40-F 1 a13-4560_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, 2012      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))

 

2600, 500 Centre Street S.E.
Calgary, Alberta, Canada T2G 1A6
(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:

 

755,842,760

 

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, as amended: Form S-8 (File No. 333-163397), Form F-3 (File No. 333-166419), and Form F-10 (File No. 333-181728).

 

 

 

 

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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, 2012.

 

(b)                              Management’s Discussion and Analysis of Cenovus Energy Inc. for the fiscal year ended December 31, 2012.

 

(c)                               Consolidated Financial Statements of Cenovus Energy Inc. as at December 31, 2012.

 

(d)                              Supplementary Information – Oil and Gas Activities (unaudited) as at December 31, 2012.

 

 

 

 

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GRAPHIC

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CENOVUS ENERGY INC.

 

 

ANNUAL INFORMATION FORM

 

FOR THE YEAR ENDED DECEMBER 31, 2012

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2012

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TABLE OF CONTENTS

 

FORWARD-LOOKING INFORMATION

1

CORPORATE STRUCTURE

2

GENERAL DEVELOPMENT OF OUR BUSINESS

3

NARRATIVE DESCRIPTION OF OUR BUSINESS

6

Oil Sands

7

Conventional

10

Refining and Marketing

13

RESERVES DATA AND OTHER OIL AND GAS INFORMATION

15

Disclosure of Reserves Data

15

Definitions

18

Reserves Reconciliation

20

Contingent and Prospective Resources

23

Other Oil and Gas Information

26

OTHER INFORMATION

37

Competitive Conditions

37

Environmental Considerations

37

Corporate Responsibility Practice

37

Employees

38

Foreign Operations

38

DIRECTORS AND EXECUTIVE OFFICERS

39

AUDIT COMMITTEE

44

DESCRIPTION OF CAPITAL STRUCTURE

46

DIVIDENDS

48

MARKET FOR SECURITIES

48

RISK FACTORS

48

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

58

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

58

MATERIAL CONTRACTS

58

TRANSFER AGENTS AND REGISTRARS

59

ADDITIONAL INFORMATION

59

ABBREVIATIONS AND CONVERSIONS

60

 

 

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

 

 

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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 the success of our hedging strategies; the 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 EBITDA as well as debt to capitalization; our ability to access various sources of debt and equity capital; accuracy of our reserves, resources and future production estimates; our ability to replace and expand oil and gas reserves; our ability to maintain our relationship with our partners 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 producing, transporting or refining of crude oil into petroleum and chemical products; 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 countries 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, 2012

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CORPORATE STRUCTURE

 

Cenovus Energy Inc. was formed under the Canada Business Corporations Act (“CBCA”) by amalgamation of 7050372 Canada Inc. (“7050372”) 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, 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 2600, 500 Centre Street S.E., Calgary, Alberta, Canada T2G 1A6.

 

Intercorporate Relationships

 

The following table summarizes our principal subsidiaries and partnerships at December 31, 2012:

 

Subsidiaries & Partnerships

 

Percentage

Owned(1)

 

Jurisdiction of
Incorporation,
Continuance, Formation
or Organization

Cenovus FCCL Ltd.

 

100

 

Alberta

Cenovus US Holdings Inc.

 

100

 

Delaware

FCCL Partnership (“FCCL”)(2)

 

50

 

Alberta

WRB Refining LP (“WRB”) (3)

 

50

 

Delaware

 

Notes:

(1)             Includes direct and indirect ownership.

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

(3)             Cenovus interest held indirectly through Cenovus US Holdings Inc.

 

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, 2012.

 

 

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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, includes the development and production of Cenovus’s bitumen assets at Foster Creek, Christina Lake and Narrows Lake as well as heavy oil assets at Pelican Lake. This segment also includes the Athabasca natural gas assets and projects in the early stages of development such as Grand Rapids and Telephone Lake. 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.

 

 

·

Conventional, which includes the development and production of conventional crude oil, NGLs and natural gas in Alberta and Saskatchewan, including the carbon dioxide enhanced oil recovery project at Weyburn and emerging tight oil opportunities.

 

 

·

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 Phillips 66, an unrelated U.S. public company. 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:

 

2012

 

·

In the second quarter, the expected gross production capacity for Christina Lake phase H was increased from 40,000 bbls/d to 50,000 bbls/d due to the addition of a fifth steam generator that will incorporate blowdown boiler technology. This is expected to increase steam capacity and enhance efficiency by increasing the water recycle rate, leading to fuel savings and a reduction in water use. We commercialized blowdown boiler technology in 2011 after testing it at Foster Creek.

 

 

·

In the second quarter, we received regulatory approval for the Narrows Lake project, which includes the use of both traditional steam-assisted gravity drainage (“SAGD”) and SAGD with the Solvent Aided Process (“SAP”) enhancement. In the fourth quarter, phase A, which has planned gross production capacity of 45,000 bbls/d, received partner approval. The Narrows Lake project is currently expected to have gross production capacity of 130,000 bbls/d in three phases.

 

 

·

In the second quarter, ConocoPhillips, our partner in FCCL and WRB, proceeded with the spin-off of its downstream business from its exploration and production business, which was announced in the third quarter of 2011. The exploration and production entity retained the ConocoPhillips name and continues to be our partner in FCCL. The downstream entity was named Phillips 66 and is our partner in WRB.

 

 

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·

In the third quarter, phase D of Christina Lake achieved first production, approximately three months ahead of schedule. Total gross production for all phases at Christina Lake averaged almost 64,000 bbls/d in 2012.

 

 

·

In the third quarter, steam injection commenced on the second well pair at Grand Rapids, with first production expected in the first quarter of 2013 from this pilot well.

 

 

·

In the third quarter, we completed a public offering in the U.S. of senior unsecured notes of US$500 million, with a coupon rate of 3.00 percent, due August 15, 2022 and US$750 million of senior unsecured notes with a coupon rate of 4.45 percent due September 15, 2042, for an aggregate amount of US$1.25 billion.

 

 

·

In the fourth quarter, with the drilling and facility construction completed, the operation of the Telephone Lake dewatering pilot commenced.

 

 

·

In the fourth quarter, we received regulatory approval to add cogeneration facilities at Christina Lake and increase expected total gross production capacity by 10,000 bbls/d at each of phase F and G.

 

 

·

In the fourth quarter, we acquired assets located adjacent to our proposed Telephone Lake oil sands project in Northern Alberta for cash of $10 million and the assumption of related decommissioning obligations.

 

2011

 

·

In the second quarter, we updated our 10 year strategic plan, identifying oil sands bitumen 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 have been successful and have resulted in a five percent increase to clean product yield. The Wood River Refinery’s total processing capability of heavy crude oil is 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 an expected 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.

 

 

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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 was 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.

 

 

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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, 2012.

 

 

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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, 2012, we had a land base of approximately 7.0 million net acres and Company Interest Before Royalties proved reserves of approximately 1,717 million barrels of bitumen, 184 million barrels of heavy crude oil, 115 million barrels of light and medium crude oil and NGLs and 955 billion cubic feet of natural gas. The estimated proved reserves life index based on working interest production at December 31, 2012 was approximately 23 years. We also had Company Interest Before Royalties probable reserves of approximately 676 million barrels of bitumen, 105 million barrels of heavy crude oil, 56 million barrels of light and medium crude oil and NGLs and 338 billion cubic feet of natural gas at December 31, 2012.

 

The following narrative describes our operations in greater detail.

 

Oil Sands

 

Oil Sands includes our bitumen assets at Foster Creek, Christina Lake and Narrows Lake, as well as heavy crude oil assets at Pelican Lake and new resource play assets including Grand Rapids and Telephone Lake plus 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.

 

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 2012, our Oil Sands capital investment was $2,211 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 258,000 bbls/d of bitumen with the addition of Christina Lake phase D in the third quarter of 2012 and completion of phase E, with first production expected in the third quarter of 2013. Overall construction of Christina Lake phase E is approximately 65% complete, while the central plant is approximately 87% complete. Pelican Lake capital investment for 2012 was primarily related to infill drilling to progress polymer flood, facilities expansions, pipeline construction and maintenance capital. We also continued to assess the potential of our new resource play assets during 2012 with our large stratigraphic test well program.

 

Plans for 2013 include the continued development of expansion phases at both Foster Creek and Christina Lake, site preparation and plant construction at Narrows Lake for phase A and infill drilling to progress the polymer flood, and facilities expansions at our Pelican Lake property. Plans also include the continuation of an active stratigraphic test well program on our new resource play assets and the continuation of pilot projects at our Grand Rapids and Telephone Lake properties.

 

At December 31, 2012, we held bitumen rights of approximately 1,469,000 gross acres (1,097,000 net acres) within the Athabasca and Cold Lake areas, as well as the exclusive rights to lease an additional 478,000 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, 2012:

 

Landholdings – Oil Sands

 

Developed
Acreage

 

Undeveloped
Acreage

 

Total
Acreage

 

Average
Working

(thousands of acres)

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Interest

Foster Creek

 

13

 

7

 

127

 

63

 

140

 

70

 

50%

Christina Lake

 

6

 

3

 

33

 

16

 

39

 

19

 

50%

Pelican Lake

 

102

 

102

 

291

 

286

 

393

 

388

 

99%

Narrows Lake

 

-

 

-

 

26

 

13

 

26

 

13

 

50%

Telephone Lake

 

3

 

3

 

144

 

144

 

147

 

147

 

100%

Athabasca

 

417

 

345

 

454

 

380

 

871

 

725

 

83%

Other

 

41

 

27

 

1,181

 

890

 

1,222

 

917

 

75%

Total

 

582

 

487

 

2,256

 

1,792

 

2,838

 

2,279

 

80%

 

 

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The following table summarizes 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)

 

2012

 

2011

 

2012

 

2011

 

2012

 

2011

 

Foster Creek

 

57,833

 

54,868

 

-

 

-

 

57,833

 

54,868

 

Christina Lake

 

31,903

 

11,665

 

-

 

-

 

31,903

 

11,665

 

Pelican Lake

 

22,552

 

20,424

 

-

 

-

 

22,552

 

20,424

 

Athabasca

 

-

 

-

 

30

 

34

 

5,000

 

5,667

 

Other

 

-

 

-

 

3

 

3

 

500

 

500

 

Total

 

112,288

 

86,957

 

33

 

37

 

117,788

 

93,124

 

 

The following table summarizes our interests in producing wells at December 31, 2012. These figures exclude wells which were capable of producing, but that were not producing as of December 31, 2012:

 

Producing Wells – Oil Sands

 

Producing
Oil Wells

 

Producing
 Gas Wells

 

Total
Producing Wells

 

(number of wells)

 

Gross 

 

Net 

 

Gross 

 

Net 

 

Gross

 

Net 

 

Foster Creek

 

217

 

109

 

-

 

-

 

217

 

109

 

Christina Lake

 

65

 

33

 

-

 

-

 

65

 

33

 

Pelican Lake

 

515

 

515

 

7

 

7

 

522

 

522

 

Athabasca

 

-

 

-

 

293

 

280

 

293

 

280

 

Other

 

-

 

-

 

17

 

17

 

17

 

17

 

Total

 

797

 

657

 

317

 

304

 

1,114

 

961

 

 

Foster Creek

 

We have a 50 percent interest in Foster Creek, an oil sands property in northeast Alberta that uses 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.

 

Development of expansion phases F, G and H at Foster Creek is progressing as planned with start-up from phase F expected in the third quarter of 2014. Cenovus expects to file an application with regulators in 2013 for an additional Foster Creek expansion, phase J. With the addition of these four phases Cenovus expects Foster Creek will have the capacity to produce 295,000 bbls/d gross and potentially as much as 310,000 bbls/d gross with optimization.

 

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 2012, no wells using our Wedge WellTM technology were drilled (2011 – 10 wells) at Foster Creek. At December 31, 2012 there were 56 producing wells of this type.

 

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. Full capacity was reached at phase C in the second quarter, while phase D had first oil production in late July, approximately three months ahead of schedule. With the addition of phase D, gross production capacity at Christina Lake of 98,000 bbls/d was achieved in the first quarter of 2013. In 2011, we received regulatory approval for phases E, F and G which are expected to add approximately 140,000 bbls/d of gross production capacity. In the fourth quarter of 2012, we received regulatory approval to add cogeneration facilities at Christina Lake and increase total gross production capacity by 10,000 bbls/d at each of phase F and phase G. With the addition of another four planned phases, we believe Christina Lake has potential gross production capacity of 288,000 bbls/d, increasing to as much as 300,000 bbls/d with optimization. In 2012, we drilled three wells (2011 – three wells) at Christina Lake using our Wedge WellTM technology and at December 31, 2012 there were six gross wells of this type producing.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2012

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Several innovations to SAGD technology have been undertaken at Christina Lake over the past several years. One major innovation is SAP technology that is currently being piloted at Christina Lake. This SAP pilot utilizes a mixture of steam and solvent to enhance recovery of the bitumen by increasing production rates and overall oil recovery, as well as reducing the steam to oil ratio. Results from the pilot were as expected, and we plan to commercialize the SAP technology with phase A of our Narrows Lake project.

 

We have 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 of the EIA was filed. The project includes planned gross production capacity of 130,000 bbls/d of bitumen. In the second quarter of 2012, we received regulatory approval for the Narrows Lake project, which includes the use of both traditional SAGD and SAGD with the SAP enhancement. In the fourth quarter of 2012, phase A, which has planned gross production capacity of 45,000 bbls/d, received partner approval. The project is expected to begin producing in 2017.

 

Pelican Lake

 

Using a patterned, 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 2012, our capital investment primarily related to infill drilling to progress the polymer flood, facilities expansions, pipeline construction and maintenance programs. In 2012, we drilled 76 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 as described below.

 

Grand Rapids

 

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. 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. During 2012, we continued to operate the pilot project at Grand Rapids and drilled the second well pair, which is currently steaming with production expected in the first quarter of 2013.

 

Telephone Lake

 

Our Telephone Lake property is located in the Borealis Region in northeast Alberta. A revised joint application and EIA was submitted in the fourth quarter of 2011 to the ERCB and Alberta Environment for the development of the property, including the construction of a facility with planned bitumen production capacity of 90,000 bbls/d. Portions of the Telephone Lake reservoir are overlain with non-

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2012

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saline water. To improve SAGD performance, this water should be removed in advance of SAGD operations. In the fourth quarter of 2012, a pilot program commenced to dewater a confined area and the results will be monitored throughout 2013.

 

Other Assets

 

The Steepbank and East McMurray properties are also located in the Borealis Region, southwest of Telephone Lake. An active stratigraphic drilling program is being carried out at these properties. In 2012, 59 gross stratigraphic wells were drilled and 204 km of 2D seismic was shot.

 

We have completed a pilot program which uses a helicopter and an experimental lightweight drilling rig to drill stratigraphic test wells. The SkyStratTM drilling rig is a new rig we developed to improve stratigraphic drilling programs in the oil sands, as the rig is transported by helicopter which allows us to access remote exploratory drilling locations year-round. Transporting by helicopter eliminates the need for temporary roads, which significantly reduces the surface footprint and has the potential to reduce water use for the drilling operations by up to 50 percent. In 2012, this rig was used to drill 15 stratigraphic wells and we plan to drill 20 wells in 2013. We also plan to build a second SkyStratTM drilling rig in 2013.

 

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 19 million cubic feet per day in 2012 (2011 - 21 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 dependent on natural gas prices.

 

Conventional

 

Conventional includes the development and production of conventional crude oil, NGLs and natural gas in Alberta and Saskatchewan, including the carbon dioxide enhanced oil recovery project at Weyburn and emerging tight oil opportunities.

 

At December 31, 2012, we had an established land position of approximately 4.9 million gross acres (4.7 million net acres), of which approximately 3.2 million gross acres (3.0 million net acres) are developed. The mineral rights on approximately 66 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 2012, our Conventional capital investment was $848 million and primarily focused on crude oil properties, including drilling, completion and major facilities work in Saskatchewan and tight oil opportunities in Alberta.

 

Plans for 2013 include oil focused capital investment to further develop our existing assets in Alberta and Saskatchewan.  The spending will include additional drilling, well optimizations, well recompletions and investment in our existing facility infrastructure.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2012

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The following table summarizes our landholdings at December 31, 2012:

 

Landholdings – Conventional

 

Developed

 

Undeveloped

 

Total

 

 

Average
Working

(thousands of acres)

 

Gross

 

Net

 

Gross

 

Net

 

 

Gross

 

Net

 

 

Interest

Alberta

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Suffield

 

914

 

904

 

131

 

129

 

 

1,045

 

1,033

 

 

99%

Brooks North

 

571

 

569

 

8

 

8

 

 

579

 

577

 

 

100%

Langevin

 

735

 

695

 

248

 

230

 

 

983

 

925

 

 

94%

Drumheller

 

404

 

391

 

51

 

49

 

 

455

 

440

 

 

97%

Wainwright

 

357

 

335

 

205

 

201

 

 

562

 

536

 

 

95%

NW Alberta

 

32

 

7

 

128

 

102

 

 

160

 

109

 

 

68%

Saskatchewan

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weyburn

 

114

 

100

 

349

 

328

 

 

463

 

428

 

 

92%

Shaunavon / Bakken

 

40

 

38

 

361

 

360

 

 

401

 

398

 

 

99%

Other

 

9

 

6

 

19

 

19

 

 

28

 

25

 

 

89%

Manitoba

 

4

 

4

 

262

 

262

 

 

266

 

266

 

 

100%

Total

 

3,180

 

3,049

 

1,762

 

1,688

 

 

4,942

 

4,737

 

 

96%

 

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)

 

2012

 

2011

 

2012

 

2011

 

2012

 

2011

Alberta

 

 

 

 

 

 

 

 

 

 

 

 

Suffield

 

11,691

 

11,505

 

167

 

182

 

39,524

 

41,838

Brooks North

 

2,866

 

2,064

 

225

 

236

 

40,366

 

41,397

Langevin

 

7,719

 

7,361

 

109

 

118

 

25,886

 

27,028

Drumheller

 

3,653

 

2,298

 

54

 

61

 

12,653

 

12,465

Wainwright

 

4,417

 

4,251

 

3

 

-

 

4,917

 

4,251

NW Alberta

 

11

 

9

 

2

 

22

 

344

 

3,676

Saskatchewan

 

 

 

 

 

 

 

 

 

 

 

 

Weyburn

 

16,278

 

16,178

 

-

 

-

 

16,278

 

16,178

Shaunavon / Bakken

 

6,480

 

3,616

 

1

 

-

 

6,647

 

3,616

Total

 

53,115

 

47,282

 

561

 

619

 

146,615

 

150,449

 

The following table summarizes our interests in producing wells at December 31, 2012. These figures exclude wells which were capable of producing, but that were not producing, at December 31, 2012:

 

Producing Wells – Conventional

 

Producing
Oil Wells

 

Producing
Gas Wells

 

Total
Producing Wells

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Alberta

 

 

 

 

 

 

 

 

 

 

 

 

 

Suffield

 

769

 

769

 

10,654

 

10,636

 

11,423

 

11,405

 

Brooks North

 

147

 

146

 

7,496

 

7,397

 

7,643

 

7,543

 

Langevin

 

257

 

254

 

4,831

 

4,816

 

5,088

 

5,070

 

Drumheller

 

216

 

211

 

1,594

 

1,537

 

1,810

 

1,748

 

Wainwright

 

453

 

415

 

13

 

3

 

466

 

418

 

NW Alberta

 

7

 

1

 

3

 

2

 

10

 

3

 

Saskatchewan

 

 

 

 

 

 

 

 

 

 

 

 

 

Weyburn

 

687

 

433

 

-

 

-

 

687

 

433

 

Shaunavon / Bakken

 

168

 

157

 

-

 

-

 

168

 

157

 

Total

 

2,704

 

2,386

 

24,591

 

24,391

 

27,295

 

26,777

 

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2012

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Crude Oil Properties

 

We hold interests in multiple zones in the Suffield, Brooks North, Langevin, Drumheller, and Wainwright areas in Alberta with a mix of medium and heavy crude oil production. Development in these areas focuses on horizontal drilling targeting tight oil formations, infill drilling to enhance recovery in producing areas, optimization of existing wells to maximize production and other specialized oil recovery methods that increase our overall recovery factors in each field.

 

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 to 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, 2012, approximately 90 percent of the approved CO2 flood pattern development at the Weyburn unit was complete. Since the inception of the project, approximately 20 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. A new contract was executed in 2012 for the purchase of CO2 from Saskatchewan Power Corporation providing an additional source of CO2 in the future.

 

In 2012, we continued developing our medium and light crude oil prospects in the Bakken and Lower Shaunavon zones in Saskatchewan. Our capital investment focused on drilling, completions, and facility work, including the construction and commissioning of batteries in both the Bakkan and Lower Shaunavon areas and supporting infrastructure. Most of the sections of land that we hold in these areas are Crown land.

 

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

 

2012

 

2011

 

2012

 

2011

 

2012

 

2011

Alberta

 

 

 

 

 

 

 

 

 

 

 

 

Suffield

 

38

 

45

 

-

 

-

 

11,667

 

11,484

Brooks North

 

52

 

42

 

2,707

 

1,898

 

-

 

-

Langevin

 

44

 

68

 

7,551

 

7,172

 

-

 

-

Drumheller

 

33

 

49

 

3,051

 

1,617

 

-

 

-

Wainwright

 

57

 

29

 

58

 

67

 

4,348

 

4,173

NW Alberta

 

-

 

-

 

11

 

9

 

-

 

-

Other

 

2

 

-

 

-

 

-

 

-

 

-

Saskatchewan

 

 

 

 

 

 

 

 

 

 

 

 

Weyburn

 

6

 

6

 

16,277

 

16,180

 

-

 

-

Shaunavon / Bakken

 

40

 

81

 

6,416

 

3,581

 

-

 

-

Other

 

4

 

5

 

-

 

-

 

-

 

-

Total

 

276

 

325

 

36,071

 

30,524

 

16,015

 

15,657

 

Natural Gas Properties

 

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

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2012

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Table of Contents

 

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

 

2012

 

2011

 

2012

 

2011

 

Suffield

 

-

 

-

 

167

 

182

 

Brooks North

 

-

 

65

 

225

 

236

 

Langevin

 

-

 

-

 

109

 

118

 

Drumheller

 

-

 

-

 

54

 

61

 

Wainwright

 

-

 

-

 

3

 

-

 

Other

 

-

 

-

 

3

 

22

 

Total

 

-

 

65

 

561

 

619

 

 

 

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.

 

In the fourth quarter, the Government of Canada announced that our proposed Shallow Gas Infill Drilling Development Project in the National Wildlife Area (“NWA”) of CFB Suffield was not approved.  The shallow gas wells we currently have in the NWA are not affected by this decision, and neither are our other oil and natural gas operations in the rest of Suffield.

 

Natural gas assets are an important component of our financial foundation, generating reliable 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.

 

We plan to prudently 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 we have a 50 percent ownership interest in both the Wood River and Borger Refineries located in Roxana, Illinois and Borger, Texas respectively. Phillips 66 is the operator and managing partner of WRB. WRB has a management committee, which is composed of three Cenovus representatives and three Phillips 66 representatives, with each company holding equal voting rights. In 2013, on a 100 percent basis, our refineries have stated processing capacity of approximately 457,000 bbls/d of crude oil (2012 – 452,000 bbls/d), including heavy crude oil processing capability of approximately 235,000 to 255,000 bbls/d.

 

Wood River Refinery

 

The Wood River Refinery 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 as well as coke 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.

 

Throughout 2012, the Wood River Refinery had stated processing capacity of 306,000 bbls/d. The start-up of the CORE project was substantially completed in 2011 and the Wood River Refinery demonstrated the benefits of this project in 2012, including an approximate 5 percent increase in clean product yield and Canadian heavy crude oil processing capability averaging in excess of 200,000 bbls/d, when not in turnaround.

 

For 2013, the Wood River Refinery’s stated processing capacity is 311,000 bbls/d of crude oil. This figure is determined based on the guidelines for calculating maximum demonstrated rate, which is 95 percent of the highest average rate achieved over a continuous 30 day period.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2012

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Borger Refinery

 

The Borger Refinery 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.

 

Throughout 2012, the Borger Refinery had a stated 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.

 

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

 

Refinery Operations(1)

 

2012

 

2011

 

Crude Oil Capacity (Mbbls/d)

 

452

 

452

 

Crude Oil Runs (Mbbls/d)

 

412

 

401

 

Crude Utilization (%)

 

91

 

89

 

Refined Products (Mbbls/d)

 

 

 

 

 

Gasoline

 

216

 

207

 

Distillates

 

138

 

132

 

Other

 

79

 

80

 

Total

 

433

 

419

 

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.

 

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, 2012.

 

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 crude oil 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.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2012

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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 coal bed methane (“CBM”) reserves annually. McDaniel evaluated approximately 96 percent of our total proved reserves, located throughout Alberta and Saskatchewan, and GLJ evaluated approximately four percent of our total proved reserves, located at 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.

 

The reserves data and other oil and gas information contained in this AIF is dated February 12, 2013, with an effective date of December 31, 2012. McDaniel’s preparation date of the information is January 10, 2013, and GLJ’s preparation date is January 3, 2013.

 

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 and facilities 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, 2012, 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”).

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2012

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Summary of Company Interest Oil and Gas Reserves at December 31, 2012

(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

 

172

 

121

 

84

 

917

 

Developed Non-Producing

 

13

 

1

 

9

 

32

 

Undeveloped

 

1,532

 

62

 

22

 

6

 

Total Proved Reserves

 

1,717

 

184

 

115

 

955

 

Probable Reserves

 

676

 

105

 

56

 

338

 

Total Proved plus
Probable Reserves

 

2,393

 

289

 

171

 

1,293

 

 

After Royalties(2)

 

 

 

 

 

 

 

 

 

 

Reserves Category

 

Bitumen
(MMbbls)

 

Heavy Oil
(MMbbls)

 

Light & Medium
Oil & NGLs
(MMbbls)

 

Natural Gas
& CBM
(Bcf)

 

Proved Reserves

 

 

 

 

 

 

 

 

 

Developed Producing

 

134

 

102

 

73

 

930

 

Developed Non-Producing

 

10

 

1

 

7

 

31

 

Undeveloped

 

1,149

 

51

 

18

 

6

 

Total Proved Reserves

 

1,293

 

154

 

98

 

967

 

Probable Reserves

 

499

 

79

 

46

 

324

 

Total Proved plus
Probable Reserves

 

1,792

 

233

 

144

 

1,291

 

 

Royalty Interest

 

 

 

 

 

 

 

 

 

 

Reserves Category

 

Bitumen
(MMbbls)

 

Heavy Oil
(MMbbls)

 

Light & Medium
Oil & NGLs
(MMbbls)

 

Natural Gas
& CBM
(Bcf)

 

Proved Reserves

 

 

 

 

 

 

 

 

 

Developed Producing

 

-

 

1

 

4

 

43

 

Developed Non-Producing

 

-

 

-

 

-

 

-

 

Undeveloped

 

-

 

-

 

-

 

-

 

Total Proved Reserves

 

-

 

1

 

4

 

43

 

Probable Reserves

 

-

 

1

 

2

 

13

 

Total Proved plus
Probable Reserves

 

-

 

2

 

6

 

56

 

Notes:

(1)        Does not include Royalty Interest Reserves.

(2)        Includes Royalty Interest Reserves.

 

Summary of Net Present Value of Future Net Revenue at December 31, 2012

(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

 

14,927

 

12,313

 

10,485

 

9,155

 

8,149

 

22.62

 

Developed Non-Producing

 

1,048

 

762

 

592

 

480

 

401

 

24.90

 

Undeveloped

 

50,592

 

24,053

 

12,798

 

7,301

 

4,313

 

10.50

 

Total Proved Reserves

 

66,567

 

37,128

 

23,875

 

16,936

 

12,863

 

13.99

 

Probable Reserves

 

31,347

 

14,385

 

7,635

 

4,598

 

3,055

 

11.25

 

Total Proved plus
Probable Reserves

 

97,914

 

51,513

 

31,510

 

21,534

 

15,918

 

13.21

 

Note:

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

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2012

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Table of Contents

 

After Income Taxes(1)

 

 

 

 

 

 

 

 

 

 

 

 

 

Discounted at %/year ($ millions)

Reserves Category

 

0%

 

5%

 

10%

 

15%

 

20%

 

Proved Reserves

 

 

 

 

 

 

 

 

 

 

 

Developed Producing

 

11,990

 

9,951

 

8,510

 

7,457

 

6,658

 

Developed Non-Producing

 

788

 

574

 

447

 

364

 

306

 

Undeveloped

 

37,993

 

17,835

 

9,342

 

5,219

 

2,993

 

Total Proved Reserves

 

50,771

 

28,360

 

18,299

 

13,040

 

9,957

 

Probable Reserves

 

23,465

 

10,675

 

5,623

 

3,362

 

2,218

 

Total Proved plus
Probable Reserves

 

74,236

 

39,035

 

23,922

 

16,402

 

12,175

 

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, 2012.

 

Total Future Net Revenue (undiscounted) at December 31, 2012

(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

 

165,198

 

37,812

 

43,995

 

15,627

 

1,197

 

66,567

 

15,796

 

50,771

 

Proved plus Probable Reserves

 

240,555

 

56,238

 

63,315

 

21,709

 

1,379

 

97,914

 

23,678

 

74,236

 

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.

 

Future Net Revenue by Production Group at December 31, 2012

(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

 

17,119

 

13.23

 

 

 

Heavy Oil

 

2,697

 

17.55

 

 

 

Light & Medium Crude Oil and NGLs

 

2,538

 

25.91

 

 

 

Natural Gas

 

1,521

 

9.44

 

 

 

Total

 

23,875

 

13.99

 

 

 

 

 

 

 

 

 

Proved plus

 

Bitumen

 

21,771

 

12.15

 

Probable Reserves

 

Heavy Oil

 

4,224

 

18.11

 

 

 

Light & Medium Crude Oil and NGLs

 

3,454

 

23.96

 

 

 

Natural Gas

 

2,061

 

9.58

 

 

 

Total

 

31,510

 

13.21

 

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2012

17

 



Table of Contents

 

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.

 

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.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2012

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Table of Contents

 

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, 2013 price forecast as referred to in the McDaniel & Associates Consultants Ltd. Summary of Price Forecasts dated January 1, 2013. For historical prices realized during 2012, 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)

 

2013

 

92.50

 

87.50

 

83.10

 

65.60

 

73.90

 

 

3.35

 

2.0

 

1.00

 

2014

 

92.50

 

90.50

 

86.00

 

67.90

 

76.50

 

 

3.85

 

2.0

 

1.00

 

2015

 

93.60

 

92.60

 

88.00

 

69.50

 

78.20

 

 

4.35

 

2.0

 

1.00

 

2016

 

95.50

 

94.50

 

89.80

 

70.90

 

79.90

 

 

4.70

 

2.0

 

1.00

 

2017

 

97.40

 

96.40

 

91.60

 

72.30

 

81.50

 

 

5.10

 

2.0

 

1.00

 

2018

 

99.40

 

98.30

 

93.40

 

73.70

 

83.10

 

 

5.45

 

2.0

 

1.00

 

2019

 

101.40

 

100.30

 

95.30

 

75.20

 

84.80

 

 

5.55

 

2.0

 

1.00

 

2020

 

103.40

 

102.30

 

97.20

 

76.70

 

86.40

 

 

5.70

 

2.0

 

1.00

 

2021

 

105.40

 

104.30

 

99.10

 

78.20

 

88.10

 

 

5.80

 

2.0

 

1.00

 

2022

 

107.60

 

106.50

 

101.20

 

79.90

 

90.00

 

 

5.90

 

2.0

 

1.00

 

2023

 

109.70

 

108.50

 

103.10

 

81.40

 

91.70

 

 

6.00

 

2.0

 

1.00

 

There-after

 

+2%/yr

 

+2%/yr

 

+2%/yr

 

+2%/yr

 

+2%/yr

 

 

+2%/yr

 

2.0

 

1.00

 

 

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)

 

2013

 

2014

 

2015

 

2016

 

2017

 

Remainder

 

Total

 

Proved Reserves

 

1,680

 

1,315

 

1,122

 

706

 

929

 

9,875

 

15,627

 

Proved plus Probable Reserves

 

1,761

 

1,493

 

1,436

 

912

 

1,067

 

15,040

 

21,709

 

 

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, 2012

19

 



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, 2012, 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, 2011

 

1,455

 

175

 

115

 

1,203

 

Extensions and Improved Recovery

 

265

 

17

 

13

 

29

 

Discoveries

 

-

 

-

 

-

 

-

 

Technical Revisions

 

30

 

6

 

(2

)

51

 

Economic Factors

 

-

 

-

 

-

 

(58

)

Acquisitions

 

-

 

-

 

1

 

1

 

Dispositions

 

-

 

-

 

-

 

(59

)

Production(1)

 

(33

)

(14

)

(12

)

(212

)

December 31, 2012

 

1,717

 

184

 

115

 

955

 

 

 

Probable

 

 

 

 

 

 

 

 

 

 

 

Bitumen
(MMbbls)

 

Heavy Oil
(MMbbls)

 

Light &
Medium
Oil & NGLs
(MMbbls)

 

Natural
Gas & CBM
(Bcf)

 

December 31, 2011

 

490

 

109

 

51

 

391

 

Extensions and Improved Recovery

 

140

 

11

 

5

 

8

 

Discoveries

 

-

 

-

 

-

 

-

 

Technical Revisions

 

46

 

(15

)

-

 

(30

)

Economic Factors

 

-

 

-

 

-

 

(4

)

Acquisitions

 

-

 

-

 

-

 

-

 

Dispositions

 

-

 

-

 

-

 

(27

)

Production(1)

 

-

 

-

 

-

 

-

 

December 31, 2012

 

676

 

105

 

56

 

338

 

 

 

Proved plus Probable 

 

 

 

 

 

 

 

 

 

 

 

Bitumen
(MMbbls)

 

Heavy Oil
(MMbbls)

 

Light &
Medium
Oil & NGLs
(MMbbls)

 

Natural
Gas & CBM
(Bcf)

 

December 31, 2011

 

1,945

 

284

 

166

 

1,594

 

Extensions and Improved Recovery

 

405

 

28

 

18

 

37

 

Discoveries

 

-

 

-

 

-

 

-

 

Technical Revisions

 

76

 

(9

)

(2

)

21

 

Economic Factors

 

-

 

-

 

-

 

(62

)

Acquisitions

 

-

 

-

 

1

 

1

 

Dispositions

 

-

 

-

 

-

 

(86

)

Production(1)

 

(33

)

(14

)

(12

)

(212

)

December 31, 2012

 

2,393

 

289

 

171

 

1,293

 

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.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2012

20

 



Table of Contents

 

Proved and proved plus probable bitumen reserves increased by approximately 18 and 23 percent respectively. Regulatory approval and partner sanction of the Narrows Lake project enabled initial booking of proved and proved plus probable reserves. Increases at Christina Lake were primarily a result of plans to increase well density in the development area and improving steam to oil ratio performance. Increases at Foster Creek were primarily due to increased recovery resulting from improved steam to oil ratio performance and more efficient drainage of bitumen in the steam chamber.

 

Proved heavy oil reserves increased by approximately five percent primarily as a result of expanding polymer flood areas and their successful performance in the Greater Pelican Region. Probable heavy oil reserves decreased by approximately three percent also based on conversion of probable reserves to proved reserves. Proved plus probable reserves increased by approximately two percent.

 

Proved light and medium oil and NGLs reserves remained unchanged, with production being offset by expanding waterflood and CO2 flood areas and their successful performance at Weyburn. Probable light and medium oil and NGLs reserves increased by approximately 10 percent as a result of continued strong performance. Overall, proved plus probable reserves increased by approximately three percent.

 

Proved natural gas reserves declined by approximately 21 percent as extensions and technical revisions did not offset production and dispositions. Also included in the decline is a loss of 58 Bcf of gas reserves due to lower gas prices in the forecast causing some gas reserves to become uneconomic to produce. Probable natural gas reserves and proved plus probable reserves declined by approximately 13 percent and 19 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 46 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

 

813

 

734

 

55

 

46

 

45

 

28

 

282

 

35

 

2010

 

295

 

1,008

 

5

 

45

 

5

 

27

 

18

 

36

 

2011

 

325

 

1,287

 

13

 

55

 

3

 

25

 

-

 

24

 

2012

 

284

 

1,532

 

20

 

61

 

3

 

22

 

-

 

6

 

 

 

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

 

633

 

467

 

43

 

43

 

26

 

26

 

38

 

38

 

2010

 

171

 

506

 

-

 

37

 

2

 

21

 

16

 

30

 

2011

 

113

 

467

 

14

 

47

 

1

 

22

 

-

 

35

 

2012

 

182

 

646

 

9

 

42

 

5

 

24

 

-

 

16

 

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2012

21

 



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Development of Proved Undeveloped Reserves

 

Bitumen

 

At the end of 2012, we had proved undeveloped bitumen reserves of 1,532 million barrels Before Royalties, or approximately 89 percent of our total proved bitumen reserves. Of our 676 million barrels of probable bitumen reserves, 646 million barrels, or approximately 96 percent are undeveloped. The evaluation of these reserves anticipates they 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 well pairs 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’s standard for sufficient drilling is a minimum of 8 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.

 

Recognition 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’s 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 44 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 proved undeveloped reserves is projected to continue for well over 40 years, with drilling of supplementary wells taking place over the next eight years, and CO2 flood advancement continuing many years beyond that. At Pelican Lake, investment in proved undeveloped reserves is projected to continue for 28 years, with a combination of infrastructure development, 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”.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2012

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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.

 

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. Only those bitumen contingent resources based on established technology and determined to be economic using the same price assumptions that were used for the 2012 reserves evaluation are disclosed in this AIF.

 

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.

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2012

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Table of Contents

 

At Christina Lake and Foster Creek we have economic contingent resources located outside the currently approved development project areas. Regulatory approval of development 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 2012, we received regulatory approval and partner sanction for a development project at Narrows Lake. This enabled reclassification of a significant portion of the contingent resources previously identified as proved and probable reserves.

 

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.

 

Application for development project approval at the Grand Rapids property in the Greater Pelican Lake area was submitted in 2011. Provided all regulatory requirements are met, we anticipate receiving regulatory approval in 2013. Pilot project work is underway to examine optimal development strategies.

 

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 probability 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 included in the low estimate range have the highest degree of certainty - a 90 percent probability – 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 included in the high estimate range have a lower degree of certainty - a 10 percent probability - that the actual quantities recovered will equal or exceed the estimate.

 

The economic contingent resources were estimated for individual projects and then aggregated for disclosure purposes. The high and low estimate volumes are arithmetic sums of multiple estimates which statistical principles indicate may be misleading as to volumes that may actually be recovered. Because the results are aggregated for disclosure, the low estimate results disclosed may have a higher probability than the estimates for the individual projects, and the high estimate results disclosed may have a lower probability than the estimates for individual projects.

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2012

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Table of Contents

 

Bitumen Economic Contingent and Prospective Resources

Company Interest Before Royalties, Billions of barrels

December 31,

2012

December 31,

2011

Economic Contingent Resources(1)

 

 

Low Estimate

7.1

6.0

Best Estimate

9.6

8.2

High Estimate

12.8

10.8

Prospective Resources(2)

 

 

Low Estimate

5.0

5.7

Best Estimate

8.5

10.0

High Estimate

14.8

17.9

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.

 

Economic bitumen best estimate contingent resources increased 1.4 billion barrels or 17 percent compared to 2011. This increase is primarily due to successful stratigraphic well drilling resulting in the conversion of prospective resources to contingent resources, the recognition of SAGD feasibility in the Wabiskaw formation adjacent to Foster Creek, and the recognition of contingent resources on acquired land near Telephone Lake, and was partially offset by conversion of contingent resources at Narrows Lake to proved and probable reserves.

 

Bitumen best estimate prospective resources declined 1.5 billion barrels or approximately 15 percent compared to 2011, primarily as a result of the reclassification of prospective resources to contingent resources resulting from stratigraphic well drilling, and the sterilization of lands resulting from the anticipated provincial adoption of the Lower Athabasca Regional Plan. Refer to “Risk Factors – Alberta’s Land-Use Framework” for more information on the Lower Athabasca Regional Plan.

 

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, 2011

1.945

8.2

10.0

Transfers between Categories

 

 

 

Additions from other resource categories

0.359

1.0

(1.0)

Reductions to other resource categories

-

(0.4)

-

Additions and Revisions Net of Transfers

0.121

0.5

(0.8)

Net Acquisitions and Dispositions

-

0.3

0.3

Production

(0.032)

-

-

December 31, 2012

2.393

9.6

8.5

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, regulatory approval and partner sanction of the Narrows Lake project and partner approval of phase A 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.

 

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.

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2012

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Table of Contents

 

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, 2012:

 

Producing Wells(1)(2)

 

Oil

Gas

Total

 

Gross

Net

Gross

Net

Gross

Net

Alberta

 

 

 

 

 

 

  Oil Sands

797

657

317

304

1,114

961

  Conventional

1,849

1,795

24,591

24,391

26,440

26,186

Total Alberta

2,646

2,452

24,908

24,695

27,554

27,147

Saskatchewan

855

590

-

-

855

590

Total

3,501

3,042

24,908

24,695

28,409

27,737

Notes:

(1)

Cenovus also has varying royalty interests in 9,135 natural gas wells and 3,449 crude oil wells which are producing.

(2)

Includes wells containing multiple completions as follows: 22,728 gross natural gas wells (22,585 net wells) and 1,324 gross crude oil wells (1,223 net wells).

 

Non-Producing Wells(1)

 

 

 

 

Oil

Gas

Total

 

Gross

Net

Gross

Net

Gross

Net

Alberta

 

 

 

 

 

 

  Oil Sands

90

83

644

509

734

592

  Conventional

749

722

802

777

1,551

1,499

Total Alberta

839

805

1,446

1,286

2,285

2,091

Saskatchewan

121

83

28

27

149

110

Total

960

888

1,474

1,313

2,434

2,201

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

2012:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil Sands

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

-

Conventional

 

8

 

7

 

-

 

-

 

-

 

-

 

8

 

7

 

20

 

28

 

7

Total Canada

 

8

 

7

 

-

 

-

 

-

 

-

 

8

 

7

 

20

 

28

 

7

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: