operations U.S. GAAP |
|
|
|
75 |
|
644 |
|
553 |
|
|||
Net Earnings Before Change in Accounting Policy U.S. GAAP |
|
|
|
3,823 |
|
5,851 |
|
3,252 |
|
|||
Cumulative Effect of Change in Accounting Policy, net of tax |
|
D ii) |
|
- |
|
(15 |
) |
- |
|
|||
Net Earnings U.S. GAAP |
|
|
|
$ |
3,823 |
|
$ |
5,836 |
|
$ |
3,252 |
|
|
|
|
|
|
|
|
|
|
|
|||
Net Earnings per
Common Share Before Change in |
|
|
|
|
|
|
|
|
|
|||
Basic |
|
|
|
$ |
5.05 |
|
$ |
7.14 |
|
$ |
3.75 |
|
Diluted |
|
|
|
$ |
5.00 |
|
$ |
6.99 |
|
$ |
3.66 |
|
Net Earnings per Common Share Including Cumulative Effect of Change in Accounting Policy U.S. GAAP |
|
|
|
|
|
|
|
|
|
|||
Basic |
|
|
|
$ |
5.05 |
|
$ |
7.12 |
|
$ |
3.75 |
|
Diluted |
|
|
|
$ |
5.00 |
|
$ |
6.98 |
|
$ |
3.66 |
|
42
Consolidated Statement of Earnings - U.S. GAAP
For the years ended December 31 |
|
Note |
|
2007 |
|
2006 |
|
2005 |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Revenues, Net of Royalties |
|
A |
|
$ |
21,431 |
|
$ |
16,578 |
|
$ |
14,356 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|||
Production and mineral taxes |
|
|
|
291 |
|
349 |
|
453 |
|
|||
Transportation and selling |
|
|
|
1,010 |
|
1,070 |
|
845 |
|
|||
Operating |
|
A, D ii) |
|
2,275 |
|
1,670 |
|
1,437 |
|
|||
Purchased product |
|
|
|
8,583 |
|
2,862 |
|
4,159 |
|
|||
Depreciation, depletion and amortization |
|
B, D ii) |
|
3,730 |
|
3,017 |
|
2,714 |
|
|||
Administrative |
|
D ii) |
|
383 |
|
279 |
|
268 |
|
|||
Interest, net |
|
A |
|
430 |
|
411 |
|
540 |
|
|||
Accretion of asset retirement obligation |
|
|
|
64 |
|
50 |
|
37 |
|
|||
Foreign exchange (gain) loss, net |
|
|
|
(164 |
) |
14 |
|
(24 |
) |
|||
Stock-based compensation options |
|
C |
|
5 |
|
- |
|
27 |
|
|||
(Gain) on divestitures |
|
|
|
(65 |
) |
(323 |
) |
- |
|
|||
Net Earnings Before Income Tax |
|
|
|
4,889 |
|
7,179 |
|
3,900 |
|
|||
Income tax expense |
|
E |
|
1,141 |
|
1,972 |
|
1,201 |
|
|||
Net Earnings From Continuing Operations U.S. GAAP |
|
|
|
3,748 |
|
5,207 |
|
2,699 |
|
|||
Net Earnings From Discontinued Operations U.S. GAAP |
|
|
|
75 |
|
644 |
|
553 |
|
|||
Net Earnings Before Change in Accounting Policy U.S. GAAP |
|
|
|
3,823 |
|
5,851 |
|
3,252 |
|
|||
Cumulative Effect of Change in Accounting Policy, net of tax |
|
D ii) |
|
- |
|
(15 |
) |
- |
|
|||
Net Earnings U.S. GAAP |
|
|
|
$ |
3,823 |
|
$ |
5,836 |
|
$ |
3,252 |
|
|
|
|
|
|
|
|
|
|
|
|||
Net Earnings From Continuing Operations per Common Share U.S. GAAP |
|
|
|
|
|
|
|
|
|
|||
Basic |
|
|
|
$ |
4.95 |
|
$ |
6.35 |
|
$ |
3.11 |
|
Diluted |
|
|
|
$ |
4.90 |
|
$ |
6.22 |
|
$ |
3.04 |
|
Net Earnings From Discontinued Operations per Common Share U.S. GAAP |
|
|
|
|
|
|
|
|
|
|||
Basic |
|
|
|
$ |
0.10 |
|
$ |
0.79 |
|
$ |
0.64 |
|
Diluted |
|
|
|
$ |
0.10 |
|
$ |
0.77 |
|
$ |
0.62 |
|
Net Earnings per
Common Share Before Change in |
|
|
|
|
|
|
|
|
|
|||
Basic |
|
|
|
$ |
5.05 |
|
$ |
7.14 |
|
$ |
3.75 |
|
Diluted |
|
|
|
$ |
5.00 |
|
$ |
6.99 |
|
$ |
3.66 |
|
Net Earnings per
Common Share Including Cumulative Effect |
|
|
|
|
|
|
|
|
|
|||
Basic |
|
|
|
$ |
5.05 |
|
$ |
7.12 |
|
$ |
3.75 |
|
Diluted |
|
|
|
$ |
5.00 |
|
$ |
6.98 |
|
$ |
3.66 |
|
Consolidated Statement of Comprehensive Income - U.S. GAAP
For the years ended December 31 |
|
Note |
|
2007 |
|
2006 |
|
2005 |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Net Earnings U.S. GAAP |
|
|
|
$ |
3,823 |
|
$ |
5,836 |
|
$ |
3,252 |
|
Change in Fair Value of Financial Instruments |
|
A, F |
|
- |
|
4 |
|
- |
|
|||
Foreign Currency Translation Adjustment |
|
B, F, D ii) |
|
1,707 |
|
(224 |
) |
573 |
|
|||
Compensation Plans |
|
F |
|
1 |
|
- |
|
- |
|
|||
Comprehensive Income |
|
|
|
$ |
5,531 |
|
$ |
5,616 |
|
$ |
3,825 |
|
Consolidated Statement of Accumulated Other Comprehensive Income - U.S. GAAP
For the years ended December 31 |
|
Note |
|
2007 |
|
2006 |
|
2005 |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Balance, Beginning of Year |
|
|
|
$ |
1,330 |
|
$ |
1,598 |
|
$ |
1,025 |
|
Change in Fair Value of Financial Instruments |
|
A, F |
|
- |
|
4 |
|
- |
|
|||
Foreign Currency Translation Adjustment |
|
B, F |
|
1,707 |
|
(224 |
) |
573 |
|
|||
Compensation Plans |
|
D i), F |
|
1 |
|
(48 |
) |
- |
|
|||
Balance, End of Year |
|
|
|
$ |
3,038 |
|
$ |
1,330 |
|
$ |
1,598 |
|
43
Consolidated Statement of Retained Earnings - U.S. GAAP
For the years ended December 31 |
|
|
|
2007 |
|
2006 |
|
2005 |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Retained Earnings, Beginning of Year |
|
|
|
$ |
11,374 |
|
$ |
9,327 |
|
$ |
7,955 |
|
Net Earnings |
|
|
|
3,823 |
|
5,836 |
|
3,252 |
|
|||
Dividends on Common Shares |
|
|
|
(603 |
) |
(304 |
) |
(238 |
) |
|||
Charges for Normal Course Issuer Bid |
|
|
|
(1,618 |
) |
(3,485 |
) |
(1,642 |
) |
|||
Retained Earnings, End of Year |
|
|
|
$ |
12,976 |
|
$ |
11,374 |
|
$ |
9,327 |
|
Condensed Consolidated Balance Sheet
As at December 31 |
|
|
|
2007 |
|
2006 |
|
||||||||
|
|
Note |
|
As Reported |
|
U.S GAAP |
|
As Reported |
|
U.S. GAAP |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
||||
Assets |
|
|
|
|
|
|
|
|
|
|
|
||||
Current Assets |
|
D i) |
|
$ |
4,444 |
|
$ |
4,446 |
|
$ |
3,702 |
|
$ |
3,703 |
|
Property, Plant
and Equipment |
|
B, D ii) |
|
59,821 |
|
59,729 |
|
45,577 |
|
45,496 |
|
||||
Accumulated Depreciation, Depletion and Amortization |
|
|
|
(23,956 |
) |
(23,669 |
) |
(17,364 |
) |
(17,197 |
) |
||||
Property, Plant
and Equipment, net |
|
|
|
35,865 |
|
36,060 |
|
28,213 |
|
28,299 |
|
||||
Investments and Other Assets |
|
D i) |
|
607 |
|
557 |
|
533 |
|
488 |
|
||||
Partnership Contribution Receivable |
|
|
|
3,147 |
|
3,147 |
|
- |
|
- |
|
||||
Risk Management |
|
|
|
18 |
|
18 |
|
133 |
|
133 |
|
||||
Goodwill |
|
|
|
2,893 |
|
2,893 |
|
2,525 |
|
2,525 |
|
||||
|
|
|
|
$ |
46,974 |
|
$ |
47,121 |
|
$ |
35,106 |
|
$ |
35,148 |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Liabilities and Shareholders Equity |
|
|
|
|
|
|
|
|
|
|
|
||||
Current Liabilities |
|
A, Di), ii), E |
|
$ |
6,330 |
|
$ |
6,574 |
|
$ |
3,691 |
|
$ |
3,742 |
|
Long-Term Debt |
|
|
|
8,840 |
|
8,840 |
|
6,577 |
|
6,577 |
|
||||
Other Liabilities |
|
A, Di) ii) |
|
242 |
|
277 |
|
79 |
|
106 |
|
||||
Partnership Contribution Payable |
|
|
|
3,163 |
|
3,163 |
|
- |
|
- |
|
||||
Risk Management |
|
|
|
29 |
|
29 |
|
2 |
|
2 |
|
||||
Asset Retirement Obligation |
|
|
|
1,458 |
|
1,458 |
|
1,051 |
|
1,051 |
|
||||
Future Income Taxes |
|
E |
|
6,208 |
|
6,172 |
|
6,240 |
|
6,189 |
|
||||
|
|
|
|
26,270 |
|
26,513 |
|
17,640 |
|
17,667 |
|
||||
Share Capital |
|
C |
|
|
|
|
|
|
|
|
|
||||
Common Shares, no par value |
|
|
|
4,479 |
|
4,514 |
|
4,587 |
|
4,617 |
|
||||
Outstanding: 2007 750.2 million shares |
|
|
|
|
|
|
|
|
|
|
|
||||
2006 777.9 million shares |
|
|
|
|
|
|
|
|
|
|
|
||||
Paid in Surplus |
|
|
|
80 |
|
80 |
|
160 |
|
160 |
|
||||
Retained Earnings |
|
|
|
13,082 |
|
12,976 |
|
11,344 |
|
11,374 |
|
||||
Accumulated Other Comprehensive Income |
|
F |
|
3,063 |
|
3,038 |
|
1,375 |
|
1,330 |
|
||||
|
|
|
|
20,704 |
|
20,608 |
|
17,466 |
|
17,481 |
|
||||
|
|
|
|
$ |
46,974 |
|
$ |
47,121 |
|
$ |
35,106 |
|
$ |
35,148 |
|
44
Condensed Consolidated Statement of Cash Flows U.S. GAAP
For the years ended December 31 |
|
2007 |
|
2006 |
|
2005 |
|
|||
|
|
|
|
|
|
|
|
|||
Operating Activities |
|
|
|
|
|
|
|
|||
Net earnings from continuing operations |
|
$ |
3,748 |
|
$ |
5,207 |
|
$ |
2,699 |
|
Depreciation, depletion and amortization |
|
3,730 |
|
3,017 |
|
2,714 |
|
|||
Future income taxes |
|
(592 |
) |
1,030 |
|
(4 |
) |
|||
Unrealized (gain) loss on risk management |
|
1,251 |
|
(2,229 |
) |
668 |
|
|||
Unrealized foreign exchange (gain) loss |
|
41 |
|
- |
|
(126 |
) |
|||
Accretion of asset retirement obligation |
|
64 |
|
50 |
|
37 |
|
|||
(Gain) on divestitures |
|
(65 |
) |
(323 |
) |
- |
|
|||
Other |
|
97 |
|
242 |
|
250 |
|
|||
Cash flow from discontinued operations |
|
- |
|
118 |
|
464 |
|
|||
Net change in other assets and liabilities |
|
(16 |
) |
138 |
|
(281 |
) |
|||
Net change in non-cash working capital from continuing operations |
|
(8 |
) |
3,343 |
|
497 |
|
|||
Net change in non-cash working capital from discontinued operations |
|
- |
|
(2,669 |
) |
(187 |
) |
|||
Cash From Operating Activities |
|
$ |
8,250 |
|
$ |
7,924 |
|
$ |
6,731 |
|
|
|
|
|
|
|
|
|
|||
Cash (Used in) Investing Activities |
|
$ |
(8,175 |
) |
$ |
(3,333 |
) |
$ |
(3,942 |
) |
|
|
|
|
|
|
|
|
|||
Cash (Used in) From Financing Activities |
|
$ |
(119 |
) |
$ |
(4,294 |
) |
$ |
(3,275 |
) |
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 will be recognized into earnings when realized. As at December 31, 2007, under Canadian GAAP, the remaining transition amount has been fully recognized into net earnings resulting in a $15 million decrease to revenue and $1 million increase to interest.
For U.S. GAAP, the Company adopted Statement of Financial Accounting Standards (SFAS) 133 effective January 1, 2001. SFAS 133 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 under SFAS 133.
Unrealized gain (loss) on derivatives relate to:
For the years ended December 31 |
|
2007 |
|
2006 |
|
2005 |
|
|||
|
|
|
|
|
|
|
|
|||
Commodity Prices (Revenues, net of royalties) |
|
$ |
(1,249 |
) |
$ |
2,327 |
|
$ |
(703 |
) |
Interest and Currency Swaps (Interest, net) |
|
(2 |
) |
(11 |
) |
(9 |
) |
|||
Total Unrealized Gain (Loss) |
|
$ |
(1,251 |
) |
$ |
2,316 |
|
$ |
(712 |
) |
|
|
|
|
|
|
|
|
|||
Amounts Allocated to Continuing Operations |
|
$ |
(1,251 |
) |
$ |
2,229 |
|
$ |
(668 |
) |
Amounts Allocated to Discontinued Operations |
|
- |
|
87 |
|
(44 |
) |
|||
|
|
$ |
(1,251 |
) |
$ |
2,316 |
|
$ |
(712 |
) |
As at December 31, 2007, it is estimated that over the following 12 months, $3.0 million ($2.0 million, net of tax) of the remaining SFAS 133 transition amount, will be reclassified into net earnings from other comprehensive income.
45
B) Full Cost Accounting
The full cost method of accounting for crude oil and natural gas operations under Canadian GAAP and U.S. GAAP differ in the following respects. Under U.S. GAAP, a ceiling test is applied to ensure the unamortized capitalized costs in each cost centre do not exceed the sum of the present value, discounted at 10 percent, of the estimated unescalated future net operating revenue from proved reserves plus unimpaired unproved property costs less future development costs, related production costs and applicable taxes. Depletion charges under U.S. GAAP are calculated by reference to proved reserves estimated using constant prices. 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 to determine whether impairment exists. Any impairment amount is measured using the fair value of proved and probable reserves. Depletion charges under Canadian GAAP are calculated by reference to proved reserves estimated using estimated future prices and costs. The U.S. GAAP adjustment results in an impact to depreciation, depletion, and amortization charges and foreign currency translation adjustment of $85.4 million decrease and $2.9 million increase respectively (2006 $97 million decrease and $1.2 million decrease; 2005 $54.8 million decrease and $1 million increase).
In computing its consolidated net earnings for U.S. GAAP purposes, the Company recorded additional depletion in 2001 and certain years prior to 2001 as a result of the application of the ceiling test. These charges were not required under the Canadian GAAP ceiling tests. As a result, the depletion base of unamortized capitalized costs is less for U.S. GAAP purposes.
C) Stock-Based Compensation CPL Reorganization
Under Canadian GAAP, compensation costs have been recognized in the financial statements for stock options granted to employees and directors in 2003. For the effect of stock-based compensation on the Canadian GAAP financial statements, which would be the same adjustment under U.S. GAAP, see Note 16.
Under Financial Accounting Standards Board (FASB) Interpretation (FIN) No. 44, Accounting for Certain Transactions Involving Stock Compensation, 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 which resulted in CPL stock options being replaced with stock options granted by EnCana, as described in Note 16. 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, SFAS 158, Employers Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R). SFAS 158 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 currently does not require the Company to recognize the funded status of these plans on its balance sheet.
ii) Tandem Share Appreciation Rights and Deferred Share Units
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 SFAS 123(R), Share-Based Payment for the year ended December 31, 2006 using the modified-prospective approach. Under SFAS 123(R), the intrinsic-method of accounting for liability-based stock compensation plans is no longer an alternative. Liability-based stock compensation plans, including tandem share appreciation rights and deferred share units, are now required to be re-measured at fair value at each reporting period up until the settlement date.
46
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. As a result:
· Net capital assets are lower by $8.4 million (2006 $22.8 million higher)
· Current liabilities are lower by $10.8 million (2006 $45.2 million higher)
· Other liabilities are lower by $2.8 million (2006 $0.4 million higher)
· Other comprehensive income is higher by $0.5 million (2006 $1.1 million higher)
· Operating expenses are lower by $3.3 million (2006 $13.9 million higher)
· Administrative expenses are $0.5 million lower (2006 $7.7 million higher)
· Depreciation, depletion and amortization expenses are $0.9 million lower (2006 $2.3 million higher)
As the Company adopted SFAS 123(R) using the modified prospective approach, prior periods have not been restated, as required by the standard.
SFAS 123(R), under the modified prospective approach, requires the cumulative impact of a change in an accounting policy to be presented in the current year Consolidated Statement of Earnings. The cumulative effect, net of tax, of initially adopting SFAS 123(R) January 1, 2006 was a loss of $15 million.
E) Income Taxes
Under U.S. GAAP, enacted tax rates are used to calculate current and future income taxes, whereas Canadian GAAP uses substantively enacted tax rates. 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. The result is an increase to income tax expense of $179 million (2006 nil, 2005 nil) 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 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 |
|
2007 |
|
2006 |
|
2005 |
|
|||
|
|
|
|
|
|
|
|
|||
Net Earnings Before Income Tax U.S. GAAP |
|
$ |
4,889 |
|
$ |
7,179 |
|
$ |
3,900 |
|
Canadian Statutory Rate |
|
32.3 |
% |
34.7 |
% |
37.9 |
% |
|||
Expected Income Tax |
|
1,579 |
|
2,491 |
|
1,478 |
|
|||
Effect on Taxes Resulting from: |
|
|
|
|
|
|
|
|||
Non-deductible Canadian Crown payments |
|
- |
|
97 |
|
207 |
|
|||
Canadian resource allowance |
|
- |
|
(16 |
) |
(202 |
) |
|||
Statutory and other rate differences |
|
76 |
|
(98 |
) |
(235 |
) |
|||
Effect of tax rate changes |
|
(301 |
) |
(457 |
) |
- |
|
|||
Non-taxable downstream partnership income |
|
(70 |
) |
- |
|
- |
|
|||
Non-taxable capital gains |
|
(124 |
) |
(1 |
) |
(24 |
) |
|||
Tax basis retained on divestitures |
|
- |
|
- |
|
(68 |
) |
|||
Large corporations tax |
|
- |
|
- |
|
25 |
|
|||
Other |
|
(19 |
) |
(44 |
) |
20 |
|
|||
Income Tax U.S. GAAP |
|
$ |
1,141 |
|
$ |
1,972 |
|
$ |
1,201 |
|
Effective Tax Rate |
|
23.3 |
% |
27.5 |
% |
30.7 |
% |
47
The net future income tax liability is comprised of:
As at December 31 |
|
2007 |
|
2006 |
|
||
|
|
|
|
|
|
||
Future Tax Liabilities |
|
|
|
|
|
||
Property, plant and equipment in excess of tax values |
|
$ |
5,340 |
|
$ |
4,632 |
|
Timing of partnership items |
|
961 |
|
1,251 |
|
||
Other |
|
- |
|
317 |
|
||
|
|
|
|
|
|
||
Future Tax Assets |
|
|
|
|
|
||
Non-capital and net operating losses carried forward |
|
(6 |
) |
(11 |
) |
||
Other |
|
(123 |
) |
- |
|
||
Net Future Income Tax Liability |
|
$ |
6,172 |
|
$ |
6,189 |
|
F) Other Comprehensive Income
U.S. GAAP requires the disclosure, as other comprehensive income, of changes in equity during the period from transaction and other events from non-owner sources. Other comprehensive income arose from the transition adjustment resulting from the January 1, 2001 adoption of SFAS 133. At December 31, 2007, accumulated other comprehensive income related to these items was a loss of $2 million, net of tax.
At December 31, 2006, accumulated other comprehensive income related to the adoption of SFAS 158 was a loss of $48 million, net of tax. At December 31, 2007, other comprehensive income related to SFAS 158, as noted in D i) was a gain of $1.2 million, net of tax.
The foreign currency translation adjustment includes the effect of the accumulated U.S. GAAP differences.
G) Joint Venture with ConocoPhillips
Under Canadian GAAP, the Integrated Oil segment is proportionately consolidated. This segment represents the joint venture with ConocoPhillips. Under U.S. GAAP, the Downstream Refining operations included in this segment are to be equity accounted for. Equity accounting for the Downstream Refining operations would have no impact on EnCanas net earnings or retained earnings. As required, the following disclosures are provided for the Downstream Refining operations of the joint venture.
Income Statement |
|
|
|
|
For the year ended December 31 |
|
2007 |
|
|
|
|
|
|
|
Operating Cash Flow (See Note 4) |
|
$ |
1,074 |
|
Depreciation, depletion and amortization |
|
(159 |
) |
|
Other |
|
(5 |
) |
|
Net Income |
|
$ |
910 |
|
Balance Sheet |
|
|
|
|
As at December 31 |
|
2007 |
|
|
|
|
|
|
|
Current Assets |
|
$ |
1,172 |
|
Long-term Assets |
|
3,851 |
|
|
Current Liabilities |
|
644 |
|
|
Long-term Liabilities |
|
21 |
|
|
|
|
|
|
|
Statement of Cash Flows |
|
|
|
|
For the year ended December 31 |
|
2007 |
|
|
|
|
|
|
|
Cash From Operating Activities |
|
$ |
885 |
|
Cash (Used in) Investing Activities |
|
(322 |
) |
|
Cash (Used in) From Financing Activities |
|
- |
|
48
H) 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. Interest from early retirement of long-term debt included as a financing activity under Canadian GAAP is presented under operating activities under U.S GAAP.
I) Dividends Declared on Common Stock
For the years ended December 31 |
|
2007 |
|
2006 |
|
2005 |
|
|||
|
|
|
|
|
|
|
|
|||
Dividends per share |
|
$ |
0.80 |
|
$ |
0.375 |
|
$ |
0.275 |
|
J) Recent Accounting Pronouncements
As of January 1, 2007, EnCana adopted, for U.S. GAAP purposes, FASB Interpretation No. 48 Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109. This Interpretation clarifies financial statement recognition and disclosure requirements for uncertain tax positions taken or expected to be taken in a tax return. Guidance is also provided on the derecognition of previously recognized tax benefits and the classification of tax liabilities on the balance sheet. The adoption of this interpretation did not have a material impact on EnCanas Consolidated Financial Statements.
The Company has assessed new and revised accounting pronouncements that have been issued that are not yet effective and determined that the following may have a significant impact on the Company:
· As of January 1, 2008, EnCana will be required to adopt, for U.S. GAAP purposes, SFAS 157, Fair Value Measurements. SFAS 157 provides a common definition of fair value, establishes a framework for measuring fair value under U.S. GAAP and expands disclosures about fair value measurements. This standard applies when other accounting pronouncements require fair value measurements and does not require new fair value measurements. The adoption of this standard should not have a material impact on EnCanas Consolidated Financial Statements.
· As of January 1, 2008, EnCana will be required to adopt, for U.S. GAAP purposes, measurement requirements under SFAS 158, Employers Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R). This standard also requires EnCana to measure the funded status of a plan as of the balance sheet date. The adoption of the change in measurement date should not have a material impact on EnCanas Consolidated Financial Statements.
· As of January 1, 2009, EnCana will be required to adopt, for U.S. GAAP purposes, SFAS 141(R), Business Combinations, which replaces SFAS 141. 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-related and restructuring costs are to be recognized separately from the business combination. The adoption of this standard will impact EnCanas U.S. GAAP accounting treatment of business combinations entered into after January 1, 2009.
· As of January 1, 2009, EnCana will be required to adopt, for U.S. GAAP purposes, SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB No. 51. 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 should not have a material impact on EnCanas Consolidated Financial Statements.
49
Certifications and Disclosure Regarding Controls and Procedures.
It should be noted that while the registrant's principal executive officer and principal financial officer believe that the registrant's disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the registrant's 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.
40-F2
Notices Pursuant to Regulation BTR.
None.
Audit Committee Financial Expert.
The registrant's board of directors has determined that Jane L. Peverett, a member of the registrant's 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" (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 registrant's 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: Kerry D. Dyte, Vice-President, General Counsel & 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 registrant's Corporate Secretarial Department at (403) 645-2000 (Fax: (403) 645-4617).
Since the adoption of the Code of Ethics, there have not been any amendments to the Code of Ethics or waivers, including implicit waivers, 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 registrant's Annual Information Form for the fiscal year ended December 31, 2007, 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 registrant's Annual Information Form for the fiscal year ended December 31, 2007, filed as part of this Annual Report on Form 40-F.
Off-Balance Sheet Arrangements.
EnCana does not have any off-balance sheet financing arrangements that have or are reasonably likely to have an effect on its results of operations or financial condition.
40-F3
Tabular Disclosure of Contractual Obligations.
The required disclosure is included under the heading "Contractual Obligations and Contingencies" in the registrant's Management's Discussion and Analysis for the fiscal year ended December 31, 2007, 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: Patrick D. Daniel, Barry W. Harrison, Dale A. Lucas, Jane L. Peverett, Allan P. Sawin, James M. Stanford and David P. O'Brien (ex officio).
Disclosure Pursuant to the Requirements of the New York Stock Exchange.
Presiding Director at Meetings of Non-Management Directors
The registrant schedules regular executive sessions in which the registrant's "non-management directors" (as that term is defined in the rules of the New York Stock Exchange) meet without management participation. Mr. David P. O'Brien serves as the presiding director (the "Presiding Director") at such sessions. Each of the registrant's non-management directors is "unrelated" as such term is used in the rules of the Toronto Stock Exchange.
Communication with Non-Management Directors
Shareholders may send communications to the registrant's non-management directors by writing to the Presiding Director, c/o Kerry D. Dyte, Vice-President, General Counsel & 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 company's 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 registrant's Information Circular in connection with its 2007 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.
40-F4
Board Committee Mandates
The Mandates of the registrant's audit committee, human resources and compensation committee, and nominating and corporate governance committee are each available for viewing on the registrant's website at www.encana.com, and are available in print to any shareholder who requests them. Requests for copies of these documents should be made by contacting: Kerry D. Dyte, Vice-President, General Counsel & Corporate Secretary, EnCana Corporation, 1800, 855-2nd Street S.W., P.O. Box 2850, Calgary, Alberta, Canada T2P 2S5. Alternatively, requests for these documents may be made by contacting the registrant's Corporate Secretarial Department at (403) 645-2000 (Fax: (403) 645-4617).
40-F5
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 Securities and Exchange Commission (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 relevant registration statement.
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 22, 2008.
EnCana Corporation | |||
By: |
/s/ THOMAS G. HINTON |
||
Name: | Thomas G. Hinton | ||
Title: | Treasurer | ||
By: |
/s/ GERALD T. INCE |
||
Name: | Gerald T. Ince | ||
Title: | Assistant Treasurer |
40-F6
Exhibit |
Description |
|
---|---|---|
99.1 | Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934 | |
99.2 |
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934 |
|
99.3 |
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350 |
|
99.4 |
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350 |
|
99.5 |
Consent of PricewaterhouseCoopers LLP |
|
99.6 |
Consent of McDaniel & Associates Consultants Ltd. |
|
99.7 |
Consent of Netherland, Sewell & Associates, Inc. |
|
99.8 |
Consent of DeGolyer and MacNaughton |
|
99.9 |
Consent of GLJ Petroleum Consultants Ltd. |