40-F 1 a10-3706_140f.htm 40-F

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UNITED STATES

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

 

 

 

R

 

ANNUAL REPORT PURSUANT TO SECTION 13(a) or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the fiscal year ended: December 31, 2009      Commission File Number:  1-34513

 

CENOVUS ENERGY INC.

(Exact name of Registrant as specified in its charter)

 

Not applicable

(Translation of Registrant’s name into English (if applicable)

 

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))

 

4000, 421-7th Avenue S.W.
Calgary, Alberta, Canada T2P 4K9
(403) 766-2000

(Address and telephone number of Registrant’s principal executive offices)

 

CT Corporation System
111 8th
Avenue
New York, New York 10011

(212) 894-8641

(Name, address (including zip code) and telephone number (including area code)

of agent for service in the United States)

 

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

 

Title of each class

 

Name of each exchange on which registered

 

 

 

Common shares, no par value (together with associated common share purchase rights)

 

New York Stock Exchange

 

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

 

None

(Title of Class)

 



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

 

None

(Title of Class)

 

For Annual Reports indicate by check mark the information filed with this Form:

 

 

R Annual information form      R 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:

 

751,308,563

 

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, please indicate the filing number assigned to the Registrant in connection with such Rule.

 

Yes o 82-

 

 

No R

 

Indicate by check mark whether the Registrant (1) has filed all reports 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 filing requirements for the past 90 days.

 

Yes o   No R

 

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

 

Yes o   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 No. 333-163397).

 

 

40-F-2




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CENOVUS ENERGY INC.

 

 

ANNUAL INFORMATION FORM

 

FOR THE YEAR ENDED DECEMBER 31, 2009

 

 

February 18, 2010

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2009

 



Table of Contents

 

TABLE OF CONTENTS

 

NOTICE TO READER

 

1

CORPORATE STRUCTURE

 

3

Intercorporate Relationships

 

3

GENERAL DEVELOPMENT OF OUR BUSINESS

 

4

The Arrangement

 

4

Our Business

 

5

NARRATIVE DESCRIPTION OF OUR BUSINESS

 

7

Integrated Oil Division

 

8

Canadian Plains Division

 

12

RESERVES AND OTHER OIL AND GAS INFORMATION

 

17

Reserves Quantities Information

 

17

Other Disclosures About Oil and Gas Activities

 

25

Production Volumes and Per-Unit Results

 

28

Drilling Activity

 

33

Location of Wells

 

33

Interest in Material Properties

 

34

Capital Expenditures, Acquisitions and Divestitures

 

35

Delivery Commitments

 

35

GENERAL

 

36

Competitive Conditions

 

36

Environmental Protection

 

36

Social and Environmental Policies

 

37

Employees

 

38

Foreign Operations

 

38

DIRECTORS AND EXECUTIVE OFFICERS

 

39

Directors

 

39

Five Year Occupational History of Directors

 

40

Other Reporting Issuer Experience of Directors

 

42

Executive Officers

 

43

Five Year Occupational History of Executive Officers

 

43

Corporate Cease Trade Orders or Bankruptcies

 

44

Conflicts of Interest

 

45

STATEMENT OF EXECUTIVE COMPENSATION

 

46

Compensation Discussion and Analysis

 

46

Tables

 

52

Director Compensation

 

56

AUDIT COMMITTEE

 

58

Composition of the Audit Committee

 

58

Pre-Approval Policies and Procedures

 

59

External Auditor Service Fees

 

59

STATEMENT OF CORPORATE GOVERNANCE PRACTICES

 

60

Board of Directors

 

60

Board of Directors’ Mandate

 

61

Position Descriptions

 

62

Orientation and Continuing Education of Directors

 

63

Ethical Business Conduct

 

63

Nomination of Directors

 

64

Compensation

 

65

Audit Committee

 

65

Reserves Committee

 

65

 

 

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Safety, Environment and Responsibility Committee

 

65

Board Assessments

 

65

Key Governance Documents

 

66

DESCRIPTION OF CAPITAL STRUCTURE

 

67

Common Shares

 

67

Preferred Shares

 

67

Employee Stock Option Plan

 

67

SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

 

71

DIVIDENDS

 

71

MARKET FOR SECURITIES

 

71

CREDIT RATINGS

 

72

PRIOR SALES

 

73

Debt Securities

 

73

RISK FACTORS

 

73

Risks relating to the Arrangement

 

73

Risks relating to our Business

 

74

Other Risk Factors

 

80

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

 

80

INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

 

80

INTERESTS OF EXPERTS

 

81

TRANSFER AGENTS AND REGISTRARS

 

81

MATERIAL CONTRACTS

 

81

PROMOTER

 

83

ADDITIONAL INFORMATION

 

83

NOTE REGARDING FORWARD-LOOKING STATEMENTS

 

84

NOTE REGARDING RESERVES DATA AND OTHER OIL AND GAS INFORMATION

 

86

GLOSSARY

 

87

ABBREVIATIONS

 

89

APPENDIX A - Report on Reserves Data by Independent Qualified Reserves Evaluators

 

A-1

APPENDIX B - Report of Management and Directors on Reserves Data and Other Information

 

B-1

APPENDIX C - Audit Committee Mandate

 

C-1

APPENDIX D - Board of Directors’ Mandate

 

D-1

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2009

 

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NOTICE TO READER

 

This is the annual information form of Cenovus Energy Inc. for the year ended December 31, 2009. In this annual information form, unless otherwise specified or the context otherwise requires, reference to “we”, “us”, “our” or “Cenovus” includes reference to subsidiaries of, and partnership interests held by, Cenovus Energy Inc. and its subsidiaries subsequent to the Effective Date and the Cenovus Assets, as held by EnCana prior to the Effective Date. We acquired the Cenovus Assets from EnCana on the Effective Date in connection with the Arrangement.

Unless otherwise specified, all dollar amounts are expressed in U.S. dollars and all references to “dollars”, “US$” or to “$” are to U.S. dollars and all references to “C$” are to Canadian dollars.

Unless otherwise indicated, all financial information included in this annual information form is determined using Canadian GAAP, which differs from U.S. GAAP in certain material respects, and thus may not be comparable to financial statements and financial information of U.S. companies. The notes to our audited consolidated financial statements for the year ended December 31, 2009 contain a discussion of the principal differences between the financial results calculated under Canadian GAAP and under U.S. GAAP.

Certain historical information contained in this annual information form has been provided by, or derived from information provided by, certain third parties, including EnCana. Although we have no knowledge that would indicate that any such information is untrue or incomplete, we assume no responsibility for the completeness or accuracy of such information or the failure by such third parties to disclose events which may have occurred or may affect the completeness or accuracy of such information, but which are unknown to us.

We commenced independent operations on December 1, 2009 following the completion of the Arrangement. The description of our business, recent significant developments, the presentation of financial statements and other information throughout this annual information form in respect of periods prior to December 1, 2009 is based on information with respect to the Cenovus Assets as operated by EnCana prior to December 1, 2009. See “General Development of our Business - The Arrangement” for further information on the Arrangement. Such financial information has been derived from the historical consolidated financial statements of EnCana for each of the relevant periods on a carve-out basis from such historical consolidated financial statements of EnCana for the relevant period and should be read in conjunction with our audited consolidated financial statements for the year ended December 31, 2009 and the carve-out consolidated financial statements in relation to Cenovus Energy for the year ended December 31, 2008 and the Management’s Discussion and Analysis thereon, each as set out in the Information Circular of EnCana dated October 20, 2009 relating to an arrangement involving Cenovus Energy Inc., and the unaudited interim carve-out consolidated financial statements in relation to Cenovus Energy for the nine months ended September 30, 2009 and the Management’s Discussion and Analysis thereon which are accessible on the SEDAR profile of EnCana at www.sedar.com and have been filed with the SEC and are available via EDGAR at www.sec.gov.

“Cenovus Energy” represents the historical operations, assets, liabilities and cash flows of the Integrated Oil and Canadian Plains Divisions of EnCana (prior to the completion of the Arrangement), as well as a portion of the Market Optimization and Corporate functions of EnCana (prior to the completion of the Arrangement). As a result, comparative historical financial results may not be indicative of those that would have resulted had we existed as a stand-alone entity during those periods. See “Risk Factors”.

This annual information form contains certain forward-looking statements or information within the meaning of applicable securities legislation. Forward-looking statements or

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2009

 

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information are typically identified by words such as “projected”, “anticipate”, “believe”, “expect”, “plan”, “intend” or similar words suggesting future outcomes or statements regarding an outlook. All statements other than statements of historical fact contained in this annual information form are forward-looking statements or information. See “Note Regarding Forward-Looking Statements”.

NI 51-101 imposes oil and gas disclosure standards for Canadian public companies engaged in oil and gas activities. We have obtained an exemption from the Canadian securities regulatory authorities to permit us to provide disclosure in accordance with the relevant legal requirements of the SEC. This facilitates comparability of our oil and gas disclosure with that provided by U.S. and other international issuers, given that we are active in the U.S. capital markets. Accordingly, the proved and probable reserves data and much of the other oil and gas information included in this annual information form is disclosed in accordance with U.S. disclosure requirements. Such information, as well as the information that we anticipate disclosing in the future in reliance on such exemption, may differ from the corresponding information prepared in accordance with NI 51-101 standards. Pursuant to U.S. reporting protocols, production and reserves information is required to be presented on an after royalties basis. In addition, to provide more complete information on our business, we are voluntarily providing production and reserves information on a before royalties basis. The probable reserves data contained in this annual information form is also being provided on a voluntary basis. See “Reserves and Other Oil and Gas Information” and “Note Regarding Reserves Data and Other Oil and Gas Information”.

Unless otherwise noted, capitalized terms used in this annual information form have the meaning ascribed thereto under the heading “Glossary”.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2009

 

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CORPORATE STRUCTURE

 

Cenovus Energy Inc. was incorporated on September 24, 2008 under the CBCA as 7050372 Canada Inc. Pursuant to the Arrangement, 7050372 and Subco amalgamated under the CBCA on the Effective Date with the amalgamated company’s name being “Cenovus Energy Inc.”. Our executive and registered office is located at #4000, 421 - 7 Avenue S.W., Calgary, Alberta, Canada T2P 4K9. Prior to completion of the Arrangement, 7050372 did not carry on any active business and did not issue any shares.

For a further description of the Arrangement, see “General Development of Our Business – The Arrangement”.

Intercorporate Relationships

We have the following principal subsidiaries and partnerships which have total assets that exceed ten percent of our total consolidated assets or sales and revenues which exceed ten percent of our total consolidated sales and revenues as at and for the year ended December 31, 2009:

 

Subsidiaries & Partnerships

 

Percentage Owned(1)

 

Jurisdiction of
Incorporation,
Continuance,
Formation or
Organization

Cenovus FCCL Ltd.

 

100

 

 

Alberta

FCCL Partnership

 

50

 

 

Alberta

Cenovus Downstream Holdings ULC

 

100

 

 

Alberta

Cenovus US Refineries, LLC

 

100

 

 

Delaware

Cenovus US Refinery Holdings

 

100

 

 

Delaware

WRB Refining LLC

 

50

 

 

Delaware

Note:

(1)  Includes indirect ownership.

 

The above table does not include all of our subsidiaries and partnerships. The assets and revenues of our unnamed subsidiaries and partnerships did not exceed 20 percent of our total consolidated assets or total consolidated sales and revenues as at and for the year ended December 31, 2009.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2009

 

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GENERAL DEVELOPMENT OF OUR BUSINESS

 

Cenovus is an integrated oil company headquartered in Calgary, Alberta. Our operations include enhanced oil recovery (“EOR”) properties and established crude oil and natural gas production in Alberta and Saskatchewan. We also have ownership interests in two refineries in Illinois and Texas, USA.

We began independent operations on December 1, 2009 following the split of EnCana into two independent publicly traded energy companies – Cenovus and EnCana. Although we are a new company, we have operated a number of our assets for decades.

The Arrangement

The division of EnCana into two highly focused and independent publicly traded energy companies was completed on November 30, 2009. It resulted in, among other things, the establishment of our company as an independent integrated oil company anchored by stable production and cash flow from well-established crude oil and natural gas plays, integrated from crude oil production through to refined products.

Pursuant to the Arrangement and a number of preliminary transactions completed on or prior to the Effective Date, we indirectly acquired:

(a)                                 those assets associated with EnCana’s Integrated Oil Division, which included EnCana’s interests in the Foster Creek, Christina Lake, Narrows Lake and Borealis areas and the U.S. refinery interests in addition to certain of EnCana’s other bitumen interests and natural gas assets located in the Athabasca area;

(b)                                 those assets associated with EnCana’s Canadian Plains Division, which included the majority of EnCana’s legacy oil and natural gas assets in southern Alberta and Saskatchewan. This Division included the EOR properties located at Weyburn and Pelican Lake, as well as the Southern Alberta oil and gas properties; and

(c)                                 those assets associated with the foregoing businesses, including marketing, corporate and office space (including a proportionate share of The Bow office project).

Pursuant to the Pre-Arrangement Reorganization in connection with the Arrangement, EnCana transferred the Cenovus Assets to Subco in exchange for, among other things, an interest bearing demand intercompany note in the amount of $3.5 billion (the “Demand Note”).

The Assumed Liabilities assumed, directly or indirectly, in connection with the Arrangement included, among others, those liabilities relating to EnCana’s Integrated Oil and Canadian Plains Divisions described above.

As a result of the Arrangement, each shareholder of EnCana (other than a Dissenting Shareholder) received one new EnCana common share (such shares being represented by existing EnCana common share certificates) and one Common Share for each EnCana common share held. On the Effective Date, 751,273,307 Common Shares were issued to such former holders of EnCana common shares.

In connection with the Arrangement and in order to provide ongoing liquidity, including working capital requirements, prior to the completion of the Arrangement, we obtained commitments from a syndicate of banks to make available an unsecured credit facility in the amount of C$2.5 billion. The revolving syndicated credit facility consists of two tranches, a C$2.0 billion three-year tranche and a C$500 million 364-day tranche. The terms of each of these facilities commenced on the Effective Date.

On September 18, 2009, a predecessor entity of Cenovus completed, in three tranches, a $3.5 billion private offering of debt securities (comprised of the 2014 Notes, 2019 Notes and 2039 Notes) which are exempt from the registration requirements of the U.S. Securities Act

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2009

 

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under Rule 144A and Regulation S (the “Cenovus Note Offering”). See “Prior Sales”. The net proceeds of the Cenovus Note Offering were placed into an escrow account pending the completion of the Arrangement. Upon completion of the Arrangement, the net proceeds, together with other pre-funded amounts, were released from escrow and were applied to repay all of the amounts outstanding under the Demand Note.

We have filed a business acquisition report in Form 51-102F4 in respect of the Arrangement. The business acquisition report is accessible under our profile on SEDAR at www.sedar.com and in our Form 6-K filed with the SEC on December 16, 2009, available via EDGAR at www.sec.gov.

Our Business

Our operations are organized into two operating divisions:

·                  Integrated Oil Division, which includes all of the assets within the upstream and downstream integrated oil business with our joint venture partner, as well as other bitumen interests and the Athabasca natural gas assets. The Integrated Oil Division has assets in both Canada and the U.S. including two major EOR properties: (i) Foster Creek; and (ii) Christina Lake; as well as two refineries: (i) Wood River; and (ii) Borger.

·                  Canadian Plains Division, which contains established crude oil and natural gas development assets in Alberta and Saskatchewan and includes two major EOR properties: (i) Weyburn; and (ii) Pelican Lake; as well as the Southern Alberta oil and gas properties. The Division also markets Cenovus’s crude oil and natural gas, as well as third-party purchases and sales of product that provide operational flexibility for transportation commitments, product type, delivery points and customer diversification.

For financial statement reporting purposes, our operating and reportable segments are:

·                  Upstream Canada, which includes Cenovus’s development and production of bitumen, crude oil, natural gas and natural gas liquids (“NGLs”) and other related activities in Canada. This includes the Foster Creek and Christina Lake operations which are jointly owned with ConocoPhillips, an unrelated U.S. public company, and operated by Cenovus.

·                  Downstream Refining, which is focused on the refining of crude oil into petroleum and chemical products at two refineries located in the United States. The refineries are jointly owned with ConocoPhillips and operated by ConocoPhillips.

·                  Corporate and Eliminations, which primarily includes unrealized gains or losses recorded on derivative financial instruments as well as other Cenovus-wide costs for general and administrative and financing activities. As financial instruments are settled, realized gains and losses are recorded in the operating segment to which the derivative instrument relates. Eliminations relate to sales and operating revenues and purchased product between segments recorded at transfer prices based on current market prices and to unrealized intersegment profits in inventory.

In addition to the Arrangement, the following describes the significant events of the last three years in respect of our business:

2009

·                  In the first quarter of 2009, two new expansion phases at Foster Creek were commissioned. Phases D and E added a total of 60,000 barrels per day of bitumen production capacity, increasing the total production capacity of Foster Creek to approximately 120,000 barrels per day.

 

 

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·                  In the second quarter of 2009, a joint regulatory application for Foster Creek phases F, G and H was submitted to the Energy Resources Conservation Board (“ERCB”) and Alberta Environment. Each phase is expected to increase production capacity by 30,000 barrels per day of bitumen.

·                  In the fourth quarter of 2009, FCCL sanctioned the next phase, phase D, of expansion at Christina Lake, which is expected to increase production capacity by 40,000 barrels per day of bitumen in 2013.

·                  In the fourth quarter of 2009, a joint regulatory application for Christina Lake phases E, F and G was submitted to the ERCB and Alberta Environment. Each phase is expected to increase production capacity by 40,000 barrels per day of bitumen.

2008

·                  In the second quarter of 2008, Christina Lake phase B expansion was commissioned. This phase added 8,000 barrels per day of production capacity, increasing the total production capacity at Christina Lake to approximately 18,000 barrels per day of bitumen.

·                  In the third quarter of 2008, the Wood River refinery received regulatory approvals to start construction on the CORE project. Our 50 percent share of the CORE project is expected to cost approximately $1.8 billion and is anticipated to be completed and in operation in 2011. The expansion is expected to more than double heavy crude oil refining capacity to approximately 240,000 barrels per day and increase crude oil refining capacity by 50,000 barrels per day to approximately 356,000 barrels per day.

2007

·     The creation of the integrated oil business venture, consisting of upstream and downstream assets, with ConocoPhillips was completed on January 3, 2007. It is comprised of two 50-50 operating entities, a Canadian upstream enterprise operated by Cenovus and a U.S. downstream enterprise operated by ConocoPhillips, with both ConocoPhillips and Cenovus having contributed equally valued assets and equity. The integrated oil business provides greater certainty of execution for our Foster Creek and Christina Lake EOR projects and allows us to participate in the full value chain from crude oil production through to refined products.

·                 In the first quarter of 2007, Foster Creek phase C expansion was commissioned. This phase added 30,000 barrels per day of production capacity, increasing the total production capacity at Foster Creek to approximately 60,000 barrels per day of bitumen.

·                 In the second quarter of 2007, a 25,000 barrel per day coker addition at the Borger refinery was completed. The refinery was shut down for approximately one month to complete a major planned turnaround timed to coincide with bringing the new coker online. The refinery started up again in June 2007 and ran its first barrel of Canadian heavy oil on July 10, 2007, marking a major milestone for the refinery.

·                 In the third quarter of 2007, regulatory approval and sanctioning was received for the Christina Lake phase C expansion, which is expected to increase production capacity by 40,000 barrels per day of bitumen in 2011.

·                  In the fourth quarter of 2007, a joint regulatory application for development of the Borealis property was 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 per day of bitumen.

 

 

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NARRATIVE DESCRIPTION OF OUR BUSINESS

 

The following maps outline the location of our assets, including our major properties and refining assets as at December 31, 2009.

 

 

 

 

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One hundred percent of our reserves and production are located in Canada. At December 31, 2009, we had a land base of approximately 7.8 million net acres and a proved reserves base (our share after royalties) of approximately 719 million barrels of bitumen reserves, 232 million barrels of crude oil and NGLs reserves and 1,474 billion cubic feet of natural gas reserves. The estimated proved reserves life index as at December 31, 2009 was approximately 14.7 years. We also had probable reserves (our share after royalties) of approximately 403 million barrels of bitumen, 127 million barrels of crude oil and NGLs and 405 billion cubic feet of natural gas as at December 31, 2009.

 

The following narrative describes each of our operating divisions in greater detail.

 

Integrated Oil Division

 

The Integrated Oil Division includes all of the assets within the integrated oil business with ConocoPhillips described below, as well as other bitumen interests and the Athabasca natural gas assets. The Integrated Oil Division has assets in both Canada and the U.S. and contains two EOR properties: (i) Foster Creek; and (ii) Christina Lake; as well as two refineries at Wood River and Borger. In 2009, the Integrated Oil Division had capital investment of approximately $1,383 million, which included continued development of the CORE project, as well as the drilling of approximately 80 net wells (including 40 stratigraphic test wells).

 

As at December 31, 2009, we held bitumen rights of approximately 1,055,000 gross acres (760,000 net acres) within the Athabasca and Cold Lake areas, as well as the exclusive rights to lease an additional 652,000 net acres on our behalf and/or our assignee’s behalf on the Cold Lake Air Weapons Range.

 

The following table summarizes landholdings for the Integrated Oil Division as at December 31, 2009.

 

 

 

Developed

 

Undeveloped

 

Total

 

Average

 

 

 

Acreage

 

Acreage

 

Acreage

 

Working

 

Landholdings (thousands of acres)

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Interest

 

Foster Creek

 

7

 

4

 

65

 

32

 

72

 

36

 

50%

 

Christina Lake

 

1

 

-

 

24

 

12

 

25

 

12

 

50%

 

Narrows Lake(1)

 

-

 

-

 

25

 

15

 

25

 

15

 

60%

 

Borealis

 

-

 

-

 

36

 

36

 

36

 

36

 

100%

 

Athabasca

 

520

 

443

 

355

 

283

 

875

 

726

 

83%

 

Other

 

23

 

10

 

923

 

675

 

946

 

685

 

72%

 

Integrated Oil Total

 

551

 

457

 

1,428

 

1,053

 

1,979

 

1,510

 

76%

 

Note:

(1)          Under an area of mutual interest arrangement, ConocoPhillips made an election to participate in a certain Cenovus lease acquisition through ConocoPhillips’s interest in FCCL, reducing Cenovus’s working interest share to 50 percent on January 1, 2010.

 

The following table sets forth our share of daily average production figures for the periods indicated.

 

 

 

Crude Oil

 

 

 

 

 

 

 

and NGLs

 

Natural Gas

 

Total Production

 

 

 

(bbls/d)

 

(MMcf/d)

 

(BOE/d)

 

Production (annual average)

 

2009

 

2008

 

2009

 

2008

 

2009

 

2008

 

Foster Creek

 

36,654

 

25,947

 

-

 

-

 

36,654

 

25,947

 

Christina Lake

 

6,527

 

4,236

 

-

 

-

 

6,527

 

4,236

 

Athabasca

 

-

 

-

 

49

 

63

 

8,167

 

10,500

 

Other

 

2,553

 

2,729

 

-

 

-

 

2,553

 

2,729

 

Integrated Oil Total

 

45,734

 

32,912

 

49

 

63

 

53,901

 

43,412

 

 

 

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The following table summarizes the Integrated Oil Division’s interests in producing wells as at December 31, 2009. These figures exclude wells which were capable of producing, but that were not producing as of December 31, 2009.

 

 

 

    Producing

 

Producing

 

Total

 

 

 

    Oil Wells

 

Gas Wells

 

Producing Wells

 

Producing Wells (number of wells)

 

Gross

 

Net

 

Gross

 

Net   

 

Gross

 

Net

 

Foster Creek

 

171

 

86

 

-

 

-

 

171

 

86

 

Christina Lake

 

16

 

8

 

8

 

4

 

24

 

12

 

Athabasca

 

-

 

-

 

683

 

647

 

683

 

647

 

Integrated Oil Total

 

187

 

94

 

691

 

651

 

878

 

745

 

 

The following describes major producing areas or activities in the Integrated Oil Division.

 

Integrated Oil Business

 

On January 3, 2007, the creation of the integrated oil business with ConocoPhillips was completed. The integrated oil business includes Canadian upstream assets contributed by Cenovus and U.S. downstream assets contributed by ConocoPhillips. The business is comprised of two 50-50 operating entities, a Canadian upstream entity, FCCL, operated by Cenovus and a U.S. downstream enterprise, WRB, operated by ConocoPhillips.

 

FCCL owns the Foster Creek and Christina Lake EOR projects. Cenovus FCCL Ltd., our wholly-owned subsidiary, is the operating and managing partner of FCCL. WRB owns the Wood River and Borger refineries. ConocoPhillips held a disproportionate economic interest in the Borger refinery of 85 percent in 2007 and 65 percent 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 composed of three of our representatives and three of ConocoPhillips’s representatives, with each company holding equal voting rights.

 

At December 31, 2009, the combined production capacity of the Foster Creek and Christina Lake properties was approximately 138,000 barrels per day. FCCL plans to increase production capacity to approximately 218,000 barrels of bitumen per day from the combined facilities at Foster Creek and Christina Lake with the completion of the Christina Lake phase C expansion in 2011 and phase D expansion in 2013.

 

At December 31, 2009, WRB had processing capability to refine up to approximately 70,000 barrels per day of bitumen equivalent. WRB plans to refine approximately 150,000 barrels per day of bitumen equivalent to primarily motor fuels with the completion of the CORE project in 2011.

 

Foster Creek

 

We have a 50 percent interest in Foster Creek, an EOR property which uses SAGD technology and produces from the McMurray formation. We hold 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. In addition, we hold exclusive rights to lease several hundred thousand acres of bitumen rights in other areas on the Cold Lake Air Weapons Range on our behalf and/or our assignee’s behalf. In the first quarter of 2009, two new expansion phases were completed at Foster Creek adding production capacity of approximately 60,000 barrels of bitumen per day and increasing total production capacity to approximately 120,000 barrels of bitumen per day.

 

We continually research and develop technologies to increase bitumen recovery, decrease costs of extracting bitumen and reduce our environmental footprint. One focus area is alternate methods of artificial lift where we utilize new pump designs that are expected to enable us to optimize SAGD performance by operating at lower pressures, thereby realizing lower steam-oil ratios and decreasing facility capital and operating costs. As at

 

 

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December 31, 2009, electrical submersible pumps were in use on 133 wells at Foster Creek and we expect to continue to utilize this technology on new SAGD wells.

 

In addition, we have successfully piloted another technology at Foster Creek whereby an additional well, a wedge well, is drilled between two producing well pairs to produce bitumen that is heated by proximity to a steam chamber, but is not recoverable by the adjacent production wells. We have received a U.S. patent for this technology, with the Canadian patent pending and expected to be received in the first half of 2010. This technology requires no additional steam, thus it helps reduce the overall steam-oil ratio. In 2009, we drilled 18 wedge wells (2008 - four wells). As at December 31, 2009, there were 27 wedge wells producing. This process will be piloted at our Christina Lake property in the first quarter of 2010.

 

We also focus on reducing our reliance on natural gas for the generation of steam used in SAGD production operations. The Solvent Aided Process (“SAP”) is discussed under “Christina Lake” below.

 

We operate an 80-megawatt natural gas-fired cogeneration facility in conjunction with the SAGD operation at Foster Creek. The steam and power generated by the facility is presently being used within the SAGD operation and the excess power generated is being sold into the Alberta Power Pool.

 

Christina Lake

 

We have a 50 percent interest in a SAGD EOR project at Christina Lake which produces from the McMurray formation. During 2008, the phase B expansion was completed which increased production capacity to approximately 18,000 barrels of bitumen per day.

 

The phase C expansion, which is expected to add an additional 40,000 barrels per day of bitumen production capacity, is currently under construction and is expected to be completed in 2011, increasing total bitumen production capacity to 58,000 barrels per day.

 

During the fourth quarter of 2009, the phase D expansion was sanctioned by FCCL. This expansion is expected to add an additional 40,000 barrels per day of bitumen production capacity at Christina Lake. We have accelerated the completion of phase D by six months and it is expected to be completed in mid-2013. Regulatory approval for this additional phase was received in 2008.

 

There have been several innovations to SAGD technology that have been undertaken at Christina Lake over the past several years. One major project that started in 2009 is a new SAP pilot. This SAP pilot utilizes a mixture of steam and solvent to enhance recovery of the bitumen by reducing the steam-oil ratio and increasing the overall recovery of the oil in place. Business cases are currently being evaluated for the potential use of this technology in the Christina Lake and Narrows Lake development plans.

 

Another innovation was undertaken in 2007, whereby a remote water disposal system was utilized to successfully manage bottom water pressures and further reduce the steam-oil ratio.

 

Narrows Lake

 

We hold a 50 percent interest in the Narrows Lake area which is located within the greater Christina Lake regional area. We are preparing development plans and regulatory applications for a project at Narrows Lake that would include two to three phases with each phase expected to add approximately 40,000 barrels per day of bitumen production capacity.

 

Wood River Refinery

 

We have a 50 percent interest in the Wood River refinery, located in Roxana, Illinois. As at December 31, 2009, the Wood River refinery had a processing capacity of approximately 306,000 barrels per day of crude oil. It processes light, low-sulphur and heavy, high-sulphur

 

 

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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 2007, the refinery completed the construction of a proprietary sulphur removal unit that produces low-sulphur gasoline. In September 2008, regulatory approval was received to proceed with the CORE project at Wood River which is expected to increase crude oil refining capacity by approximately 50,000 barrels per day, increase coking capacity by approximately 65,000 barrels per day, more than double heavy crude oil refining capacity to approximately 240,000 barrels per day and increase the clean transportation fuels yield by approximately ten percent to approximately 89 percent. Capital expenditures for the CORE project are estimated at $3.6 billion ($1.8 billion net to Cenovus) and the project is scheduled to be completed in 2011. At December 31, 2009, the CORE project was 71 percent complete, on schedule and on budget.

 

Borger Refinery

 

We have a 50 percent interest in the Borger refinery, located in Borger, Texas. As at December 31, 2009, the Borger refinery had a processing 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 U.S. 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 heavy oil, 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 and other air emissions.

 

The following table summarizes the combined refineries’ key operational results for the periods indicated.

 

Refinery Operations(1)

 

2009

 

 

2008

 

 

Crude Oil Capacity (Mbbls/d)

 

452

 

 

452

 

 

Crude Oil Runs (Mbbls/d)

 

394

 

 

423

 

 

Crude Utilization (%)

 

87

 

 

93

 

 

Refined Products (Mbbls/d)

 

 

 

 

 

 

 

Gasoline

 

223

 

 

230

 

 

Distillates

 

120

 

 

139

 

 

Other

 

74

 

 

79

 

 

Total

 

417

 

 

448

 

 

Note:

(1)  Represents 100 percent of the Wood River and Borger refinery operations.

 

Other Integrated Oil Division Properties

 

Borealis

 

We hold a 100 percent working interest in the Borealis area, which is located approximately 90 kilometres northeast of Fort McMurray. Borealis is not included in the integrated oil business with ConocoPhillips. Approximately 200 delineation wells have been drilled in the greater Borealis area as at December 31, 2009. 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. We continue to evaluate the greater Borealis area in support of the development application.

 

 

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Athabasca Gas

 

We produce natural gas from the Cold Lake Air Weapons Range and several surrounding landholdings located in northeast Alberta and hold surface access and natural gas rights for exploration, development and transportation from areas within the Cold Lake Air Weapons Range that were granted by the Governments of Canada and Alberta. The majority of our natural gas production in the area is processed through wholly-owned and operated compression facilities.

 

Natural gas production continues to be impacted by the September 2003, July 2004, September 2004, July 2007 and October 2009 ERCB decisions to shut-in natural gas production from the McMurray, Wabiskaw and Clearwater formations 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 25 million cubic feet per day in 2009 (26 million cubic feet per day in 2008). The Alberta Government’s Department of Energy 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.

 

Canadian Plains Division

 

The Canadian Plains Division encompasses crude oil development and production activities in Alberta and Saskatchewan, as well as established natural gas development and production activities in both southern and northern Alberta and southern Saskatchewan. Three major properties are located in the Canadian Plains Division: EOR projects at Pelican Lake and Weyburn, as well as conventional oil and natural gas in Southern Alberta. The Division also markets crude oil and natural gas, including third-party purchases and sales of product that provide operational flexibility for transportation commitments, product type, delivery points and customer diversification.

 

As at December 31, 2009, the Canadian Plains Division had an established land position of approximately 6.7 million gross acres (6.3 million net acres), of which approximately 4.3 million gross acres (4.1 million net acres) are developed. The mineral rights on approximately 50 percent of the total net acreage are owned in fee title by Cenovus, 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 2009, the Canadian Plains Division had capital investment of approximately $478 million and drilled approximately 614 net wells. Of our capital expenditures, 56 percent was oil focused, while 43 percent of the capital expenditure was natural gas focused.

 

Plans for 2010 include further EOR initiatives, continued drilling, well optimizations, well recompletions (including coalbed methane (“CBM”)) and investment in facility infrastructure necessary for continued development.

 

 

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The following table summarizes the landholdings for the Canadian Plains Division as at December 31, 2009.

 

 

 

   Developed
   Acreage

 

  Undeveloped
  Acreage

 

 Total
 Acreage

 

Average
Working

 

Landholdings (thousands of acres)

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Interest

 

Weyburn

 

99

 

87

 

383

 

377

 

482

 

464

 

96%

 

Pelican Lake

 

133

 

133

 

279

 

264

 

412

 

397

 

96%

 

Southern Alberta

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Suffield

 

928

 

917

 

63

 

60

 

991

 

977

 

99%

 

Brooks North

 

569

 

567

 

8

 

8

 

577

 

575

 

100%

 

Langevin

 

1,132

 

1,022

 

371

 

345

 

1,503

 

1,367

 

91%

 

Drumheller

 

356

 

345

 

19

 

16

 

375

 

361

 

96%

 

Total Southern Alberta

 

2,985

 

2,851

 

461

 

429

 

3,446

 

3,280

 

95%

 

Other

 

1,058

 

986

 

1,303

 

1,193

 

2,361

 

2,179

 

92%

 

Canadian Plains Total

 

4,275

 

4,057

 

2,426

 

2,263

 

6,701

 

6,320

 

94%

 

 

The following table sets forth our share of daily average production figures for the periods indicated.

 

 

 

   Crude Oil

 

 

 

 

 

 

 

   and NGLs

 

  Natural Gas

 

  Total Production

 

 

 

   (bbls/d)

 

  (MMcf/d)

 

  (BOE/d)

 

Production (annual average)

 

2009 

 

2008 

 

2009

 

2008

 

2009

 

2008

 

Weyburn

 

14,960

 

14,056

 

-

 

-

 

14,960

 

14,056

 

Pelican Lake

 

20,105

 

21,975

 

-

 

1

 

20,105

 

22,102

 

Southern Alberta

 

 

 

 

 

 

 

 

 

 

 

 

 

Suffield

 

12,038

 

13,054

 

213

 

231

 

47,567

 

51,621

 

Brooks North

 

1,104

 

839

 

260

 

273

 

44,373

 

46,339

 

Langevin

 

8,293

 

9,111

 

185

 

203

 

39,044

 

43,029

 

Drumheller

 

2,122

 

2,276

 

81

 

93

 

15,679

 

17,776

 

Total Southern Alberta

 

23,557

 

25,280

 

739

 

800

 

146,663

 

158,765

 

Other

 

5,428

 

6,027

 

36

 

41

 

11,489

 

12,748

 

Canadian Plains Total

 

64,050

 

67,338

 

775

 

842

 

193,217

 

207,671

 

 

The following table summarizes the Canadian Plains Division’s interests in producing wells as at December 31, 2009. These figures exclude wells which were capable of producing, but that were not producing, as of December 31, 2009.

 

 

 

    Producing

 

    Producing

 

Total

 

 

 

    Oil Wells

 

    Gas Wells

 

Producing Wells

 

Producing Wells (number of wells)

 

Gross 

 

Net 

 

Gross 

 

Net 

 

Gross

 

Net

 

Weyburn

 

764

 

482

 

-

 

-

 

764

 

482

 

Pelican Lake

 

445

 

445

 

9

 

9

 

454

 

454

 

Southern Alberta

 

 

 

 

 

 

 

 

 

 

 

 

 

Suffield

 

745

 

745

 

10,348

 

10,330

 

11,093

 

11,075

 

Brooks North

 

57

 

57

 

7,338

 

7,230

 

7,395

 

7,287

 

Langevin

 

251

 

246

 

7,028

 

6,388

 

7,279

 

6,634

 

Drumheller

 

121

 

118

 

1,612

 

1,552

 

1,733

 

1,669

 

Total Southern Alberta

 

1,174

 

1,166

 

26,326

 

25,550

 

27,500

 

26,665

 

Other

 

665

 

626

 

1,173

 

1,154

 

1,838

 

1,780

 

Canadian Plains Total

 

3,048

 

2,719

 

27,508

 

26,663

 

30,556

 

29,381

 

 

 

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The following describes major producing areas or activities in the Canadian Plains Division.

 

Weyburn

 

We have a 62 percent working interest (50 percent economic interest) in the unitized portion of the Weyburn crude oil field in southeast Saskatchewan. The Weyburn unit produces light and medium sour crude from the Mississippian Midale formation and covers 78 sections of land. Cenovus is the operator and we are increasing ultimate recovery in the EOR area of the field with a carbon dioxide (“CO2”) miscible flood project. As at December 31, 2009, approximately 70 percent of the approved and planned CO2 flood pattern development at the Weyburn unit was complete. Since the inception of the project, approximately 15 million tonnes of CO2 have been injected as part of the EOR program. We estimate that another 15 million tonnes will be injected as part of the EOR project. The CO2 is delivered by pipeline directly to the Weyburn facility from a coal gasification project in North Dakota.

 

Pelican Lake

 

Pelican Lake produces heavy crude oil from the Cretaceous Wabiskaw formation in northeast Alberta through horizontally drilled waterflood and polymer EOR methods. Facility infrastructure expansion in this area continued in 2009 to accommodate higher total fluid production volumes associated with its waterflood and polymer projects. The polymer flood program was expanded by 50 injection wells during 2009.

 

In addition to the heavy crude oil in the Wabiskaw formation, large deposits of bitumen have been identified in the Cretaceous Grand Rapids and the Devonian Grosmont formations in the Pelican Lake area which we continue to evaluate. In 2009, 17 stratigraphic test wells were drilled to acquire technical data on these formations.

 

We hold 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.

 

In August 2008, we entered into an agreement with Pembina Pipeline Corporation (“Pembina”) to transport blended heavy oil from Utikuma, Alberta to Edmonton, Alberta via Pembina’s 100,000 barrels per day capacity pipeline. This pipeline will be used to transport heavy oil from our Pelican Lake property to crude oil markets. The parties also agreed to transport condensate, used as diluent for transporting heavy oil, from Whitecourt, Alberta to Utikuma, Alberta via a 22,000 barrel per day capacity pipeline. The initial term of the agreement is ten years from the in-service date, which is estimated to be in mid-2011.

 

Southern Alberta

 

We own all the mineral rights across the majority of our fee title lands in southern Alberta and we lease the majority of the Cretaceous rights in Suffield and parts of southeastern Alberta. Approximately 59 percent of the land we hold in this area is fee simple or freehold and approximately 41 percent is Crown land. Our Southern Alberta properties are comprised of both oil and gas fields.

 

Southern Alberta - Oil Properties

 

We hold interests in multiple zones, primarily in the Early Cretaceous, in the Suffield, Langevin, Brooks North and Drumheller areas in southern Alberta with a mix of medium and heavy oil production. Development in this area focuses on infill drilling, optimization of existing wells and EOR schemes. We operate water handling facilities to effectively manage primary and enhanced oil production.

 

 

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The following table sets forth net oil wells drilled and daily average oil production figures for the periods indicated.

 

 

 

  Net Wells

 

 Light/Medium

 

Heavy Oil

 

Net Wells Drilled and

 

  Drilled

 

 (bbls/d)

 

(bbls/d)

 

Production (annual average)

 

2009

 

2008 

 

2009

 

2008 

 

2009  

 

2008  

 

Suffield

 

40

 

47

 

-

 

-

 

12,038

 

13,054

 

Brooks North

 

18

 

3

 

894

 

642

 

-

 

-

 

Langevin

 

14

 

16

 

8,053

 

8,862

 

-

 

-

 

Drumheller

 

28

 

1

 

1,421

 

1,595

 

-

 

-

 

Southern Alberta - Oil Properties - Total

 

100

 

67

 

10,368

 

11,099

 

12,038

 

13,054

 

 

Southern Alberta - Natural Gas Properties

 

We hold interests in multiple zones, primarily in the Late Cretaceous, in the Suffield, Brooks North, Langevin and Drumheller areas in southern Alberta.

 

Development in this area focuses on infill drilling up to 16 wells per section, recompletions and optimization of existing wells.

 

The following table sets forth net gas wells drilled and daily average gas production figures for the periods indicated.

 

 

 

 

 

Gas Production

 

Net Wells Drilled and

 

Net Wells Drilled

 

(MMcf/d)

 

Production (annual average)

 

2009

 

2008

 

2009

 

2008

 

Suffield

 

170

 

468

 

213

 

231

 

Brooks North

 

163

 

478

 

260

 

273

 

Langevin

 

109

 

248

 

185

 

203

 

Drumheller

 

56

 

172

 

81

 

93

 

Southern Alberta - Natural Gas Properties - Total

 

498

 

1,366

 

739

 

800

 

 

Included in the Brooks North and Langevin area lands is the Belly River Cretaceous formation where Cenovus is producing CBM. In 2009, approximately 500 wells were recompleted which added approximately 14 million cubic feet per day of natural gas production by the end of the year. The CBM assets are long-life and low decline and are expected to generate production for future growth in a capital efficient manner.

 

Suffield is one of the core areas of our Southern Alberta major property. The Suffield area is largely made up of the Suffield Block, where operations are carried out pursuant to an agreement among Cenovus, the Government of Canada and the Province of Alberta governing surface access to CFB Suffield. In 1999, the parties agreed to permit access to the Suffield military training area to additional operators. Our predecessor companies, Alberta Energy Company Ltd. and EnCana Corporation, have operated at CFB Suffield for over 30 years. On October 6, 2008, pursuant to the Canadian Environmental Assessment Act, a joint review panel (“JRP”), made up of provincial and federal regulators, heard our application for a shallow gas infill development in the National Wildlife Area (“NWA”) at CFB Suffield. The hearing was completed in late October 2008. On January 27, 2009, the JRP released its recommendations, concluding that the proposed project could proceed provided two key pre-conditions were met: first, critical habitat assessments for certain specific species of plants and animals must be finalized by Environment Canada within the NWA; and second, the role of the Suffield Environmental Advisory Committee (“SEAC”) must be clarified by the parties to the surface access agreement, and SEAC must be resourced adequately to provide proper environmental oversight of the project. The JRP also concluded that other mitigations and recommendations should be followed once the two key pre-conditions were met. We are working with necessary interested parties to proceed with this project.

 

 

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Other Properties

 

We have started evaluating medium and light oil prospects in the Bakken and Shaunavon areas in Saskatchewan.

 

We also hold interests in other conventional oil and natural gas producing properties, primarily located in east central and northern Alberta.

 

Crude Oil and Natural Gas Marketing

 

Our Marketing group is focused on enhancing the netback price of our proprietary production. Canadian Plains divisional results include third-party purchases and sales of product to provide operational flexibility for transportation commitments, product quality, delivery points and customer diversification. The Marketing and Power group is also focused on ensuring reliable sourcing and lowest delivered cost of power at the field level.

 

We also seek to mitigate the market risk associated with future cash flows by entering into various risk management contracts relating to produced products. Details of those transactions related to our various risk management positions for crude oil, natural gas and power are found in the notes to our consolidated financial statements for the year ended December 31, 2009.

 

Crude Oil Marketing

 

We manage the transportation and marketing of crude oil for our upstream operating divisions. Our objective is to sell production to achieve the best price within the constraints of a diverse sales portfolio, as well as to obtain and manage condensate supply, inventory and storage to meet diluent requirements. During 2009, our blend volumes on behalf of FCCL were 120,894 barrels per day (2008 - 80,866 barrels per day), while our non-partnership blend volumes were 78,303 barrels per day (2008 - 86,560 barrels per day).

 

Natural Gas Marketing

 

Our natural gas is primarily marketed to industrials, other producers and energy marketing companies. In 2009, approximately 25 percent of our sales of natural gas were directly marketed by us to industrials. The remaining 75 percent of sales of natural gas were marketed to other producers and energy marketing companies. Prices received by us are based primarily upon prevailing index prices for natural gas. Prices are impacted by competing fuels in such markets and by North American regional supply and demand for natural gas.

 

 

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RESERVES AND OTHER OIL AND GAS INFORMATION

 

We retain independent qualified reserves evaluators (“IQREs”) to evaluate and prepare reports on 100 percent of our bitumen, crude oil, NGLs and natural gas reserves annually. These evaluators are McDaniel & Associates Consultants Ltd. and GLJ Petroleum Consultants Ltd. The following reserves information is derived from the reserves reports prepared for us by each of these companies.

 

We have a Reserves Committee (as defined herein) of independent Board members which reviews the qualifications and appointment of the IQREs. The Reserves Committee also reviews the procedures for providing information to the evaluators.

 

Cenovus’s Vice-President, Strategic Planning and Reserves Governance and two other staff under this individual’s direction oversee the preparation of the reserves estimates by the IQREs. Currently, this internal staff of two professional engineers have combined relevant experience of over 65 years. The Vice-President and other engineering staff are all members of the appropriate provincial professional associations and are members of various industry associations such as the Society of Petroleum Engineers.

 

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

 

There are numerous uncertainties inherent in estimating quantities of crude oil and natural gas reserves. See “Risk Factors - Risks relating to our Business - Our crude oil and natural gas reserves data and future net revenue estimates are uncertain”. Classifications of reserves as proved or probable are only attempts to define the degree of uncertainty associated with the estimates. In addition, whereas proved reserves are those reserves that can be estimated with reasonable certainty to be economically producible, probable reserves are those additional reserves that are less certain to be recovered than proved reserves, but which, together with proved reserves, are as likely as not to be recovered. Therefore, probable reserves estimates, by definition, have a higher degree of uncertainty than proved reserves.

 

Reserves Quantities Information

 

Revised reserves disclosure requirements issued by the SEC at the end of 2008 require separate disclosure of our bitumen reserves from our crude oil and NGLs reserves. The following information in this annual information form reflects this separation for each of the years presented.

 

The majority of our bitumen reserves will be recovered and produced using SAGD technology. SAGD involves injecting steam into horizontal wells drilled into the bitumen formation and recovering heated bitumen from producing wells located below the injection wells. This technique has a surface footprint comparable to conventional oil production. We have no bitumen reserves that require mining techniques to recover the bitumen.

 

 

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Table of Contents

 

Total Proved Reserves After Royalties

 

In 2009, bitumen reserves increased by approximately eight percent, largely as a result of Christina Lake phase D receiving approval to proceed. The increase was partially offset by reductions attributed to higher royalty bitumen rates resulting from a higher WTI price. In addition, as a result of the new Alberta Royalty Framework, where royalties are determined on a sliding scale depending on the price of bitumen, when prices are between C$55 per barrel and C$120 per barrel, pre-payout royalty rates range from one to nine percent of gross revenue. Once a project reaches payout, the royalty is based on the greater of one to nine percent of a project’s gross revenue or 25 to 40 percent of net revenue. The actual royalty rate that is payable within these ranges is determined based on the WTI U.S. dollar price of crude oil, translated into Canadian dollars. In 2008, bitumen reserves increased by approximately 12 percent, largely due to lower royalties resulting from a lower WTI price. In 2007, bitumen reserves decreased by approximately 26 percent, as a consequence of 50 percent of the Foster Creek and Christina Lake reserves being contributed into the integrated oil business with ConocoPhillips. The subsequent approval of Christina Lake phase C and other minor additions and revisions in the year restored 52 percent of the contributed reserves.

 

In 2009, crude oil and NGLs reserves decreased by approximately four percent as aggregate additions and revisions were insufficient to replace production. During 2008, crude oil and NGLs reserves increased by approximately four percent as reserve additions exceeded production and negative revisions. During 2007, crude oil and NGLs reserves decreased approximately four percent as reserves additions were more than offset by production.

 

In 2009, natural gas reserves decreased by approximately 21 percent as production and negative revisions to undeveloped reserves due to low gas prices, exceeded additions and positive revisions. Natural gas reserves during 2008 decreased by approximately eight percent, with positive revisions and additions insufficient to offset production. In 2007, natural gas reserves decreased by approximately nine percent, as positive revisions and additions only replaced approximately 46 percent of production.

 

Impact of SEC Modernization of Oil and Gas Reporting Requirements

 

SEC reporting requirements have changed with respect to prices used to estimate reserves and in the definition of proved oil and gas reserves. Our IQREs have determined that no changes to reserves have occurred as a result of the definition changes. However, the changes related to prices did impact our reserves at December 31, 2009. The following is a summary of the impact of using the new pricing rules (average 2009 prices) as compared to the old pricing rules (price on December 31, 2009): bitumen reserves are higher by 28 million barrels and oil and NGLs reserves are higher by seven million barrels, both as a result of lower royalty rates, and natural gas reserves are lower by 156 billion cubic feet as a result of low gas prices.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2009

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Table of Contents

 

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

Constant Pricing

 

 

 

 

 

 

 

 

 

 

 

 

 

Bitumen

 

Crude Oil and
Natural Gas Liquids

 

Natural Gas

 

 

 

(millions of barrels)

 

(millions of barrels)

 

(billions of cubic feet)

 

2007

 

 

 

 

 

 

 

 

 

 

Beginning of year

 

800

 

 

240

 

 

2,209

 

 

Revisions and improved recovery

 

63

 

 

12

 

 

47

 

 

Extensions and discoveries

 

142

 

 

5

 

 

116

 

 

Purchase of reserves in place

 

-

 

 

-

 

 

-

 

 

Sale of reserves in place

 

(398

)

 

-

 

 

-

 

 

Production

 

(11

)

 

(26

)

 

(353

)

 

End of year

 

596

 

 

231

 

 

2,019

 

 

Developed

 

72

 

 

184

 

 

1,818

 

 

Undeveloped

 

524

 

 

47

 

 

201

 

 

Total

 

596

 

 

231

 

 

2,019

 

 

2008

 

 

 

 

 

 

 

 

 

 

Beginning of year

 

596

 

 

231

 

 

2,019

 

 

Revisions and improved recovery

 

84

 

 

27

 

 

93

 

 

Extensions and discoveries

 

-

 

 

8

 

 

75

 

 

Purchase of reserves in place

 

-

 

 

-

 

 

-

 

 

Sale of reserves in place

 

-

 

 

-

 

 

(1

)

 

Production

 

(12

)

 

(25

)

 

(331

)

 

End of year

 

668

 

 

241

 

 

1,855

 

 

Developed

 

126

 

 

175

 

 

1,715

 

 

Undeveloped

 

542

 

 

66

 

 

140

 

 

Total

 

668

 

 

241

 

 

1,855

 

 

2009

 

 

 

 

 

 

 

 

 

 

Beginning of year

 

668

 

 

241

 

 

1,855

 

 

Revisions and improved recovery

 

(88

)

 

8

 

 

(128

)

 

Extensions and discoveries

 

160

 

 

6

 

 

50

 

 

Purchase of reserves in place

 

-

 

 

-

 

 

-

 

 

Sale of reserves in place

 

(4

)

 

-

 

 

(2

)

 

Production

 

(17

)

 

(23

)

 

(301

)

 

End of year

 

719

 

 

232

 

 

1,474

 

 

Developed

 

108

 

 

170

 

 

1,450

 

 

Undeveloped

 

611

 

 

62

 

 

24

 

 

Total

 

719

 

 

232

 

 

1,474

 

 

Notes:

(1)                Definitions:

(a)              “Net” reserves are the remaining reserves attributable to the Cenovus Assets, after deduction of estimated royalties and including royalty interests.

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

(c)              “Proved Developed” reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

(d)              “Proved Undeveloped” reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(2)                Estimates of total net proved bitumen, crude oil or natural gas reserves are not filed with any U.S. federal authority or agency other than the SEC.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2009

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Table of Contents

 

Supplemental Reserves Disclosure

 

The volatility of our net bitumen reserves and the net oil reserves at Pelican Lake due to the linkage of royalty rates to the WTI oil reference price has led Cenovus to conclude that it would facilitate comprehension of our assets to disclose our reserves on a before royalty basis, in addition to the above disclosure on a net, or after royalty, basis. This will provide a clearer understanding of the outcome of our reserves development activities.

 

Total Proved Reserves Before Royalties

 

In 2009, bitumen reserves increased by approximately 24 percent, as a result of the approval of Christina Lake phase D. In 2008, bitumen reserves were unchanged, as minor revisions offset production in the year. In 2007, bitumen reserves decreased by approximately 22 percent, as a consequence of 50 percent of the Foster Creek and Christina Lake reserves being contributed into the integrated oil business effective January 2, 2007. The subsequent approval of Christina Lake phase C and other minor additions and revisions in the year restored approximately 57 percent of the contributed reserves.

 

In 2009, crude oil and NGLs reserves remained relatively constant as additions and revisions very slightly exceeded production. During 2008, crude oil and NGLs reserves decreased by approximately four percent as reserves additions and positive revisions were exceeded by production and negative revisions. During 2007, crude oil and NGLs reserves decreased approximately one percent as reserves additions nearly offset production.

 

In 2009, natural gas reserves decreased by approximately 21 percent as production and negative revisions to undeveloped reserves due to low gas prices exceeded additions and positive revisions. Natural gas reserves during 2008 decreased by approximately nine percent, with positive revisions and additions insufficient to offset production. In 2007, natural gas reserves decreased by approximately nine percent, as positive revisions and additions only replaced approximately 43 percent of production.

 

Impact of SEC Modernization of Oil and Gas Reporting Requirements

 

SEC reporting requirements have changed with respect to prices used to estimate reserves and in the definition of proved oil and gas reserves. Our IQREs have determined that no changes to reserves have occurred as a result of the definition changes. However, the changes related to prices did impact our reserves at December 31, 2009. The following is a summary of the impact of using the new pricing rules (average 2009 prices) as compared to the old pricing rules (price on December 31, 2009): bitumen reserves are unchanged, oil and NGLs reserves are slightly down by one million barrels and natural gas reserves are lower by 164 billion cubic feet as a result of low gas prices.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2009

 

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Table of Contents

 

Company Share Proved Reserves Before Royalties(1)(2)

Constant Pricing

 

 

 

Bitumen
(millions of barrels)

 

Crude Oil and
Natural Gas Liquids
(millions of barrels)

 

Natural Gas
(billions of cubic feet)

2007

 

 

 

 

 

 

 

 

 

Beginning of year

 

901

 

 

292

 

 

2,342

 

Revisions and improved recovery

 

93

 

 

23

 

 

37

 

Extensions and discoveries

 

165

 

 

5

 

 

122

 

Purchase of reserves in place

 

-

 

 

-

 

 

-

 

Sale of reserves in place

 

(449

)

 

-

 

 

-

 

Production

 

(11

)

 

(31

)

 

(374

)

End of year

 

699

 

 

289

 

 

2,127

 

Developed

 

82

 

 

228

 

 

1,917

 

Undeveloped

 

617

 

 

61

 

 

210

 

Total

 

699

 

 

289

 

 

2,127

 

2008

 

 

 

 

 

 

 

 

 

Beginning of year

 

699

 

 

289

 

 

2,127

 

Revisions and improved recovery

 

12

 

 

7

 

 

76

 

Extensions and discoveries

 

-

 

 

8

 

 

79

 

Purchase of reserves in place

 

-

 

 

-

 

 

-

 

Sale of reserves in place

 

-

 

 

-

 

 

-

 

Production

 

(12

)

 

(28

)

 

(345

)

End of year

 

699

 

 

276

 

 

1,937

 

Developed

 

135

 

 

202

 

 

1,790

 

Undeveloped

 

564

 

 

74

 

 

147

 

Total

 

699

 

 

276

 

 

1,937

 

2009

 

 

 

 

 

 

 

 

 

Beginning of year

 

699

 

 

276

 

 

1,937

 

Revisions and improved recovery

 

28

 

 

22

 

 

(151

)

Extensions and discoveries

 

161

 

 

6

 

 

51

 

Purchase of reserves in place

 

-

 

 

-

 

 

-

 

Sale of reserves in place

 

(5

)

 

-

 

 

(3

)

Production

 

(17

)

 

(27

)

 

(305

)

End of year

 

866

 

 

277

 

 

1,529

 

Developed

 

132

 

 

203

 

 

1,504

 

Undeveloped

 

734

 

 

74

 

 

25

 

Total

 

866

 

 

277

 

 

1,529

 

Notes:

(1)                Definitions:

(a)              “Company Share” reserves are the remaining reserves attributable to the Cenovus Assets, before deduction of estimated royalties, but including royalty interests.

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

(c)              “Proved Developed” reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

(d)              “Proved Undeveloped” reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(2)                Estimates of total Company Share proved bitumen, crude oil or natural gas reserves are not filed with any U.S. federal authority or agency other than the SEC.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2009

 

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Table of Contents

 

Optional Disclosure of Probable Reserves

 

In addition to providing total proved reserves results, both before and after royalties, we are also providing information on our probable reserves. Probable reserves are those additional reserves quantities of bitumen, crude oil, natural gas and NGLs that are less certain to be recovered than proved reserves, but which, together with proved reserves, are as likely as not to be recovered.

 

Probable reserves were estimated at the same time as the IQREs estimated the proved reserves, and incorporate the same technical and economic data in their estimation.

 

Total Probable Reserves After Royalties

 

At the end of 2009, probable bitumen reserves were 403 million barrels, or approximately 35 percent less than the previous year, due to the reclassification of Christina Lake phase D to proved reserves from probable reserves. In 2008, bitumen reserves were 624 million barrels, an increase of approximately 16 percent. In 2007, bitumen reserves were 537 million barrels.

 

At the end of 2009, probable crude oil and NGLs reserves were 127 million barrels, a decrease of approximately seven percent. In 2008, crude oil and NGLs reserves were 136 million barrels, an increase of approximately 14 percent. In 2007, crude oil and NGLs reserves were 119 million barrels.

 

At the end of 2009, probable natural gas reserves were 405 billion cubic feet, a decrease of approximately 22 percent. Natural gas reserves in 2008 were 522 billion cubic feet, a decrease of approximately eight percent. In 2007, natural gas reserves were 569 billion cubic feet.

 

Net Probable Reserves (Share After Royalties)(1)(2)

Constant Pricing

 

 

 

Bitumen
(millions of barrels)

 

Crude Oil and
Natural Gas Liquids
(millions of barrels)

 

Natural Gas
(billions of cubic feet)

2007

 

 

 

 

 

 

 

 

 

End of year

 

537

 

 

119

 

 

569

 

2008

 

 

 

 

 

 

 

 

 

End of year

 

624

 

 

136

 

 

522

 

2009

 

 

 

 

 

 

 

 

 

End of year

 

403

 

 

127

 

 

405

 

Developed

 

10

 

 

69

 

 

362

 

Undeveloped

 

393

 

 

58

 

 

43

 

Total

 

403

 

 

127

 

 

405

 

Notes:

(1)                Definitions:

(a)              “Net” reserves are the remaining reserves attributable to the Cenovus Assets, after deduction of estimated royalties, but including royalty interests.

(b)              “Probable” reserves are those additional reserves quantities of bitumen, crude oil, natural gas and NGLs that are less certain to be recovered than proved reserves, but which, together with proved reserves, are as likely as not to be recovered.

(c)              “Probable Developed” reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

(d)              “Probable Undeveloped” reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(2)                Estimates of total net probable bitumen, crude oil or natural gas reserves are not filed with any U.S. federal authority or agency other than the SEC.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2009

 

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Table of Contents

 

Supplemental Reserves Disclosure

 

As with proved reserves, the impact of oil price variations on royalty rates on probable reserves from year to year can create an unclear view of the development of our bitumen business. We are providing probable reserves on a before royalty basis below to assist understanding of our business.

 

Probable Reserves Before Royalties

 

At the end of 2009, probable bitumen reserves were 479 million barrels, or approximately 25 percent less than the previous year, due to the reclassification of Christina Lake phase D to proved reserves from probable reserves. In 2008, bitumen reserves were 637 million barrels, an increase of approximately two percent. In 2007, bitumen reserves were 622 million barrels.

 

At the end of 2009, probable crude oil and NGLs reserves were 156 million barrels, a decrease of approximately one percent. In 2008, crude oil and NGLs reserves were 158 million barrels, an increase of approximately five percent. In 2007, crude oil and NGLs reserves were 150 million barrels.

 

At the end of 2009, probable natural gas reserves were 436 billion cubic feet, a decrease of approximately 23 percent. Natural gas reserves in 2008 were 566 billion cubic feet, a decrease of approximately eight percent. In 2007, natural gas reserves were 618 billion cubic feet.

 

Company Share Probable Reserves Before Royalties(1)(2)

Constant Pricing

 

 

 

Bitumen
(millions of barrels)

 

Crude Oil and
Natural Gas Liquids
(millions of barrels)

 

Natural Gas
(billions of cubic feet)

2007

 

 

 

 

 

 

 

 

 

End of year

 

622

 

 

150

 

 

618

 

2008

 

 

 

 

 

 

 

 

 

End of year

 

637

 

 

158

 

 

566

 

2009

 

 

 

 

 

 

 

 

 

End of year

 

479

 

 

156

 

 

436

 

Developed

 

12

 

 

84

 

 

393

 

Undeveloped

 

467

 

 

72

 

 

43

 

Total

 

479

 

 

156

 

 

436

 

Notes:

(1)                Definitions:

(a)              “Company Share” reserves are the remaining reserves attributable to the Cenovus Assets, before deduction of estimated royalties, but including royalty interests.

(b)              “Probable” reserves are those additional reserves quantities of bitumen, crude oil, natural gas and NGLs that are less certain to be recovered than proved reserves, but which, together with proved reserves, are as likely as not to be recovered.

(c)              “Probable Developed” reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

(d)              “Probable Undeveloped” reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(2)                Estimates of total Company Share probable bitumen, crude oil or natural gas reserves are not filed with any U.S. federal authority or agency other than the SEC.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2009

 

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Table of Contents

 

Development of Proved Undeveloped Reserves

 

Bitumen

 

At the end of 2009, we had proved undeveloped bitumen reserves of 611 million barrels after royalties, or approximately 85 percent of our total proved bitumen reserves. Our existing reserves will be recovered using SAGD. Typical SAGD project development involves installing a steam generation facility, at a cost much greater than drilling a production/injection well pair, and drilling sufficient SAGD wells to fully utilize the available steam.

 

Proved bitumen reserves have been determined in compliance with Canadian Oil and Gas Evaluation Handbook standards. Proved developed bitumen reserves are differentiated from proved undeveloped bitumen reserves by the presence of drilled production/injection well pairs at the reserves estimation effective date. Because a steam plant has a long life relative to well pairs, in the early stages of a SAGD project, only a small portion of proved reserves will be developed as the number of well pairs drilled will be limited by the available steam capacity.

 

The forecast production of Cenovus’s proved bitumen reserves extends over 40 years, based on existing facilities. Production of the current proved developed portion is estimated to last ten years.

 

Oil

 

We have a significant CO2 EOR project at Weyburn and a significant waterflood/polymer flood EOR project at Pelican Lake. These projects occur in large, well-developed reservoirs, where undeveloped reserves are not necessarily defined by the absence of drilling, but by improved recovery associated with development of the EOR schemes. Extending both EOR schemes requires intensive capital investment in infrastructure development and will occur over many years.

 

At Weyburn, investment in proved undeveloped reserves is projected to continue for well over 30 years, with drilling of supplementary wells taking place over the next six years and CO2 flood advancement continuing many years beyond that. At Pelican Lake, investment in proved undeveloped reserves is projected to continue for over 20 years, with a combination of infill drilling and polymer flood advancement.

 

Material Changes to Proved Undeveloped Reserves

 

The approval of Christina Lake phase D added approximately 160 million barrels of proved undeveloped bitumen reserves in 2009. Natural gas reserves were reduced by approximately 108 billion cubic feet due to low gas prices.

 

Development Progress

 

In 2009, approximately $240 million was spent to convert 17 million barrels of bitumen, eight million barrels of oil and 41 billion cubic feet of natural gas from proved undeveloped to proved developed reserve status.

 

Aging of Proved Undeveloped Reserves

 

The only current proved undeveloped reserves that have remained undeveloped for five years or more are located in the Pelican Lake EOR project. Limited polymer flooding to date has provided positive indications for broader application throughout the reservoir.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2009

 

24

 

 



Table of Contents

 

Commodity Prices for Reserves Evaluation

 

To estimate Cenovus’s reserves, the IQREs used the following 2009 reference prices:

 

 

 

2009        

 

2008        

 

% Change    

Crude Oil ($/bbl)

 

 

 

 

 

 

WTI

 

61.18        

 

44.60        

 

37    

WCS (C$)

 

58.65        

 

41.98        

 

40    

Natural Gas ($/MMbtu)

 

 

 

 

 

 

Henry Hub

 

3.87        

 

5.71        

 

(32)   

AECO (C$)

 

3.77        

 

6.22        

 

(39)   

 

The 2009 prices reflect the new SEC requirements that prices be determined by using the average of the first day of the month price for each of the 12 months preceding the effective date of the evaluation. The 2008 reference prices were based on prices at December 31, 2008.

 

Other Disclosures About Oil and Gas Activities

 

The tables in this section set forth oil and gas information prepared by us in accordance with the U.S. Financial Accounting Standards Board’s ASC 932-10, “Extractive Activities - Oil and Gas”.

 

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein

 

In calculating the standardized measure of discounted future net cash flows for 2009, 12-month average price and cost assumptions were applied to our annual future production from proved reserves to determine cash inflows. For the 2008 and 2007 calculations of standardized measure of discounted future net cash flows, the prices were based on the year-end price for each of the respective years. Future production and development costs are based on average 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 ten 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 the IQREs in relation to the reserves they respectively evaluated, and adjusted to the extent provided by contractual arrangements such as price risk management activities, in existence at year-end and to account for asset retirement obligations and future income taxes.

 

We caution that the discounted future net cash flows relating to proved oil and gas reserves are an indication of neither the fair market value of our 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 ten percent may not appropriately reflect future interest rates. The computation also excludes values attributable to the marketing of our proprietary production and third-party purchases and sales of product.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2009

 

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Table of Contents

 

Standardized Measure of Discounted Future Net Cash Flows

Relating to Proved Oil and Gas Reserves

 

 

 

2009 

 

2008

 

2007

 

 

 

($ millions)

 

 

Future cash inflows

 

48,006

 

31,626

 

57,706

 

Less future:

 

 

 

 

 

 

 

Production costs

 

16,757

 

15,001

 

17,345

 

Development costs

 

5,313

 

4,334

 

4,635

 

Asset retirement obligation payments

 

2,954

 

1,669

 

1,769

 

Income taxes

 

5,553

 

2,142

 

7,641

 

Future net cash flows

 

17,429

 

8,480

 

26,316

 

Less 10 percent annual discount for estimated timing of cash flows

 

9,816

 

3,366

 

13,472

 

Discounted future net cash flows

 

7,613

(1)

5,114

 

12,844

 

Note:

(1)     2009 discounted future net cash flows have been calculated using 12-month average prices of: crude oil - WTI of $61.18/bbl and WCS of C$58.65/bbl; natural gas - Henry Hub of $3.87/MMbtu and AECO of C$3.77/MMbtu. Future net cash flows would have been $12,524 million using the following single day December 31, 2009 prices: WTI of $79.36/bbl and WCS of C$75.21/bbl; natural gas - Henry Hub of $5.78/MMbtu and AECO of C$5.63/MMbtu. In 2008 and 2007, future net cash flows were calculated using the December 31 period end price for the respective years.

 

Changes in Standardized Measure of Discounted Future Net Cash Flows

Relating to Proved Oil and Gas Reserves

 

 

 

2009

 

2008

 

2007

 

 

 

 

 

($ millions)

 

 

Balance, beginning of year

 

5,114

 

12,844

 

8,963

 

Changes resulting from:

 

 

 

 

 

 

 

Sales of oil and gas produced during the period

 

(3,330

)

(3,896

)

(3,151

)

Discoveries and extensions, net of related costs

 

817

 

165

 

1,330

 

Purchases of proved reserves in place

 

 

 

3

 

Sales of proved reserves in place

 

(11

)

(2

)

(1,244

)

Net change in prices and production costs

 

5,561

 

(10,401

)

6,206

 

Revisions to quantity estimates

 

(270

)

1,589

 

524

 

Accretion of discount

 

632

 

1,647

 

1,127

 

Previously estimated development costs incurred net of changes in future development costs

 

(92

)

670

 

468

 

Other

 

180

 

89

 

(73

)

Net change in income taxes

 

(988

)

2,409

 

(1,309

)

Balance, end of year

 

7,613

 

5,114

 

12,844

 

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2009

 

26

 

 



Table of Contents

 

Results of Operations, Capitalized Costs and Costs Incurred

 

Results of Operations(1)

 

 

 

2009

 

2008

 

2007

 

 

 

($ millions)

 

 

Oil and gas revenues, net of royalties, transportation and selling costs

 

4,058

 

4,732

 

3,883

 

Less:

 

 

 

 

 

 

 

Operating costs, production and mineral taxes, and accretion of asset retirement obligations

 

728

 

836

 

732

 

Depreciation, depletion and amortization

 

1,090

 

1,103

 

1,217

 

Operating income

 

2,240

 

2,793

 

1,934

 

Income taxes

 

634

 

815

 

574

 

Results of operations

 

1,606

 

1,978

 

1,360

 

Note:

(1)  All of our proved oil and gas reserves are located within Canada.

 

Capitalized Costs

 

 

 

2009 

 

2008 

 

2007 

 

 

 

($ millions)

 

 

Proved oil and gas properties

 

19,975

 

16,423

 

19,105

 

Unproved oil and gas properties

 

615

 

177

 

160

 

Total capital cost

 

20,590

 

16,600

 

19,265

 

Accumulated depreciation, depletion and amortization

 

10,945

 

8,476

 

9,707

 

Net capitalized costs

 

9,645

 

8,124

 

9,558

 

 

Costs Incurred

 

 

 

2009

 

2008

 

2007

 

 

 

($ millions)

 

 

Acquisitions

 

 

 

 

 

 

 

– Unproved

 

3

 

 

 

– Proved

 

 

 

14

 

Total acquisitions

 

3

 

 

14

 

Exploration costs

 

60

 

195

 

101

 

Development costs

 

894

 

1,305

 

1,140

 

Total costs incurred

 

957

 

1,500

 

1,255

 

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2009

 

27

 



Table of Contents

 

Production Volumes and Per-Unit Results

 

Production Volumes

 

The following tables summarize our net daily production volumes, after royalties, on a quarterly basis for the periods indicated.

 

 

 

Production Volumes - 2009

 

 

 

Year  

 

Q4   

 

Q3   

 

Q2   

 

Q1   

 

PRODUCTION VOLUMES

 

 

 

 

 

 

 

 

 

 

 

Oil and Natural Gas Liquids (bbls/d)

 

 

 

 

 

 

 

 

 

 

 

Heavy Oil

 

 

 

 

 

 

 

 

 

 

 

Foster Creek

 

36,654

 

45,035

 

38,954

 

34,249

 

28,170

 

Christina Lake

 

6,527

 

7,022

 

6,097

 

6,428

 

6,559

 

Integrated Oil – Other(1)

 

2,553

 

1,921

 

4,401

 

1,800

 

2,069

 

Canadian Plains

 

32,143

 

30,338

 

31,684

 

31,508

 

35,097

 

Light and Medium Oil – Canadian Plains

 

30,721

 

29,110

 

30,676

 

31,183

 

31,946

 

Natural Gas Liquids(2) – Canadian Plains

 

1,186

 

1,164

 

1,216

 

1,162

 

1,201

 

Total Oil and Natural Gas Liquids

 

109,784

 

114,590

 

113,028

 

106,330

 

105,042

 

Natural Gas (MMcf/d)

 

 

 

 

 

 

 

 

 

 

 

Integrated Oil – Other

 

49

 

31

 

51

 

72

 

42

 

Canadian Plains

 

775

 

734

 

775

 

792

 

800

 

Total Natural Gas

 

824

 

765

 

826

 

864

 

842

 

Total (BOE/d)

 

247,117

 

242,090

 

250,695

 

250,330

 

245,375

 

Notes:

(1)  Senlac property sold November 2009.

(2)  Natural gas liquids include condensate volumes.

 

 

 

Production Volumes - 2008

 

 

 

Year  

 

Q4   

 

Q3   

 

Q2   

 

Q1   

 

PRODUCTION VOLUMES

 

 

 

 

 

 

 

 

 

 

 

Oil and Natural Gas Liquids (bbls/d)

 

 

 

 

 

 

 

 

 

 

 

Heavy Oil

 

 

 

 

 

 

 

 

 

 

 

Foster Creek

 

25,947

 

28,955

 

26,979

 

21,038

 

26,770

 

Christina Lake

 

4,236

 

6,113

 

4,568

 

3,633

 

2,606

 

Integrated Oil – Other

 

2,729

 

2,133

 

2,273

 

3,009

 

3,514

 

Canadian Plains

 

35,029

 

32,843

 

34,655

 

34,618

 

38,029

 

Light and Medium Oil – Canadian Plains

 

31,128

 

32,147

 

30,134

 

30,479

 

31,752

 

Natural Gas Liquids(1) – Canadian Plains

 

1,181

 

1,126

 

1,147

 

1,189

 

1,262

 

Total Oil and Natural Gas Liquids

 

100,250

 

103,317

 

99,756

 

93,966

 

103,933

 

Natural Gas (MMcf/d)

 

 

 

 

 

 

 

 

 

 

 

Integrated Oil – Other

 

63

 

59

 

61

 

67

 

65

 

Canadian Plains

 

842

 

820

 

831

 

856

 

860

 

Total Natural Gas

 

905

 

879

 

892

 

923

 

925

 

Total (BOE/d)

 

251,083

 

249,817

 

248,423

 

247,799

 

258,100

 

Note:

(1)  Natural gas liquids include condensate volumes.

 

 

 

Production Volumes - 2007