40-F 1 a12-4456_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

 

 

þ

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

 

For the fiscal year ended: December 31, 2011      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:

 

 

þ Annual information form      þ 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:

 

754,499,336

 

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 þ   No o

 

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), Form
F-3 (File No. 333-166419), and Form F-9 (File No. 333-167876).

 

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Principal Documents

 

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

 

(a)

Annual Information Form of Cenovus Energy Inc. for the fiscal year ended December 31, 2011.

 

 

(b)

Management’s Discussion and Analysis of Cenovus Energy Inc. for the fiscal year ended December 31, 2011.

 

 

(c)

Consolidated Financial Statements of Cenovus Energy Inc. as at December 31, 2011.

 

 

 

 

 

 

 

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CENOVUS ENERGY INC.

 

 

ANNUAL INFORMATION FORM

 

FOR THE YEAR ENDED DECEMBER 31, 2011

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2011

 



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TABLE OF CONTENTS

 

 

FORWARD-LOOKING INFORMATION

1

CORPORATE STRUCTURE

2

GENERAL DEVELOPMENT OF OUR BUSINESS

2

NARRATIVE DESCRIPTION OF OUR BUSINESS

5

Oil Sands

6

Conventional

9

Refining and Marketing

12

RESERVES DATA AND OTHER OIL AND GAS INFORMATION

13

Disclosure of Reserves Data

14

Definitions

16

Reserves Reconciliation

19

Contingent and Prospective Resources

21

Other Oil and Gas Information

24

OTHER INFORMATION

34

Competitive Conditions

34

Environmental Considerations

34

Corporate Responsibility Practice

35

Employees

36

Foreign Operations

36

DIRECTORS AND EXECUTIVE OFFICERS

37

AUDIT COMMITTEE

41

DESCRIPTION OF CAPITAL STRUCTURE

43

DIVIDENDS

45

MARKET FOR SECURITIES

46

RISK FACTORS

46

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

55

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

55

MATERIAL CONTRACTS

56

TRANSFER AGENTS AND REGISTRARS

56

ADDITIONAL INFORMATION

56

ABBREVIATIONS AND CONVERSIONS

57

 

 

APPENDIX A -

Report on Reserves Data by Independent Qualified Reserves Evaluators

APPENDIX B -

Report of Management and Directors on Reserves Data and Other Information

APPENDIX C -

Audit Committee Mandate

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2011

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FORWARD-LOOKING INFORMATION

 

This Annual Information Form (“AIF”) contains forward-looking statements and other information (collectively “forward-looking information”) about our current expectations, estimates and projections, made in light of our experience and perception of historical trends. This forward-looking information is identified by words such as “anticipate”, “believe”, “expect”, “plan”, “forecast”, “target”, “project”, “could”, “focus”, “vision”, “goal”, “proposed”, “scheduled”, “outlook”, “potential”, “may” or similar expressions and includes suggestions of future outcomes, including statements about our growth strategy and related schedules, projected future value or net asset value, forecast operating and financial results, planned capital expenditures, expected future production, including the timing, stability or growth thereof, anticipated finding and development costs, expected reserves and contingent and prospective resources estimates, potential dividends and dividend growth strategy, anticipated timelines for future regulatory, partner or internal approvals, forecasted commodity prices, future use and development of technology and projected increasing shareholder value. Readers are cautioned not to place undue reliance on forward-looking information as our actual results may differ materially from those expressed or implied.

 

Developing forward-looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which are specific to Cenovus and others that apply to the industry in general.

 

The factors or assumptions on which the forward-looking information is based include: assumptions inherent in our current guidance, available at www.cenovus.com; our projected capital investment levels, the flexibility of capital spending plans and the associated source of funding; estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; our ability to obtain necessary regulatory and partner approvals; the successful and timely implementation of capital projects; our ability to generate sufficient cash flow from operations to meet our current and future obligations; and other risks and uncertainties described from time to time in the filings we make with securities regulatory authorities.

 

The risk factors and uncertainties that could cause our actual results to differ materially, include: volatility of and assumptions regarding oil and gas prices; the effectiveness of our risk management program, including the impact of derivative financial instruments and our access to various sources of capital; accuracy of cost estimates; fluctuations in commodity prices, currency and interest rates; fluctuations in product supply and demand; market competition, including from alternative energy sources; risks inherent in our marketing operations, including credit risks; maintaining desirable ratios of debt to adjusted earnings before interest, taxes, depreciation and amortization and debt to capitalization; our ability to access external sources of debt and equity capital; success of our hedging strategies; accuracy of reserves, resources and future production estimates; our ability to replace and expand oil and gas reserves; our ability to maintain our relationship with ConocoPhillips (or any successor thereof) and to successfully manage and operate our integrated heavy oil business; reliability of our assets; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; refining and marketing margins; potential failure of new products to achieve acceptance in the market; unexpected cost increases or technical difficulties in constructing or modifying manufacturing or refining facilities; unexpected difficulties in manufacturing, transporting or refining of crude oil into petroleum and chemical products at two refineries; risks associated with technology and its application to our business; the timing and the costs of well and pipeline construction; our ability to secure adequate product transportation; changes in the regulatory framework in any of the locations in which we operate, including changes to the regulatory approval process and land-use designations, royalty, tax, environmental, greenhouse gas, carbon and other laws or regulations, or changes to the interpretation of such laws and regulations, as adopted or proposed, the impact thereof and the costs associated with compliance; the expected impact and timing of various accounting pronouncements, rule changes and standards on our business, our financial results and our Consolidated Financial Statements; changes in the general economic, market and business conditions; the political and economic conditions in the locations in which we operate; the occurrence of unexpected events such as war, terrorist threats and the instability resulting therefrom; and risks associated with existing and potential future lawsuits and regulatory actions against us.

 

Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. For a full discussion of our material risk factors, see “Risk Factors” in this AIF. Readers should also refer to “Risk Management” in our current Management’s Discussion and Analysis and to the risk factors described in other documents we file from time to time with securities regulatory authorities, available at www.sedar.com, www.sec.gov and on our website at www.cenovus.com.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2011

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CORPORATE STRUCTURE

 

Cenovus Energy Inc. was formed under the Canada Business Corporations Act (“CBCA”) by amalgamation of 7050372 Canada Inc. and Cenovus Energy Inc. (formerly Encana Finance Ltd. and referred to as “Subco”) on November 30, 2009 pursuant to an arrangement under the CBCA (the “Arrangement”) involving, among others, 7050372 Canada Inc., Subco and Encana Corporation (“Encana”). On January 1, 2011, we amalgamated with our wholly owned subsidiary, Cenovus Marketing Holdings Ltd., through a plan of arrangement approved by the Alberta Court of Queen’s Bench.

 

Unless otherwise specified or the context otherwise requires, reference to “we”, “us”, “our”, “its”, “Company” or “Cenovus” includes reference to subsidiaries of, and partnership interests held by, Cenovus Energy Inc. and its subsidiaries and, when in reference to prior period information, as held by Encana prior to the closing of the Arrangement.

 

Our principal and registered office is located at #4000, 421 – 7 Avenue S.W., Calgary, Alberta, Canada T2P 4K9.

 

Intercorporate Relationships

 

The following table summarizes our principal subsidiaries and partnerships at December 31, 2011:

 

 

Subsidiaries & Partnerships

 

Percentage
Owned
(1)

 

Jurisdiction of
Incorporation,
Continuance, Formation
or Organization

Cenovus FCCL Ltd.

 

100

 

Alberta

Cenovus US Refinery Holdings(2)

 

100

 

Delaware

FCCL Partnership (“FCCL”)(3)

 

50

 

Alberta

WRB Refining LP (“WRB”) (4)

 

50

 

Delaware

Notes:

(1)    Includes direct and indirect ownership.

(2)    A Delaware partnership.

(3)    Cenovus interest held through Cenovus FCCL Ltd., the operator and managing partner of FCCL Partnership.

(4)    Cenovus interest held indirectly through Cenovus US Refinery Holdings.

 

The above table includes our subsidiaries and partnerships which have total assets that exceed 10 percent of our total consolidated assets, or revenues which exceed 10 percent of our total consolidated revenues. The assets and revenues of our unidentified subsidiaries and partnerships did not exceed 20 percent of our total consolidated assets or total consolidated revenues at and for the year ended December 31, 2011.

 

 

GENERAL DEVELOPMENT OF OUR BUSINESS

 

Cenovus is a Canadian oil company headquartered in Calgary, Alberta. Our operations include oil sands 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, U.S.A.

 

We began independent operations on December 1, 2009 following the split of Encana into two independent publicly traded energy companies, Cenovus and Encana.

 

Our Business

 

Our reportable segments are as follows:

 

·        Oil Sands, which consists of Cenovus’s producing bitumen assets at Foster Creek and Christina Lake, heavy oil assets at Pelican Lake, new resource play assets such as Narrows Lake, Grand Rapids and Telephone Lake, and the Athabasca natural gas assets. Certain of the Company’s operated oil sands properties, notably Foster Creek, Christina Lake and Narrows Lake, are jointly owned with ConocoPhillips, an unrelated U.S. public company.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2011

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·        Conventional, which includes the development and production of conventional crude oil, natural gas and NGLs in Alberta and Saskatchewan, notably the carbon dioxide enhanced oil recovery project at Weyburn, and the Bakken and Lower Shaunavon crude oil properties.

 

·        Refining and Marketing, which is focused on the refining of crude oil products into petroleum and chemical products at two refineries located in the U.S. The refineries are jointly owned with and operated by ConocoPhillips. This segment 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.

 

·        Corporate and Eliminations, which primarily includes unrealized gains and losses recorded on derivative financial instruments, gains and losses on divestiture of assets, as well as other Cenovus-wide costs for general and administrative and financing activities. As financial instruments are settled, the 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.

 

Three Year History

 

The following describes the significant events of the last three years in respect of our business:

 

2011

 

·        In the second quarter, we updated our 10 year strategic plan, identifying oil sands production of more than 400,000 bbls/d net and total oil production of approximately 500,000 bbls/d net, by the end of 2021.

 

·        In the second quarter, we received regulatory approval for Christina Lake phases E, F and G. Planned gross production capacity for each expansion phase is 40,000 bbls/d for a total of 120,000 bbls/d of bitumen. Also in the second quarter, partner approval was received for phase E.

 

·        In the second quarter, we received approval from the Alberta Department of Energy (“ADOE”) to include all previous capital investment for Foster Creek expansion phases F, G and H as part of our existing Foster Creek royalty calculation.

 

·        In the second quarter, we announced plans to increase gross production capacity at each of Foster Creek phases F, G and H from 30,000 to 35,000 bbls/d and received partner approval for each phase. Planned gross production capacity for each expansion phase was further increased to 40,000 bbls/d for phases G and H and to 45,000 bbls/d for phase F, due to the success of our Wedge WellTM technology and plant optimization. Total gross production capacity for these three phases at completion is expected to be 125,000 bbls/d of bitumen.

 

·        In the third quarter, phase C of Christina Lake achieved first production ahead of schedule and with capital expenditures below budget for the entire phase. Net production at Christina Lake during 2011 averaged 11,665 bbls/d and ended 2011 at approximately 23,000 bbls/d.

 

·        In the fourth quarter, we completed coker construction and start up activities of the Coker and Refinery Expansion (“CORE”) project, at the Wood River Refinery. CORE project capital expenditures were within 10 percent of its original budget. Test runs of the CORE project, which will continue through the first quarter of 2012, have been successful to date and have resulted in a five percent increase to clean product yield. Upon completion of testing, the Wood River Refinery’s total processing capability of heavy crude oil will be dependent on the quality of heavy Canadian crude oil that is economically available, and is expected to increase to 200,000 to 220,000 bbls/d.

 

·        In the fourth quarter, Cenovus filed a joint application and Environmental Impact Assessment (“EIA”) for a commercial SAGD operation at Grand Rapids with a gross production capacity of 180,000 bbls/d.

 

·        In the fourth quarter, progressing the Telephone Lake project, we filed a revised joint regulatory application and EIA. This application updates the expected gross production capacity to 90,000 bbls/d from the original 35,000 bbls/d application that was filed in 2007.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2011

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·        In the fourth quarter, we applied for an amendment to the existing Christina Lake regulatory approval to add cogeneration facilities and increasing expected total gross production capacity by 10,000 bbls/d at each of phase F and phase G.

 

2010

 

·        In the second quarter, an application for the Narrows Lake project in the Christina Lake Region was submitted to the Energy Resources Conservation Board (“ERCB”) and Alberta Environment. The project is jointly owned with ConocoPhillips and is expected to be developed in three phases with a total gross production capacity of 130,000 bbls/d of bitumen.

 

·        In the third quarter, regulatory approval was received for Foster Creek phases F, G and H. Planned gross production capacity for each expansion phase is 30,000 bbls/d for a total gross production capacity of 90,000 bbls/d of bitumen.

 

·        In the fourth quarter, we started up our Grand Rapids pilot project after receiving project approval from Alberta Environment. We had previously received project approval from the ERCB in the second quarter of 2010.

 

2009

 

·        In the first quarter, two new expansion phases at Foster Creek were commissioned. Phases D and E added gross capacity of 60,000 bbls/d of bitumen, increasing gross production capacity of Foster Creek to approximately 120,000 bbls/d of bitumen.

 

·        In the second quarter, a joint regulatory application for Foster Creek phases F, G and H was submitted to the ERCB and Alberta Environment.

 

·        In the fourth quarter, FCCL sanctioned the next phase, phase D, of expansion at Christina Lake, which is expected to increase gross production capacity by 40,000 bbls/d of bitumen in 2013.

 

·        In the fourth quarter, 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 gross production capacity by 40,000 bbls/d of bitumen.

 

·        On December 1, 2009, we began independent operations as a publicly traded company having completed the Arrangement with Encana. In connection with the Arrangement, Encana shareholders received one Cenovus common share and one new Encana common share for each Encana common share held.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2011

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NARRATIVE DESCRIPTION OF OUR BUSINESS

 

The following map outlines the location of our upstream and refining assets as at December 31, 2011.

 

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2011

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Overview

 

All of our reserves and production are located in Canada, primarily within the provinces of Alberta and Saskatchewan. At December 31, 2011, we had a land base of approximately 7.4 million net acres and Company Interest Before Royalties proved reserves of approximately 1,455 million barrels of bitumen, 175 million barrels of heavy crude oil, 115 million barrels of light and medium crude oil and NGLs and 1,203 billion cubic feet of natural gas. The estimated proved reserves life index based on working interest production at December 31, 2011 was approximately 22 years. We also had Company Interest Before Royalties probable reserves of approximately 490 million barrels of bitumen, 109 million barrels of heavy crude oil, 51 million barrels of light and medium crude oil and NGLs and 391 billion cubic feet of natural gas at December 31, 2011.

 

The following narrative describes our operations in greater detail.

 

Oil Sands

 

Oil Sands includes our producing bitumen assets at Foster Creek and Christina Lake, as well as heavy crude oil assets at Pelican Lake, new resource play assets including Narrows Lake, Grand Rapids and Telephone Lake, and the Athabasca natural gas assets. The Foster Creek and Christina Lake operations as well as the Narrows Lake property are jointly owned with ConocoPhillips, an unrelated U.S. public company, through the FCCL Partnership (“FCCL”).

 

FCCL owns the Foster Creek, Christina Lake and Narrows Lake properties, as well as other bitumen interests. Cenovus FCCL Ltd., our wholly owned subsidiary, is the operator and managing partner of FCCL, and owns 50 percent of FCCL. FCCL has a management committee, which is composed of three Cenovus representatives and three ConocoPhillips representatives, with each company holding equal voting rights.

 

In 2011, our Oil Sands capital investment was $1,415 million, and was primarily related to the expansion of the production capacity of FCCL’s assets. FCCL plans to increase gross production capacity to approximately 218,000 bbls/d of bitumen following the completion of Christina Lake phase D, which is expected in the fourth quarter of 2012. Pelican Lake capital investment for 2011 was primarily related to infill drilling to progress polymer flood, drilling of stratigraphic test wells, facilities expansions and maintenance capital. Oil Sands also continued to assess the potential of our new resource play assets during 2011 with our large stratigraphic test well program.

 

Plans for 2012 include the continued development of expansion phases at both Foster Creek and Christina Lake, additional capital investment at our Pelican Lake property, the continuation of an active stratigraphic test well program on our new resource play assets and progressing pilot projects at our Grand Rapids and Telephone Lake properties.

 

At December 31, 2011, we held bitumen rights of approximately 1,227,000 gross acres (889,000 net acres) within the Athabasca and Cold Lake areas, as well as the exclusive rights to lease an additional 544,000 net acres on our behalf and/or our assignee’s behalf on the Cold Lake Air Weapons Range.

 

The following table summarizes our landholdings at December 31, 2011:

 

Landholdings – Oil Sands

 

Developed

 

Undeveloped

 

Total

 

Average
Working

(thousands of acres)

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Interest

Foster Creek

 

12

 

6

 

130

 

65

 

142

 

71

 

50%

Christina Lake

 

6

 

3

 

33

 

16

 

39

 

19

 

50%

Pelican Lake

 

105

 

105

 

287

 

283

 

392

 

388

 

99%

Telephone Lake

 

4

 

4

 

142

 

142

 

146

 

146

 

100%

Athabasca

 

445

 

370

 

426

 

355

 

871

 

725

 

83%

Other

 

49

 

31

 

956

 

691

 

1,005

 

722

 

72%

Total

 

621

 

519

 

1,974

 

1,552

 

2,595

 

2,071

 

80%

 

 

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

 

Production – Oil Sands

 

Crude Oil
and NGLs
(bbls/d)

 

Natural Gas
(MMcf/d)

 

Total
Production
(BOE/d)

 

(annual average)

 

2011

 

2010

 

2011

 

2010

 

2011

 

2010

 

Foster Creek

 

54,868

 

51,147

 

-

 

-

 

54,868

 

51,147

 

Christina Lake

 

11,665

 

7,898

 

-

 

-

 

11,665

 

7,898

 

Pelican Lake

 

20,424

 

22,966

 

-

 

-

 

20,424

 

22,966

 

Athabasca

 

-

 

-

 

34

 

40

 

5,667

 

6,667

 

Other

 

-

 

-

 

3

 

3

 

500

 

500

 

Total

 

86,957

 

82,011

 

37

 

43

 

93,124

 

89,178

 

 

The following table summarizes our interests in producing wells at December 31, 2011. These figures exclude wells which were capable of producing, but that were not producing as of December 31, 2011:

 

Producing Wells – Oil Sands

 

Producing
Oil Wells

 

Producing
Gas Wells

 

Total
Producing Wells

 

(number of wells)

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Foster Creek

 

204

 

102

 

-

 

-

 

204

 

102

 

Christina Lake

 

38

 

19

 

-

 

-

 

38

 

19

 

Pelican Lake

 

444

 

444

 

5

 

5

 

449

 

449

 

Athabasca

 

-

 

-

 

416

 

394

 

416

 

394

 

Other

 

1

 

1

 

17

 

17

 

18

 

18

 

Total

 

687

 

566

 

438

 

416

 

1,125

 

982

 

 

Foster Creek

 

We have a 50 percent interest in Foster Creek, an oil sands property in northeast Alberta that uses steam-assisted gravity drainage (“SAGD”) technology and produces from the McMurray formation. We hold surface access rights from the Governments of Canada and Alberta and bitumen rights from the Government of Alberta for exploration, development and transportation from areas within the Cold Lake Air Weapons Range. 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.

 

We have successfully piloted and implemented our Wedge WellTM technology at Foster Creek whereby an additional 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. This technology requires minimal additional steam, thus it helps reduce the overall steam to oil ratio. In 2011, we drilled 10 wells (2010 – 20 wells) using this technology, and at December 31, 2011 there were 41 wells of this type producing.

 

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 any excess power generated is being sold into the Alberta Power Pool.

 

Christina Lake

 

We have a 50 percent interest in Christina Lake, an oil sands property in northeast Alberta that uses SAGD technology and produces from the McMurray formation. The phase C expansion, completed in 2011, increased gross production capacity to approximately 58,000 bbls/d of bitumen. In 2011, we received regulatory approval for phases E, F and G which are expected to add a total of approximately 140,000 bbls/d of gross bitumen production capacity. In the fourth quarter of 2011, we applied for an amendment to our existing application to add cogeneration facilities at Christina Lake and increasing total gross production capacity by 10,000 bbls/d at each of phase F and phase G. In 2011, we drilled three wells (2010 – four wells) at Christina Lake using our Wedge WellTM technology and at December 31, 2011 there were four wells of this type producing.

 

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

 

 

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In 2011, we applied steam dilation technology as part of the Christina Lake phase C start up. As steam is injected into the injector and producer wells at high pressure, the force of the steam rearranges the sand grains and creates gaps, which are filled with water. This increases both porosity and water mobility, allowing fluid flow between the wells. Steam dilation requires minimal additional costs or surface facility modifications, takes less than one month and results in more uniform start up along the full length of the well pairs. This allows the well to reach peak production rates more quickly. Steam benefits include a faster start up time, a reduction in steam circulation time and a decrease in cumulative steam to oil ratio.

 

Narrows Lake

 

We hold a 50 percent interest in Narrows Lake, an oil sands property within the Christina Lake Region in northeast Alberta. In the first quarter of 2010, we initiated the regulatory approval process for Narrows Lake by filing proposed terms of reference for an EIA and began public consultation for the project. In the second quarter of 2010, final terms of reference were issued by Alberta Environment and a joint application and EIA was filed. The project includes gross production capacity of 130,000 bbls/d of bitumen to be developed in up to three phases, with the first phase expected to have production capacity of approximately 40,000 bbls/d of bitumen. Our submitted application includes the option to implement the SAP technology at Narrows Lake which would allow the project to be developed in two phases of 65,000 bbls/d, rather than three phases. The project is expected to begin producing in 2016, subject to receiving regulatory approval.

 

Pelican Lake

 

Using a pattern, horizontal well polymer flood, we produce heavy crude oil from the Cretaceous Wabiskaw formation at our Pelican Lake property, which is located within the Greater Pelican Region in northeast Alberta. In 2011, our capital investment primarily related to infill drilling to progress the polymer flood, drilling of stratigraphic test wells, facilities expansions and maintenance programs. In 2011 we drilled 31 heavy oil wells.

 

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.

 

New Resource Play Assets

 

Our new resource play assets include our emerging oil sands properties.

 

Our Grand Rapids property is located in the Greater Pelican Region in northeast Alberta, where large deposits of bitumen have been identified in the Cretaceous Grand Rapids formation. During 2011, we executed a pilot project at Grand Rapids which will continue to be operated during 2012. In the fourth quarter of 2011, we filed a joint application and EIA for a commercial operation with production capacity of 180,000 bbls/d.

 

Our Telephone Lake property is located in the Borealis Region in northeast Alberta. A joint application and EIA was submitted in 2007 to the ERCB and Alberta Environment for the development of the property, including the construction of a facility with bitumen production capacity of 35,000 bbls/d. In the fourth quarter of 2011, we submitted a revised joint application and EIA, which increases the planned production capacity to 90,000 bbls/d. Portions of the Telephone Lake reservoir are overlain with non-saline water. To improve SAGD performance, this water should be removed in advance of SAGD operations. In the first quarter of 2012, a significant test will be carried out to dewater a confined area and the results will be monitored throughout the year.

 

The Steepbank and East McMurray properties are also located in the Borealis Region, southwest of Telephone Lake. An active exploration program is being carried out at these properties. In 2011, 44 stratigraphic wells were drilled and 210 km of 2D seismic was shot. A comparable sized program is underway in 2012.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2011

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Table of Contents

 

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 ERCB decisions made between 2003 and 2009 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 our annualized natural gas production of approximately 21 million cubic feet per day in 2011 (2010 - 23 million cubic feet per day). The ADOE is providing financial assistance in the form of a royalty credit, which can equal up to approximately 50 percent of the cash flow lost as a result of the shut-in wells but is dependant on natural gas prices.

 

Conventional

 

We have conventional crude oil and natural gas operations in Alberta and Saskatchewan. Conventional operations include crude oil properties in southern Alberta, the Weyburn CO2 enhanced oil recovery project as well as our Bakken and Lower Shaunavon properties.

 

At December 31, 2011, we had an established land position of approximately 5.5 million gross acres (5.3 million net acres), of which approximately 3.7 million gross acres (3.6 million net acres) are developed. The mineral rights on approximately 59 percent of our net landholdings 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. We may lease out a portion of our fee lands in areas where the land is not consistent with our long range business plan. We lease Crown lands in some areas in Alberta, mainly in the Early Cretaceous geological formations, primarily in the Suffield and Wainwright areas. In Saskatchewan, the majority of our current production comes from lands leased from the Province of Saskatchewan.

 

In 2011, our Conventional capital investment was $788 million and primarily focused on crude oil properties, including drilling and facility work at Weyburn and in southern Alberta as well as drilling in the Bakken and Lower Shaunavon areas.

 

Plans for 2012 include additional capital investment in our Weyburn, Bakken and Lower Shaunavon properties as well as our Alberta crude oil properties. The investment is expected to include additional drilling, well optimizations, well recompletions and investment in facility infrastructure necessary for continued development of our assets.

 

The following table summarizes our landholdings at December 31, 2011:

 

Landholdings – Conventional

 

Developed

 

Undeveloped

 

Total

 

 

Average
Working

(thousands of acres)

 

Gross

 

Net

 

Gross

 

Net

 

 

Gross

 

Net

 

 

Interest

Alberta

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Suffield

 

915

 

906

 

106

 

103

 

 

1,021

 

1,009

 

 

99%

Brooks North

 

571

 

569

 

8

 

8

 

 

579

 

577

 

 

100%

Langevin

 

730

 

691

 

244

 

226

 

 

974

 

917

 

 

94%

Drumheller

 

402

 

390

 

45

 

42

 

 

447

 

432

 

 

97%

Wainwright

 

354

 

332

 

208

 

203

 

 

562

 

535

 

 

95%

Boyer

 

590

 

558

 

204

 

164

 

 

794

 

722

 

 

91%

Saskatchewan

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weyburn

 

108

 

95

 

368

 

348

 

 

476

 

443

 

 

93%

Shaunavon / Bakken

 

26

 

24

 

370

 

367

 

 

396

 

391

 

 

99%

Other

 

9

 

6

 

19

 

19

 

 

28

 

25

 

 

87%

Manitoba

 

3

 

3

 

261

 

261

 

 

264

 

264

 

 

100%

Total

 

3,708

 

3,574

 

1,833

 

1,741

 

 

5,541

 

5,315

 

 

96%

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2011

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Table of Contents

 

The following table summarizes our share of daily average production for the periods indicated:

 

Production – Conventional

 

Crude Oil
and NGLs
(bbls/d)

 

Natural Gas
(MMcf/d)

 

Total
Production
(BOE/d)

(annual average)

 

2011

 

2010

 

2011

 

2010

 

2011

 

2010

Alberta

 

 

 

 

 

 

 

 

 

 

 

 

Suffield

 

11,505

 

12,742

 

182

 

200

 

41,838

 

46,075

Brooks North

 

2,064

 

1,637

 

236

 

240

 

41,397

 

41,637

Langevin

 

7,361

 

7,728

 

118

 

152

 

27,028

 

33,062

Drumheller

 

2,298

 

2,109

 

61

 

72

 

12,465

 

14,109

Wainwright

 

4,251

 

4,414

 

-

 

3

 

4,251

 

4,914

Boyer

 

9

 

13

 

22

 

24

 

3,676

 

4,013

Saskatchewan

 

 

 

 

 

 

 

 

 

 

 

 

Weyburn

 

16,178

 

16,537

 

-

 

-

 

16,178

 

16,537

Shaunavon / Bakken

 

3,616

 

1,996

 

-

 

3

 

3,616

 

2,496

Total

 

47,282

 

47,176

 

619

 

694

 

150,449

 

162,843

 

The following table summarizes our interests in producing wells at December 31, 2011. These figures exclude wells which were capable of producing, but that were not producing, at December 31, 2011:

 

Producing Wells – Conventional

 

Producing
Oil Wells

 

Producing
Gas Wells

 

Total
Producing Wells

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Alberta

 

 

 

 

 

 

 

 

 

 

 

 

 

Suffield

 

746

 

746

 

10,649

 

10,631

 

11,395

 

11,377

 

Brooks North

 

111

 

111

 

7,520

 

7,411

 

7,631

 

7,522

 

Langevin

 

243

 

240

 

4,842

 

4,826

 

5,085

 

5,066

 

Drumheller

 

169

 

165

 

1,615

 

1,555

 

1,784

 

1,720

 

Wainwright

 

442

 

400

 

19

 

5

 

461

 

406

 

Boyer

 

7

 

1

 

1,079

 

1,078

 

1,086

 

1,079

 

Saskatchewan

 

 

 

 

 

 

 

 

 

 

 

 

 

Weyburn

 

712

 

448

 

-

 

-

 

712

 

448

 

Shaunavon / Bakken

 

96

 

93

 

-

 

-

 

96

 

93

 

Total

 

2,526

 

2,204

 

25,724

 

25,506

 

28,250

 

27,710

 

 

Crude Oil Properties

 

We hold interests in multiple zones in the Suffield, Brooks North, Langevin, Drumheller, and Wainwright areas in southern Alberta with a mix of medium and heavy crude oil production. Development in these areas focuses on infill drilling, optimization of existing wells and other specialized oil recovery methods. We operate water handling facilities to effectively manage oil production.

 

In the unitized portion of the Weyburn crude oil field in southeast Saskatchewan we have a 62 percent working interest. However, after taking into consideration a net royalty interest obligation to a third party, our economic interest is 50 percent. The Weyburn unit produces light and medium sour crude oil from the Mississippian Midale formation and covers 78 sections of land. Cenovus is the operator and we are increasing ultimate recovery of crude oil with a CO2 miscible flood project. At December 31, 2011, approximately 87 percent of the approved CO2 flood pattern development at the Weyburn unit was complete. Since the inception of the project, approximately 18 million tonnes of CO2 have been injected as part of the program. The CO2 is delivered by pipeline directly to the Weyburn facility from a coal gasification project in North Dakota, U.S.A.

 

In 2011, we continued developing our medium and light crude oil prospects in the Bakken and Lower Shaunavon zones in Saskatchewan, where we drilled 81 wells and increased production to approximately 3,581 bbls/d of crude oil. Most of the sections of land that we hold in these areas are Crown land.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2011

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Table of Contents

 

The following table summarizes net oil wells drilled and daily average oil production figures for the periods indicated:

 

 

 

 

 

 

 

Average
Production (bbls/d)

 

 

 

Net
Wells Drilled

 

Light/Medium

 

Heavy

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Wells Drilled and Production

 

2011

 

2010

 

2011

 

2010

 

2011

 

2010

 

Alberta

 

 

 

 

 

 

 

 

 

 

 

 

 

Suffield

 

45

 

43

 

-

 

-

 

11,484

 

12,717

 

Brooks North

 

42

 

41

 

1,898

 

1,458

 

-

 

-

 

Langevin

 

68

 

22

 

7,172

 

7,529

 

-

 

-

 

Drumheller

 

49

 

30

 

1,617

 

1,403

 

-

 

-

 

Wainwright

 

29

 

3

 

67

 

452

 

4,173

 

3,942

 

Boyer

 

-

 

-

 

9

 

12

 

-

 

-

 

Saskatchewan

 

 

 

 

 

 

 

 

 

 

 

 

 

Weyburn

 

6

 

3

 

16,180

 

16,534

 

-

 

-

 

Shaunavon / Bakken

 

81

 

36

 

3,581

 

1,958

 

-

 

-

 

Other

 

5

 

2

 

-

 

-

 

-

 

-

 

Total

 

325

 

180

 

30,524

 

29,346

 

15,657

 

16,659

 

 

Natural Gas Properties

 

We hold interests in multiple zones in the Suffield, Brooks North, Langevin and Drumheller areas in southern Alberta. Development in these areas focuses on recompletions and optimization of existing wells.

 

The following table summarizes net gas wells drilled and daily average gas production for the periods indicated:

 

 

 

 

Net
Wells Drilled

 

Average Production
(MMcf/d)

 

Net Wells Drilled and Production

 

2011

 

2010

 

2011

 

2010

 

Suffield

 

-

 

292

 

182

 

200

 

Brooks North

 

65

 

149

 

236

 

240

 

Langevin

 

-

 

24

 

118

 

152

 

Drumheller

 

-

 

29

 

61

 

72

 

Other

 

-

 

1

 

22

 

30

 

Total

 

65

 

495

 

619

 

694

 

 

Suffield is one of the core areas of our crude oil and natural gas production in Alberta. 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 Canadian Forces Base (“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, 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.

 

Natural gas assets are an important component of our financial foundation, generating operating cash flow well in excess of their ongoing capital investment requirements. The natural gas business also acts as an economic hedge against price fluctuations, because natural gas fuels the Company’s oil sands and refining operations.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2011

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Table of Contents

 

We plan to manage declines in natural gas volumes, targeting a long-term production level that will match Cenovus’s future anticipated internal usage at its oil sands and refining facilities.

 

Refining and Marketing

 

Refining

 

Through WRB Refining LP (“WRB”) we have a 50 percent ownership interest in both the Wood River and Borger Refineries located in Roxana, Illinois and Borger, Texas respectively. ConocoPhillips is the operator and managing partner of WRB. WRB has a management committee, which is composed of three Cenovus representatives and three ConocoPhillips representatives, with each company holding equal voting rights. Throughout 2011, on a 100 percent basis, our refineries had a capacity of approximately 452,000 bbls/d of crude oil and approximately 45,000 bbls/d of NGLs, including processing capability of up to 145,000 bbls/d of heavy crude oil. As plant test runs proceed, maximum demonstrated refining capacity increases attributable to the CORE project at the Wood River Refinery, including expanded coking and heavy crude oil processing capabilities, will be reflected in our 2012 operations.

 

Wood River Refinery

 

Throughout 2011, the Wood River Refinery had a processing capability of approximately 306,000 bbls/d, including approximately 110,000 bbls/d of heavy crude oil. It processes light low-sulphur and heavy high-sulphur crude oil that it receives from North American crude oil pipelines to produce gasoline, diesel and jet fuel, petrochemical feedstocks and asphalt. The gasoline and diesel are transported via pipelines to markets in the upper U.S. Midwest. Other products are transported via pipeline, truck, barge and railcar to markets in the U.S. Midwest.

 

Test runs of the CORE project, which will continue through the first quarter of 2012, have been successful to date and have resulted in a five percent increase to clean product yield.  Upon completion of testing, the Wood River Refinery’s total processing capability of heavy crude oil will be dependent on the quality of heavy Canadian crude oil that is economically available, and is expected to increase to 200,000 to 220,000 bbls/d.

 

Borger Refinery

 

At December 31, 2011, the Borger Refinery had a processing capacity of approximately 146,000 bbls/d of crude oil, including approximately 35,000 bbls/d of heavy crude oil, and approximately 45,000 bbls/d of NGLs. It processes mainly medium 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.

 

The following table summarizes the key operational results for our refineries in the periods indicated:

 

Refinery Operations(1)

 

2011

 

2010

Crude Oil Capacity (Mbbls/d)

 

452

 

452

Crude Oil Runs (Mbbls/d)

 

401

 

386

Crude Utilization (%)

 

89

 

86

Refined Products (Mbbls/d)

 

 

 

 

Gasoline

 

207

 

204

Distillates

 

132

 

123

Other

 

80

 

78

Total

 

419

 

405

Note:

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

 

Marketing

 

Our Marketing group is focused on enhancing the netback price of our production. As part of these activities, the group also carries out third-party purchases and sales of product to provide operational flexibility for transportation commitments, product quality, delivery points and customer diversification.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2011

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Table of Contents

 

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 transactions related to our various risk management positions for crude oil, natural gas and power are found in the notes to our audited Consolidated Financial Statements for the year ended December 31, 2011.

 

Crude Oil Marketing

 

We manage the transportation and marketing of crude oil for our upstream operations. 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. Our portfolio of transportation commitments includes feeder pipelines from our production areas to the Edmonton and Hardisty trade centres and major pipeline alternatives to markets downstream of these hubs. Other transportation commitments are primarily related to the reliable supply of diluent, as well as tankage, terminalling and railcar transportation of both blend and condensate volumes.

 

Natural Gas Marketing

 

We also manage the marketing of our natural gas, which is primarily sold to industrials, 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.

 

 

RESERVES DATA AND OTHER OIL AND GAS INFORMATION

 

As a Canadian issuer, we are subject to the reporting requirements of Canadian securities regulatory authorities, including the reporting of our reserves in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”).

 

Our reserves are primarily located in Alberta and Saskatchewan, Canada. We retain two independent qualified reserves evaluators (“IQREs”), McDaniel and Associates Consultants Ltd. (“McDaniel”) and GLJ Petroleum Consultants Ltd. (“GLJ”), to evaluate and prepare reports on 100 percent of our bitumen, heavy oil, light and medium oil, NGLs, natural gas, and coalbed methane (“CBM”) reserves annually. McDaniel evaluated approximately 95 percent of our total proved reserves, located throughout Alberta and Saskatchewan, and GLJ evaluated approximately five percent of our total proved reserves, located at Boyer and Weyburn. We also engaged McDaniel to evaluate 100 percent of our contingent and prospective bitumen resources.

 

The Reserves Committee of our Board of Directors (“Board”), composed of independent Board members, reviews the qualifications and appointment of the IQREs, the procedures relating to the disclosure of information with respect to oil and gas activities and the procedures for providing information to the IQREs. The Reserves Committee meets with management and each IQRE to determine whether any restrictions affect the ability of the IQRE to report on the reserves data without reservation, to review the reserves data and the report of the IQRE thereon, and to provide a recommendation approval of the reserves and resources disclosure to the Board.

 

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 and water 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.

 

Classifications of reserves as proved or probable are only attempts to define the degree of certainty associated with the estimates. There are numerous uncertainties inherent in estimating quantities of bitumen, oil and natural gas reserves. It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. Readers should review the definitions and information contained in “Additional Notes to Reserves Data Tables”, “Definitions” and “Pricing Assumptions” in conjunction with the disclosure. The reserves estimates provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates disclosed. See “Risk Factors – Uncertainty of Reserves, Resources and Future Net Revenue Estimates” in this AIF for additional information.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2011

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Table of Contents

 

The reserves data and other oil and gas information contained in this AIF is dated February 13, 2012, with an effective date of December 31, 2011. McDaniel’s preparation date of the information is February 13, 2012, and GLJ’s preparation date is January 9, 2012.

 

Disclosure of Reserves Data

 

The reserves data presented summarizes our bitumen, heavy oil, light and medium oil plus NGLs, and natural gas plus CBM reserves and the net present values of future net revenue for these reserves. The reserves data uses forecast prices and costs prior to provision for interest, general and administrative expenses, costs associated with environmental regulations, the impact of any hedging activities or the liability associated with certain abandonment and all well, pipeline, facilities and reclamation costs. Future net revenues have been presented on a before and after tax basis.

 

We hold significant fee title rights which generate production for our account from third parties leasing those lands (“Royalty Interest Production”). At December 31, 2011, approximately 2.4 million acres throughout southeastern Alberta and southern Saskatchewan and Manitoba were leased out to third parties. In accordance with NI 51-101, only the After Royalties volumes presented herein include reserves associated with this Royalty Interest Production (“Royalty Interest Reserves”).

 

 

Summary of Company Interest Oil and Gas Reserves at December 31, 2011

(Forecast Prices and Costs)

 

Before Royalties(1)

 

 

 

 

 

 

 

 

 

Reserves Category

 

Bitumen
(MMbbls)

 

Heavy Oil
(MMbbls)

 

Light & Medium
Oil & NGLs
(MMbbls)

 

Natural Gas
& CBM
(Bcf)

Proved Reserves

 

 

 

 

 

 

 

 

Developed Producing

 

162

 

105

 

82

 

1,145

Developed Non-Producing

 

6

 

15

 

8

 

34

Undeveloped

 

1,287

 

55

 

25

 

24

Total Proved Reserves

 

1,455

 

175

 

115

 

1,203

Probable Reserves

 

490

 

109

 

51

 

391

Total Proved plus
Probable Reserves

 

1,945

 

284

 

166

 

1,594

 

After Royalties(2)

 

 

 

 

 

 

 

 

 

Reserves Category

 

Bitumen
(MMbbls)

 

Heavy Oil
(MMbbls)

 

Light & Medium
Oil & NGLs
(MMbbls)

 

Natural Gas
& CBM
(Bcf)

Proved Reserves

 

 

 

 

 

 

 

 

Developed Producing

 

121

 

86

 

70

 

1,152

Developed Non-Producing

 

5

 

12

 

5

 

34

Undeveloped

 

953

 

44

 

20

 

23

Total Proved Reserves

 

1,079

 

142

 

95

 

1,209

Probable Reserves

 

357

 

81

 

42

 

375

Total Proved plus
Probable Reserves

 

1,436

 

223

 

137

 

1,584

 

Royalty Interest

 

 

 

 

 

 

 

 

 

Reserves Category

 

Bitumen
(MMbbls)

 

Heavy Oil
(MMbbls)

 

Light & Medium
Oil & NGLs
(MMbbls)

 

Natural Gas
& CBM
(Bcf)

Proved Reserves

 

 

 

 

 

 

 

 

Developed Producing

 

-

 

2

 

4

 

45

Developed Non-Producing

 

-

 

-

 

-

 

-

Undeveloped

 

-

 

-

 

-

 

-

Total Proved Reserves

 

-

 

2

 

4

 

45

Probable Reserves

 

-

 

-

 

2

 

15

Total Proved plus
Probable Reserves

 

-

 

2

 

6

 

60

Notes:

(1)             Does not include Royalty Interest Reserves.

(2)             Includes Royalty Interest Reserves.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2011

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Table of Contents

 

Summary of Net Present Value of Future Net Revenue at December 31, 2011

(Forecast Prices and Costs)

 

Before Income Taxes

 

 

 

 

 

 

 

 

 

Discounted at %/year ($ millions)

 

Unit Value

Discounted at

10%(1)

Reserves Category

0%

5%

10%

15%

20%

 

$/BOE

Proved Reserves

 

 

 

 

 

 

 

   Developed Producing

16,704

13,539

11,404

9,883

8,747

 

24.28

   Developed Non-Producing

1,119

760

568

452

374

 

20.98

   Undeveloped

45,721

19,864

10,121

5,677

3,352

 

9.91

Total Proved Reserves

63,544

34,163

22,093

16,012

12,473

 

14.56

Probable Reserves

25,192

12,571

6,881

4,169

2,746

 

12.68

Total Proved plus

Probable Reserves

88,736

46,734

28,974

20,181

15,219

 

14.06

Note:

(1)             Unit values have been calculated using Company Interest After Royalties reserves.

 

After Income Taxes(1)

 

 

 

 

 

 

 

Discounted at %/year ($ millions)

Reserves Category

0%

5%

10%

15%

20%

Proved Reserves

 

 

 

 

 

   Developed Producing

13,094

10,668

9,017

7,837

6,954

   Developed Non-Producing

834

567

425

340

282

   Undeveloped

34,237

14,747

7,434

4,110

2,379

Total Proved Reserves

48,165

25,982

16,876

12,287

9,615

Probable Reserves

18,705

9,294

5,057

3,042

1,989

Total Proved plus

Probable Reserves

66,870

35,276

21,933

15,329

11,604

Note:

(1)             Values are calculated by considering existing tax pools and tax circumstances for Cenovus and its subsidiaries in the consolidated evaluation of Cenovus’s oil and gas properties, and take into account current federal tax regulations. Values do not represent an estimate of the value at the business entity level, which may be significantly different. For information at the business entity level, please see our Consolidated Financial Statements and Management’s Discussion and Analysis for the year ended December 31, 2011.

 

Total Future Net Revenue (undiscounted) at December 31, 2011

(Forecast Prices and Costs) ($ millions)

 

Reserves

Category

Revenue

Royalties

Operating

Costs

Development

Costs

Abandonment

Costs (1)

Future

Net

Revenue

Before

Income

Taxes

Future

Income

Taxes

Future

Net

Revenue

After

Income

Taxes

Proved

Reserves

151,861

35,574

40,130

11,563

1,050

63,544

15,379

48,165

Proved plus

Probable Reserves

209,399

49,813

53,882

15,769

1,199

88,736

21,866

66,870

Note:

(1)             The abandonment costs only include downhole abandonment costs for the wells considered in the IQREs’ evaluation of reserves. Abandonment of other wells, surface reclamation, asset recovery and facility site reclamation costs are not included.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2011

 

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Future Net Revenue by Production Group at December 31, 2011

(Forecast Prices and Costs)

 

Reserves Category

Production Group

Future Net

Revenue Before

Income Taxes

(discounted at

10%/year)

($ millions)

Unit Value

(Company Interest

After Royalties
Reserves)

($/BOE)

Proved Reserves

Bitumen

13,897

12.88

 

Heavy Oil

3,008

21.19

 

Light and Medium Crude Oil and NGLs

2,986

31.30

 

Natural Gas

2,202

10.94

 

Total

22,093

14.56

 

 

 

 

Proved plus

Bitumen

17,490

12.18

Probable Reserves

Heavy Oil

4,533

20.31

 

Light and Medium Crude Oil and NGLs

4,053

29.51

 

Natural Gas

2,898

10.98

 

Total

28,974

14.06

 

Additional Notes to Reserves Data Tables

 

·                  The estimates of future net revenue presented do not represent fair market value.

 

·                  Future net revenue from reserves excludes cash flows related to our risk management activities.

 

·                  For disclosure purposes, we have included NGLs with light and medium oil, and CBM gas with natural gas, as the reserves of each are not material relative to the other reported product types.

 

·                  Numbers presented are rounded to the nearest whole number and tables may not add due to rounding.

 

Definitions

 

1.              After Royalties means volumes after deduction of royalties and includes Royalty Interests.

 

2.              Before Royalties means volumes before deduction of royalties and excludes Royalty Interests.

 

3.              Company Interest means, in relation to production, reserves, resources and property, the interest (operating or non-operating) held by us.

 

4.              Gross means:

 

(a)         in relation to wells, the total number of wells in which we have an interest; and

(b)         in relation to properties, the total area of properties in which we have an interest.

 

5.              Net means:

 

(a)         in relation to wells, the number of wells obtained by aggregating our working interest in each of our gross wells; and

(b)         in relation to our interest in a property, the total area in which we have an interest multiplied by the working interest owned by us.

 

6.              Reserves are estimated remaining quantities anticipated to be recoverable from known accumulations, from a given date forward, based on analysis of drilling, geological, geophysical and engineering data, the use of established technology and specified economic conditions.

 

Reserves are classified according to the degree of certainty associated with the estimates:

 

·                  Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

 

·                  Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2011

 

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Each of the reserves categories may be divided into developed and undeveloped categories:

 

·                  Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g., when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided as follows:

 

o                 Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

 

o                 Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.

 

·                  Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g. similar to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned.

 

7.              Royalty Interest Reserves means those reserves related to our royalty entitlement on lands to which we hold fee title and which have been leased to third parties, plus any reserves related to other royalty interests, such as overriding royalties, to which we are entitled.

 

8.              Royalty Interest Production means the production related to our royalty entitlement on lands to which we hold fee title and which have been leased to third parties, plus any production related to other royalty interests, such as overriding royalties, to which we are entitled.

 

Pricing Assumptions

 

The forecast price and cost assumptions assume the continuance of current laws and take into account inflation with respect to future operating and capital costs. The forecast prices are provided in the table below and reflect McDaniel’s January 1, 2012 price forecast as referred to in the McDaniel & Associates Consultants Ltd. Summary of Price Forecasts dated January 1, 2012. For historical prices realized during 2011, see “Production History” in this AIF.

 

 

Oil

 

Natural

Gas

 

 

 

Year

WTI

Cushing

Oklahoma

($US/bbl)

Edmonton

Par

Price

40 API

($C/bbl)

Cromer

Medium

29.3 API

($C/bbl)

Hardisty

Heavy

12 API

($C/bbl)

Western

Canadian

Select

($C/bbl)

 

AECO

Gas

Price

($C/MMBtu)

 

Inflation

Rate

(%/year)

Exchange

Rate

($US/$C)

2012

97.50

99.00

91.00

74.00

80.50

 

3.50

 

2.0

0.975

2013

97.50

99.00

91.00

74.00

80.50

 

4.20

 

2.0

0.975

2014

100.00

101.50

93.30

75.90

82.50

 

4.70

 

2.0

0.975

2015

100.80

102.30

94.10

76.50

83.20

 

5.10

 

2.0

0.975

2016

101.70

103.20

94.90

77.10

83.90

 

5.55

 

2.0

0.975

2017

102.70

104.20

95.80

77.90

84.70

 

5.90

 

2.0

0.975

2018

103.60

105.10

96.60

78.60

85.50

 

6.25

 

2.0

0.975

2019

104.50

106.00

97.50

79.20

86.20

 

6.45

 

2.0

0.975

2020

105.40

106.90

98.30

79.90

86.90

 

6.70

 

2.0

0.975

2021

107.60

109.20

100.30

81.60

88.70

 

6.85

 

2.0

0.975

There-

after

+2%/yr

+2%/yr

+2%/yr

+2%/yr

+2%/yr

 

+2%/yr

 

2.0

0.975

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2011

 

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Table of Contents

 

Future Development Costs

 

The following table outlines undiscounted development costs deducted in the estimation of future net revenue calculated utilizing forecast prices and costs for the years indicated:

 

Reserves Category

($ millions)

2012

2013

2014

2015

2016

Remainder

Total

Proved Reserves

1,413

928

527

595

334

7,766

11,563

Proved plus Probable Reserves

1,582

1,247

859

854

518

10,709

15,769

 

We believe that internally generated cash flows, existing credit facilities and access to capital markets will be sufficient to fund our future development costs. However, there can be no guarantee that the necessary funds will be available or that we will allocate funding to develop all of our reserves. Failure to develop those reserves would have a negative impact on our future net revenue.

 

The interest or other costs of external funding are not included in the reserves and future net revenue estimates and would reduce future net revenue depending upon the funding sources utilized. We do not believe that interest or other funding costs would make development of any property uneconomic.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2011

 

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Table of Contents

 

Reserves Reconciliation

 

The following tables provide a reconciliation of our Company Interest Before Royalties reserves for bitumen, heavy oil, light and medium oil and NGLs, and natural gas for the year ended December 31, 2011, presented using forecast prices and costs. All reserves are located in Canada.

 

Company Interest Before Royalties

Reserves Reconciliation by Principal Product Type and Reserves Category

(Forecast Prices and Costs)

 

Proved

 

 

 

 

 

Bitumen

(MMbbls)

Heavy Oil

(MMbbls)

Light &

Medium

Oil & NGLs

(MMbbls)

Natural

Gas & CBM

(Bcf)

December 31, 2010

1,154

169

111

1,390

Extensions and Improved Recovery

256

16

13

50

Discoveries

-

-

-

-

Technical Revisions

69

2

1

29

Economic Factors

-

1

-

(28)

Acquisitions

-

-

-

-

Dispositions

-

-

-

-

Production(1)

(24)

(13)

(10)

(238)

December 31, 2011

1,455

175

115

1,203

 

 

 

 

 

Probable

 

 

 

 

 

Bitumen

(MMbbls)

Heavy Oil

(MMbbls)

Light &

Medium

Oil & NGLs

(MMbbls)

Natural

Gas & CBM

(Bcf)

December 31, 2010

523

97

49

410

Extensions and Improved Recovery

32

14

3

11

Discoveries

-

-

-

-

Technical Revisions

(65)

(2)

(1)

(27)

Economic Factors

-

-

-

(3)

Acquisitions

-

-

-

-

Dispositions

-

-

-

-

Production(1)

-

-

-

-

December 31, 2011

490

109

51

391

 

 

 

 

 

Proved plus Probable

 

 

 

 

 

Bitumen

(MMbbls)

Heavy Oil

(MMbbls)

Light &

Medium

Oil & NGLs

(MMbbls)

Natural

Gas & CBM

(Bcf)

December 31, 2010

1,677

266

160

1,800

Extensions and Improved Recovery

288

30

16

61

Discoveries

-

-

-

-

Technical Revisions

4

-

-

2

Economic Factors

-

1

-

(31)

Acquisitions

-

-

-

-

Dispositions

-

-

-

-

Production(1)

(24)

(13)

(10)

(238)

December 31, 2011

1,945

284

166

1,594

 

Note:

(1)             Production used for the reserves reconciliation differs from publicly reported production. In accordance with NI 51-101, Company Interest Before Royalties production used for the reserves reconciliation above includes our share of gas volumes provided to the FCCL partnership for steam generation, but does not include Royalty Interest Production.

 

Proved and proved plus probable bitumen reserves increased by approximately 26 and 16 percent respectively. Increases at Christina Lake were primarily a result of receiving regulatory approval to expand the development area and from positive delineation results. Increases at Foster Creek were primarily due to positive revisions from delineation drilling, increased recovery resulting from wells using our Wedge WellTM technology and improved steam chamber recovery.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2011

 

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Proved heavy oil reserves increased by approximately four percent primarily as a result of expanding polymer flood areas and their successful performance in the Greater Pelican Region. Probable heavy oil reserves increased by approximately 12 percent also based on expansion and performance. Proved plus probable reserves increased by approximately seven percent.

 

Proved light and medium oil and NGLs reserves increased by approximately four percent, primarily as a result of expanding waterflood and CO2 flood areas and their successful performance at Weyburn. Probable light and medium oil and NGLs reserves increased by approximately four percent as a result of continued strong performance. Overall, proved plus probable reserves increased by approximately four percent.

 

Proved natural gas reserves declined by approximately 13 percent as extensions and technical revisions did not offset production. Probable natural gas reserves and proved plus probable reserves declined by approximately five percent and 11 percent respectively.

 

Undeveloped Reserves

 

Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production.

 

Proved and probable undeveloped reserves have been estimated by the IQREs in accordance with procedures and standards contained in the Canadian Oil and Gas Evaluation (“COGE”) Handbook. In general, undeveloped reserves are scheduled to be developed within the next one to 43 years.

 

 

 

 

 

 

 

 

 

 

Company Interest Proved Undeveloped – Before Royalties

 

 

 

 

 

 

Bitumen

(MMbbls)

Heavy Oil

(MMbbls)

Light and Medium

Oil and NGLs

(MMbbls)

Natural Gas & CBM

(Bcf)

 

First

Attributed

Total at

Year-End

First

Attributed

Total at

Year-End

First

Attributed

Total at

Year-End

First

Attributed

Total at

Year-End

Prior

623

560

47

45

38

29

272

150

2009

190

734

8

46

7

28

10

35

2010

295

1,008

5

45

5

27

18

36

2011

325

1,287

13

55

3

25

-

24

 

 

 

 

 

 

 

 

 

Company Interest Probable Undeveloped – Before Royalties

 

 

 

 

 

 

Bitumen

(MMbbls)

Heavy Oil

(MMbbls)

Light and Medium

Oil and NGLs

(MMbbls)

Natural Gas & CBM

(Bcf)

 

First

Attributed

Total at

Year-End

First

Attributed

Total at

Year-End

First

Attributed

Total at

Year-End

First

Attributed

Total at

Year-End

Prior

628

625

-(1)

-(1)

-(1)

-(1)

-(1)

-(1)

2009

5

467

43 

43 

26 

26 

38 

38 

2010

171

506

37 

21 

16 

30 

2011

113

467

14 

47 

22 

35 

 

Note:

(1)             Historical information is not available.

 

Development of Proved Undeveloped Reserves

 

Bitumen

 

At the end of 2011, we had proved undeveloped bitumen reserves of 1,287 million barrels Before Royalties, or approximately 88 percent of our total proved bitumen reserves. Of our 490 million barrels of probable bitumen reserves, 467 million barrels, or approximately 95 percent are undeveloped. For this evaluation, it is assumed that these reserves will be recovered using SAGD technology.

 

Typical SAGD project development involves the initial installation of a steam generation facility, at a cost much greater than drilling a production/injection well pair, and then progressively drilling sufficient SAGD wells to fully utilize the available steam.

 

Bitumen reserves can be classified as proved when there is sufficient stratigraphic drilling to have demonstrated to a high degree of certainty the presence of the bitumen in commercially recoverable volumes. Our IQRE standard for sufficient drilling is a minimum eight wells per section with 3D seismic, or 16 wells per section with no seismic. Additionally, all requisite legal and regulatory approvals must have been obtained, operator and partner funding approvals must be in place, and a reasonable development timetable must be established. 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.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2011

 

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Development of probable reserves requires sufficient drilling of stratigraphic wells to establish reservoir suitability for SAGD. Reserves will be classified as probable if the number of wells drilled falls between the stratigraphic well requirements for proved reserves and for probable reserves, or if the reserves are not located within an approved development plan area. The IQRE standard for probable reserves is a minimum of four stratigraphic wells per section. If reserves lie outside the approved development area, approval to include those reserves in the development plan area must be obtained before development drilling of SAGD well pairs can commence.

 

Development of the proved undeveloped reserves will take place in an orderly manner as additional well pairs are drilled to utilize the available steam when existing well pairs reach the end of their steam injection phase. The forecast production of Cenovus’s proved bitumen reserves extends approximately 43 years, based on existing facilities. Production of the current proved developed portion is estimated to take about 10 years.

 

Oil

 

We have a significant medium oil CO2 enhanced oil recovery (“EOR”) project at Weyburn and a significant heavy oil 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 anticipated improved recovery associated with development of the EOR schemes. Extending both EOR schemes within the projects requires intensive capital investment in infrastructure development and will occur over many years.

 

At Weyburn, investment in undeveloped reserves is projected to continue for well over 40 years, with drilling of supplementary wells taking place over the next seven years, and CO2 flood advancement continuing many years beyond that. At Pelican Lake, investment in undeveloped reserves is projected to continue for eight years, with a combination of infill drilling and polymer flood advancement.

 

Significant Factors or Uncertainties Affecting Reserves Data

 

The evaluation of reserves is a continuous process, one that can be significantly impacted by a variety of internal and external influences. Revisions are often required resulting from changes in pricing, economic conditions, regulatory changes, and historical performance. While these factors can be considered and potentially anticipated, certain judgments and assumptions are always required. As new information becomes available these areas are reviewed and revised accordingly. For a discussion of the risk factors and uncertainties affecting reserves data, see “Risk Factors – Operational Risks - Uncertainty of Reserves and Future Net Revenue Estimates.

 

Contingent and Prospective Resources

 

We retain McDaniel to evaluate and prepare reports on all of our contingent and prospective bitumen resources. The evaluations by McDaniel are conducted from the fundamental petrophysical, geological, engineering, financial and accounting data. Processes and procedures are in place to ensure that McDaniel is in receipt of all relevant information. Contingent and prospective resources are estimated using volumetric calculations of the in-place quantities, combined with performance from analog reservoirs. The existing SAGD projects that are producing from the McMurray-Wabiskaw formations at Foster Creek and Christina Lake are used as performance analogs at Foster Creek and Christina Lake. Other regional analogs are used for contingent and prospective resources estimation in the Cretaceous Grand Rapids formation at Grand Rapids property in the Greater Pelican Region, in the McMurray formation at the Telephone Lake property in the Borealis Region and in the Clearwater formation in the Foster Creek Region. McDaniel also tests contingent resources for economic viability using the same forecast prices and costs used for our reserves (refer to “Pricing Assumptions” in this AIF).

 

This evaluation assumes that the majority of our bitumen resources will be recovered and produced using SAGD or cyclic steam stimulation (“CSS”) established technologies. SAGD involves injecting steam into horizontal wells drilled into the bitumen formation and recovering heated bitumen and water from producing wells located below the injection wells. CSS involves injecting steam into a well and then producing water and heated bitumen from the same wellbore. Such alternating injection and production cycles are repeated a number of times for a given wellbore. Both of these techniques have a surface footprint comparable to conventional oil production. We have no bitumen resources that require mining techniques for recovery.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2011

 

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All of our current contingent and prospective resources are associated with clastic or sandstone formations. We have also identified significant amounts of bitumen in the Grosmont carbonate formation for which we have extensive mineral rights. Pilot testing of the SAGD recovery process in carbonates is currently underway in the Grosmont carbonate formation several miles away from Cenovus’s lands but commercial viability has yet to be established. Cenovus has commenced work on its own pilot for bitumen production from the Grosmont carbonate formation.

 

In addition to the reserve definitions provided in the preceding sections, the following terminology, consistent with the COGE Handbook and guidance from Canadian securities regulatory authorities, was used to prepare the disclosure that follows.

 

Contingent Resources are those quantities of bitumen estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include such factors as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent resources are further classified in accordance with the level of certainty associated with the estimates and may be subclassified based on project maturity and/or characterized by their economic status. The McDaniel estimates of contingent resources have not been adjusted for risk based on the chance of development.

 

Economic Contingent Resources are those contingent resources that are currently economically recoverable based on specific forecasts of commodity prices and costs. All of Cenovus’s bitumen contingent resources were evaluated using the same economic assumptions that were used for the 2011 reserves evaluation.

 

Contingencies which must be overcome to enable the reclassification of contingent resources as reserves can be categorized as economic, non-technical and technical. The COGE Handbook identifies non-technical contingencies as legal, environmental, political and regulatory matters or a lack of markets. The contingent resources disclosed by us are not contingent due to economic factors. Our bitumen contingent resources are located in four general regions: Christina Lake, Foster Creek, Borealis, and the Greater Pelican Region.

 

At Christina Lake and Foster Creek we have economic contingent resources located outside the currently approved development project areas. Regulatory approval of development project area expansion is necessary to enable the reclassification of these economic contingent resources as reserves. The rate at which we submit applications for development area expansion is dependent on the rate of development drilling, which ties to an orderly development plan that maximizes utilization of steam generation facilities and ultimately optimizes production, capital utilization and value.

 

In the Borealis Region we have submitted an application for a development project of the Telephone Lake property, which, if approved, would enable the reclassification of certain economic contingent resources in the area to reserves. Other areas in the Borealis Region require additional delineation drilling and seismic in order to submit regulatory applications for development projects.  Stratigraphic drilling and seismic is continuing in these areas to bring them to project readiness. Currently, sufficient pipeline take-away capacity is also considered a contingency.

 

In the Greater Pelican Region we submitted an application in the fourth quarter of 2011 for development project approval at the Grand Rapids property. Provided all regulatory requirements are met, we anticipate receiving regulatory approval in 2013.  Pilot project work is underway to examine optimal development strategies.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2011

 

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Prospective Resources are those quantities of bitumen petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. Prospective resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be subclassified based on project maturity. The estimate of prospective resources has not been adjusted for risk based on the chance of discovery or the chance of development.

 

Best Estimate is considered to be the best estimate of the quantity of resources that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. Those resources that fall within the best estimate have a 50 percent confidence level that the actual quantities recovered will equal or exceed the estimate.

 

Low Estimate is considered to be a conservative estimate of the quantity of resources that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. Those resources at the low end of the estimate range have the highest degree of certainty - a 90 percent confidence level – that the actual quantities recovered will equal or exceed the estimate.

 

High Estimate is considered to be an optimistic estimate of the quantity of resources that will actually be recovered. It is unlikely that the actual remaining quantities of resources recovered will meet or exceed the high estimate. Those resources at the high end of the estimate range have a lower degree of certainty - a 10 percent confidence level - that the actual quantities recovered will equal or exceed the estimate.

 

The economic contingent resources were estimated on a project level. The high and low estimates are arithmetic sums of multiple estimates which statistical principles indicate may be misleading as to volumes that may actually be recovered. The aggregated low estimate results shown may have a higher level of confidence than the individual projects, and the aggregated high estimate results shown may have a lower level of confidence than the individual projects.

 

Economic Contingent and Prospective Resources

 

 

Company Interest Before Royalties, Billions of barrels

December 31,

2011

December 31,

2010

Economic Contingent Resources(1)

 

 

Low Estimate

6.0

4.4

Best Estimate

8.2

6.1

High Estimate

10.8

8.0

Prospective Resources(2)

 

 

Low Estimate

5.7

7.3

Best Estimate

10.0

12.3

High Estimate

17.9

21.7

Notes:

(1)             There is no certainty that it will be commercially viable to produce any portion of the contingent resources.

(2)             There is no certainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources. Prospective resources are not screened for economic viability.

 

Best estimate economic contingent resources increased 2.1 billion barrels or 34 percent compared to 2010. This increase is primarily due to successful stratigraphic well drilling resulting in the conversion of prospective resources to contingent resources, and to positive technical revisions to volumetric and recovery factor estimates.

 

Best estimate prospective resources declined 2.3 billion barrels or approximately 19 percent compared to 2010, primarily as a result of the reclassification of prospective resources to contingent resources resulting from stratigraphic well drilling.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2011

 

23

 

 



Table of Contents

 

A more detailed annual reconciliation is shown in the following table:

 

Bitumen Proved plus Probable Reserves, Contingent Resources and Prospective Resources

Reconciliation and Category Movements

 

Company Interest Before Royalties, Billions of barrels

 

Proved plus
Probable
Reserves

 

Best Estimate
Contingent
Resources
(1)

 

Best Estimate
Prospective
Resources
(2)

 

December 31, 2010

 

1.677

 

6.1

 

12.3

 

Transfers between Categories

 

 

 

 

 

 

 

Additions from other resource categories

 

0.142

 

2.0

 

(2.0

)

Reductions to other resource categories

 

-

 

(0.1

)

-

 

Additions and Revisions Net of Transfers

 

0.150

 

0.2

 

(0.3

)

Net Acquisitions and Dispositions

 

-

 

-

 

-

 

Production

 

(0.024

)

-

 

-

 

December 31, 2011

 

1.945

 

8.2

 

10.0

 

 

Notes:

(1)

There is no certainty that it will be commercially viable to produce any portion of the contingent resources.

(2)

There is no certainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources. Prospective resources are not screened for economic viability.

 

We are systematically progressing the classification of our bitumen prospective resources to contingent resources and then to reserves, and ultimately to production. For example, approval for expansion of the Christina Lake development area resulted in the movement of some contingent resources to proved and probable reserves. Similarly, the stratigraphic well drilling program in the Borealis and the Greater Pelican Regions moved some prospective resources to contingent resources. The overall reduction of prospective resources is the expected outcome of a successful stratigraphic well drilling program, which converts undiscovered resources to discovered resources.

 

Bitumen reserves and resources increased in part because of improvements in SAGD performance at our Foster Creek and Christina Lake properties resulting from improved operating performance and the use of wells drilled using our Wedge WellTM technology. Analysis of core data in the steamed portions of the reservoir has revealed that the efficiency of the SAGD process in extracting bitumen from the reservoir is greater than previously anticipated. We expect to continue to improve overall recovery from our bitumen assets as technology develops.

 

Other Oil and Gas Information

 

Oil and Gas Properties and Wells

 

The following tables summarize our interests in producing and non-producing wells, at December 31, 2011:

 

Producing Wells(1)(2)

 

 

 

Oil

Gas

Total

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Alberta

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil Sands

 

687

 

566

 

438

 

416

 

1,125

 

982

 

Conventional

 

1,718

 

1,663

 

25,724

 

25,506

 

27,442

 

27,169

 

Total Alberta

 

2,405

 

2,229

 

26,162

 

25,922

 

28,567

 

28,151

 

Saskatchewan

 

808

 

541

 

-

 

-

 

808

 

541

 

Total

 

3,213

 

2,770

 

26,162

 

25,922

 

29,375

 

28,692

 

Notes:

(1)                   Cenovus also has varying royalty interests in 7,076 natural gas wells and 3,495 crude oil wells which are producing.

(2)                   Includes wells containing multiple completions as follows: 22,836 gross natural gas wells (22,633 net wells) and 1,227 gross crude oil wells (1,119 net wells).

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2011

24

 

 



Table of Contents

 

Non-Producing Wells(1)

 

 

 

Oil

Gas

Total

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Alberta

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil Sands

 

81

 

67

 

615

 

564

 

696

 

631

 

Conventional

 

734

 

709

 

879

 

857

 

1,613

 

1,566

 

Total Alberta

 

815

 

776

 

1,494

 

1,421

 

2,309

 

2,197

 

Saskatchewan

 

137

 

100

 

38

 

38

 

175

 

138

 

Total

 

952

 

876

 

1,532

 

1,459

 

2,484

 

2,335

 

Note:

(1)

Non-producing wells include wells which are capable of producing, but which are currently not producing. Non-producing wells do not include other types of wells such as stratigraphic test wells, service wells, or wells that have been abandoned.

 

Exploration and Development Activity

 

The following tables summarize our gross participation and net interest in wells drilled for the periods indicated:

 

Exploration Wells Drilled

 

 

 

Oil

Gas

Dry &
Abandoned

Total Working
Interest

Royalty

Total

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Gross

 

Net

 

2011:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil Sands

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

Conventional

 

24

 

22

 

-

 

-

 

2

 

2

 

26

 

24

 

40

 

66

 

24

 

Total Canada

 

24

 

22

 

-

 

-

 

2

 

2

 

26

 

24

 

40

 

66

 

24

 

2010:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil Sands

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

Conventional

 

26

 

26

 

-

 

-

 

1

 

1

 

27

 

27

 

21

 

48

 

27

 

Total Canada

 

26

 

26

 

-

 

-

 

1

 

1

 

27

 

27

 

21

 

48

 

27

 

2009:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil Sands

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

Conventional

 

4

 

4

 

-

 

-

 

-

 

-

 

4

 

4

 

8

 

12

 

4

 

Total Canada

 

4

 

4

 

-

 

-

 

-

 

-

 

4

 

4

 

8

 

12

 

4

 

 

Development Wells Drilled

 

 

 

Oil

Gas

Dry &
Abandoned

Total
Working
Interest

Royalty

Total

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Gross

 

Net

 

2011:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil Sands

 

71

 

51

 

3

 

3

 

-

 

-

 

74

 

54

 

87

 

161

 

54

 

Conventional

 

312

 

303

 

66

 

65

 

4

 

4

 

382

 

372

 

156

 

538

 

372

 

Total Canada

 

383

 

354

 

69

 

68

 

4

 

4

 

456

 

426

 

243

 

699

 

426

 

2010:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil Sands

 

82

 

47

 

-

 

-

 

-

 

-

 

82

 

47

 

8

 

90

 

47

 

Conventional

 

160

 

154

 

499

 

495

 

-

 

-

 

659

 

649

 

204

 

863

 

649

 

Total Canada

 

242

 

201

 

499

 

495

 

-

 

-

 

741

 

696

 

212

 

953

 

696

 

2009:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil Sands

 

50

 

29

 

8

 

8

 

8

 

8

 

66

 

45

 

10

 

76

 

45

 

Conventional

 

102

 

101

 

555

 

502

 

2

 

2

 

659

 

605

 

261

 

920

 

605