40-F 1 a14-5065_140f.htm 40-F

 

 

 

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

 

x

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

 

For the fiscal year ended: December 31, 2013      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)

 

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:

 

x Annual information form      x 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:

 

756,045,621

 

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 x   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-3D (File No. 333-166419), and Form F-10 (File No. 333-188478).

 

 

 



 

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, 2013.

 

(b)          Management’s Discussion and Analysis of Cenovus Energy Inc. for the fiscal year ended December 31, 2013.

 

(c)          Consolidated Financial Statements of Cenovus Energy Inc. for the fiscal year ended December 31, 2013.

 

(d)          Supplementary Information — Oil and Gas Activities (unaudited) for the fiscal year ended December 31, 2013.

 

2



 

GRAPHIC

 

CENOVUS ENERGY INC.

 

ANNUAL INFORMATION FORM

 

FOR THE YEAR ENDED DECEMBER 31, 2013

 



 

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

11

Refining and Marketing

14

RESERVES DATA AND OTHER OIL AND GAS INFORMATION

16

Disclosure of Reserves Data

16

Definitions

19

Reserves Reconciliation

21

Contingent and Prospective Resources

24

Other Oil and Gas Information

27

OTHER INFORMATION

37

Competitive Conditions

37

Environmental Considerations

37

Corporate Responsibility Practice

38

Employees

39

Foreign Operations

39

DIRECTORS AND EXECUTIVE OFFICERS

40

AUDIT COMMITTEE

45

DESCRIPTION OF CAPITAL STRUCTURE

47

DIVIDENDS

49

MARKET FOR SECURITIES

49

RISK FACTORS

49

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

60

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

60

MATERIAL CONTRACTS

60

TRANSFER AGENTS AND REGISTRARS

60

ADDITIONAL INFORMATION

61

ABBREVIATIONS AND CONVERSIONS

61

 

APPENDIX A -

Report on Reserves Data by Independent Qualified Reserves Evaluators

APPENDIX B -

Report of Management and Directors on Reserves Data and Other Information

APPENDIX C -

Audit Committee Mandate

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2013

 

ii



 

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”, “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, forecast operating and financial results, planned capital expenditures, expected future production, including the timing, stability or growth thereof, 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 Energy Inc. 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 natural gas liquids (“NGLs”) 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 earnings before interest, taxes, depreciation and amortization 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 including sufficient crude-by-rail or alternate transportation to address any gaps caused by operational constraints in the pipeline system; 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, 2013

 

1



 

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, references to “we”, “us”, “our”, “its”, “Company” or “Cenovus” mean Cenovus Energy Inc., the subsidiaries of, and partnership interests held by, Cenovus Energy Inc. and its subsidiaries.

 

Our head 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, 2013:

 

Subsidiaries & Partnerships

 

Percentage
Owned
(1)

 

Jurisdiction of
Incorporation,
Continuance, Formation
or Organization

 

Cenovus FCCL Ltd.

 

100

 

Alberta

 

Cenovus Energy Marketing Services 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.

(3)        Cenovus interest held directly 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, 2013.

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2013

 

2



 

GENERAL DEVELOPMENT OF OUR BUSINESS

 

Cenovus is a Canadian integrated oil company headquartered in Calgary, Alberta. We are in the business of developing, producing and marketing crude oil, NGLs and natural gas in Canada with refining operations in two refineries in the United States (“U.S.”) in Illinois and Texas.

 

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

 

Our Business

 

Our reportable segments are as follows:

 

·                       Oil Sands, which includes the development and production of Cenovus’s bitumen assets at Foster Creek, Christina Lake and Narrows Lake as well as projects in the early stages of development, such as Grand Rapids and Telephone Lake. The Athabasca natural gas assets also form part of this segment. 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 heavy oil assets at Pelican Lake. This segment also includes 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, research costs 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.

 

The operating and reportable segments shown above have been changed from those presented in prior periods to match Cenovus’s new operating structure. All prior periods have been restated to reflect this presentation.

 

Three Year History

 

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

 

2013

 

·                       In the first quarter, we submitted regulatory applications and environmental impact assessments (“EIAs”) for Christina Lake phase H and Foster Creek phase J, with expected gross production capacity of 50,000 bbls/d from each phase.

 

·                       In the first quarter, we achieved first production from the second pilot well pair at Grand Rapids. We operated the pilot project at Grand Rapids throughout the year. The purpose of the pilot is to test reservoir performance.

 

·                       In the second quarter, we updated our 10 year strategic plan to increase our net oil sands bitumen production to approximately 435,000 barrels per day and our net crude oil production, including our conventional oil operations, to approximately 525,000 barrels per day by the end of 2023.

 

·                       In the third quarter, we sold our Lower Shaunavon asset to an unrelated third party for proceeds of approximately $240 million plus closing adjustments.

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2013

 

3



 

·                       In the third quarter, phase E of Christina Lake achieved first production, with expected gross production capacity of 40,000 bbls/d.

 

·                       In the third quarter, we completed a public offering in the U.S. of senior unsecured notes of US$450 million with a coupon rate of 3.8 percent due September 15, 2023 and US$350 million senior unsecured notes with a coupon rate of 5.2 percent due September 15, 2043, for an aggregate amount of US$800 million. The net proceeds of the offering were used to partially fund the early redemption of our US$800 million senior unsecured notes due September 2014.

 

·                       In the third quarter, construction of the Narrows Lake phase A plant was initiated. Site construction, engineering and procurement at Narrows Lake are progressing as expected. Phase A has expected gross production capacity of 45,000 bbls/d.

 

·                       In the third quarter, we received regulatory approval for the optimization program at Christina Lake phases C, D and E. This program is expected to add up to 22,000 bbls/d of gross production capacity to the Christina Lake facility.

 

·                       In the fourth quarter, the Telephone Lake dewatering pilot was successfully completed. We effectively displaced water with compressed air, removing approximately 70 percent of below-ground top water.

 

·                       In the fourth quarter, we increased our rail shipping capacity to 10,000 bbls/d.

 

·                       In the fourth quarter, we received US$1.4 billion from ConocoPhillips, our partner in FCCL, representing the remaining principal and interest due under the Partnership Contribution Receivable through our interest in FCCL, net to Cenovus.

 

·                       Timing of optimization work for Foster Creek phases F, G and H has been reassessed as part of Cenovus’s long-term reservoir management plan. Phases F, G and H are each expected to ramp-up to 30,000 bbls/d. Once these phases are complete, optimization work to lower steam to oil ratios, increase production and improve plant efficiency is expected to commence. Total gross production capacity from these three phases, including optimization, remains unchanged at 125,000 bbls/d.

 

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.

 

·                       In the third quarter, phase D of Christina Lake achieved first production, approximately three months ahead of schedule. Total gross production for phases A through D 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 achieved 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

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2013

 

4



 

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, 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. The CORE project has been successful and has resulted in the capability to increase clean product yield by up to five percent. The Wood River Refinery’s total processing capability of heavy crude oil has also increased to up to 220,000 bbls/d.

 

·                       In the fourth quarter, Cenovus filed a joint application and 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.

 

·                       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.

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2013

 

5



 

NARRATIVE DESCRIPTION OF OUR BUSINESS

 

The following map outlines the location of our upstream and refining assets as at December 31, 2013:

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2013

 

6



 

Overview

 

All of our reserves and production are located in Canada, primarily within the provinces of Alberta and Saskatchewan. At December 31, 2013, we had a land base of approximately 7.0 million net acres. The estimated proved reserves life index based on working interest production at December 31, 2013 was approximately 24 years.

 

The following table summarizes our Company Interest Before Royalties proved and probable reserves at December 31, 2013:

 

Company Interest Before Royalties(1)

 

 

 

Proved

 

Probable

 

Bitumen (MMbbls)

 

1,846

 

683

 

Heavy Oil (MMbbls)

 

179

 

140

 

Light & Medium Oil and NGLs (MMbbls)

 

115

 

50

 

Natural Gas & CBM (Bcf)

 

865

 

300

 

 


Note:

(1)  Does not include Royalty Interest Reserves. Please refer to the “Reserves Data and Other Oil and Gas Information” section for additional information.

 

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 new resource play assets including Grand Rapids and Telephone Lake, plus our Athabasca natural gas assets. Foster Creek, Christina Lake and Narrows Lake are jointly owned through FCCL 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 2013, our Oil Sands capital investment was $1,883 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 285,000 bbls/d of bitumen with the addition of Christina Lake phase E in the third quarter of 2013 and first production from Foster Creek phase F expected in the third quarter of 2014. Overall progress of Foster Creek expansion phases F, G and H is approximately 63 percent complete, while the Phase F plant facility is approximately 90 percent complete. We also continued to assess the potential of our new resource play assets during 2013 with our stratigraphic test well program.

 

Plans for 2014 include the continued development of expansion phases at both Foster Creek and Christina Lake and engineering, procurement, and construction of the phase A plant at Narrows Lake. Overall Narrows Lake phase A is approximately 16 percent complete, while the central plant is approximately 21 percent complete. Plans for 2014 also include the continuation of an active stratigraphic test well drilling program with 291 gross wells planned. The dewatering pilot at Telephone Lake was completed in the fourth quarter of 2013 and we have effectively displaced water with compressed air, removing approximately 70 percent of below-ground top water in the pilot area. Steam injection commenced in the third quarter of 2012 on our second well pair at the Grand Rapids pilot and first production was achieved in February 2013.

 

At December 31, 2013, we held bitumen rights of approximately 1.4 million gross acres (1.1 million 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.

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2013

 

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The following table summarizes our landholdings at December 31, 2013:

 

 

 

Developed

 

Undeveloped

 

Total

 

Average

 

Landholdings – Oil Sands 

 

Acreage

 

Acreage

 

Acreage

 

Working

 

(thousands of acres)

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Interest

 

Foster Creek

 

15

 

8

 

125

 

62

 

140

 

70

 

50

%

Christina Lake

 

8

 

4

 

50

 

25

 

58

 

29

 

50

%

Narrows Lake

 

 

 

26

 

13

 

26

 

13

 

50

%

Grand Rapids

 

 

 

73

 

73

 

73

 

73

 

100

%

Telephone Lake

 

16

 

16

 

142

 

142

 

158

 

158

 

100

%

Athabasca

 

417

 

345

 

454

 

380

 

871

 

725

 

83

%

Other

 

27

 

9

 

1,018

 

737

 

1,045

 

746

 

71

%

Total

 

483

 

382

 

1,888

 

1,432

 

2,371

 

1,814

 

77

%

 

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

 

 

 

Crude Oil

 

 

 

 

 

 

 

 

 

 

 

and NGLs

 

Natural Gas

 

Total Production

 

Production – Oil Sands

 

(bbls/d)

 

(MMcf/d)

 

(BOE/d)

 

(annual average)

 

2013

 

2012

 

2013

 

2012

 

2013

 

2012

 

Foster Creek

 

53,190

 

57,833

 

 

 

53,190

 

57,833

 

Christina Lake

 

49,310

 

31,903

 

 

 

49,310

 

31,903

 

Athabasca(1)

 

 

 

21

 

30

 

3,500

 

5,000

 

Total

 

102,500

 

89,736

 

21

 

30

 

106,000

 

94,736

 

 


Note:

(1) Net of internal usage of natural gas used at Foster Creek to produce steam.

 

The following table summarizes our interests in producing wells at December 31, 2013. These figures exclude wells which were capable of producing, but that were not producing as of December 31, 2013:

 

 

 

Producing

 

Producing

 

Total

 

Producing Wells – Oil Sands

 

Oil Wells

 

Gas Wells

 

Producing Wells

 

(number of wells)

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Foster Creek

 

236

 

118

 

 

 

236

 

118

 

Christina Lake

 

98

 

49

 

 

 

98

 

49

 

Grand Rapids

 

2

 

2

 

 

 

2

 

2

 

Athabasca

 

 

 

299

 

299

 

299

 

299

 

Other

 

2

 

2

 

 

 

2

 

2

 

Total

 

338

 

171

 

299

 

299

 

637

 

470

 

 

Foster Creek

 

We have a 50 percent working interest in Foster Creek, an oil sands property situated on the Cold Lake Air Weapons Range in northeastern 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.

 

Expansion work at phases F, G and H at Foster Creek is proceeding as planned. Each phase is expected to ramp-up to its initial design capacity of 30,000 bbls/d. Once these phases are complete, optimization work will commence to reduce steam to oil ratio, increase production and improve plant efficiency. Total gross production capacity for these phases, including optimization work, is expected to reach 125,000 bbls/d. Production from phase F is expected to start in the third quarter of 2014 with production ramp-up to design capacity expected to take twelve to eighteen months. Production from phases G and H is expected in 2015 and 2016, respectively. We submitted a joint application and EIA to regulators in February 2013 for an additional expansion, phase J, and we anticipate receiving regulatory approval in the first quarter of 2015. With the addition of these four phases, Cenovus

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2013

 

8



 

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 2013, 30 wells using our Wedge WellTM technology were drilled (2012 — no wells) at Foster Creek. At December 31, 2013 there were 65 gross 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 working interest in Christina Lake, an oil sands property in northeastern Alberta that uses SAGD technology and produces from the McMurray formation. Full capacity was reached at phase D in the first quarter of 2013 and phase E had first oil production in the third quarter of 2013. With the addition of phase E, gross production capacity at Christina Lake of 138,000 bbls/d is expected to be achieved in the first quarter of 2014. Phases F, including cogeneration, and G are expected to add approximately 50,000 bbls/d of gross production capacity from each phase. Expansion work is continuing as planned and we expect production from phases F and G in 2016 and 2017, respectively. In the third quarter of 2013, we received regulatory approval for the optimization program at phases C, D and E, which is expected to add up to 22,000 bbls/d of gross capacity in 2015. We submitted a joint application and EIA to regulators in the first quarter of 2013 for the phase H expansion, a 50,000 bbls/d phase for which we expect regulatory approval in the fourth quarter of 2014. With the addition of phases F, G and H, we believe Christina Lake has potential gross production capacity of 288,000 bbls/d, increasing to as much as 310,000 bbls/d with optimization. In 2013, we drilled 11 wells (2012 — three wells) at Christina Lake using our Wedge WellTM technology and at December 31, 2013 there were 10 gross wells of this type producing.

 

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 and select wells on phases D and E. As steam is injected into the injector and producer wells, 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 dilation 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 working interest in Narrows Lake, an oil sands property within the Christina Lake Region in northeastern Alberta. 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. During 2013, site preparation for the phase A plant at Narrows Lake was completed and construction of the plant commenced. Site construction, engineering and procurement, and construction of the phase A plant are progressing as planned. The project is expected to begin producing in 2017.

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2013

 

9



 

New Resource Play Assets

 

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

 

Grand Rapids

 

Our 100 percent owned Grand Rapids property is located in the Greater Pelican Region in northeastern 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 and we anticipate regulatory approval in the first quarter of 2014. During 2013, we continued to operate the pilot project at Grand Rapids and achieved first production from the second well pair in the first quarter of 2013. The purpose of the pilot is to test reservoir performance.

 

Telephone Lake

 

Our 100 percent owned Telephone Lake property is located in the Borealis Region in northeastern Alberta. A revised joint application and EIA was submitted in the fourth quarter of 2011 to the Alberta Energy Regulator (“AER”), formerly the Alberta Energy Resources Conservation Board, and Alberta Environment and Sustainable Resource Development for the development of the property, including the construction of a facility with planned bitumen production capacity of 90,000 bbls/d. We anticipate receiving regulatory approval in the second quarter of 2014. In 2013, we effectively displaced water with compressed air, removing approximately 70 percent of below-ground top water. The water displaced was not potable and therefore not suitable to be used for human or other consumption. Capital investment decreased in 2013 with the completion of drilling and facility construction for the dewatering pilot in the third quarter of 2012.

 

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 2013, 50 gross stratigraphic wells were drilled.

 

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 over 50 percent. In the second and third quarters of 2013, this rig was used to drill 24 stratigraphic wells. We expect to complete construction and testing of a second SkyStratTM drilling rig by the end of the second quarter of 2014.

 

Athabasca Gas

 

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

 

Natural gas production continues to be impacted by the AER’s 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 16 million cubic feet per day in 2013 (2012 - 19 million cubic feet per day). The ADOE provides 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 over a ten year period. This royalty credit is also dependent on natural gas prices. The royalty credit for some of these wells reached the end of the ten year period in the third quarter of 2013.

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2013

 

10



 

Conventional

 

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

 

At December 31, 2013, we had an established land position of approximately 5.4 million gross acres (5.2 million net acres), of which approximately 3.3 million gross acres (3.2 million net acres) are developed. The mineral rights on approximately 61 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 crown lands leased from the Province of Saskatchewan.

 

In 2013, our Conventional capital investment was $1,191 million and primarily focused on crude oil properties. This investment included drilling and facilities work in Weyburn, spending at Pelican Lake on the expansion of the polymer flood as well as drilling, completion and facilities work in our tight oil opportunities in Alberta.

 

Plans for 2014 include oil-focused capital investment to further develop our existing assets in Alberta and Saskatchewan.  The spending will include additional drilling, including infill drilling at Pelican Lake, well optimizations, well recompletions and investment in our existing facility infrastructure.

 

The following table summarizes our landholdings at December 31, 2013:

 

Landholdings – Conventional

 

Developed
Acreage

 

Undeveloped
Acreage

 

Total
Acreage

 

Average
Working

 

(thousands of acres)

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Interest

 

Alberta

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Brooks North

 

571

 

569

 

8

 

8

 

579

 

577

 

100

%

Suffield

 

917

 

906

 

142

 

141

 

1,059

 

1,047

 

99

%

Langevin

 

737

 

697

 

245

 

228

 

982

 

925

 

94

%

Pelican Lake

 

112

 

112

 

360

 

354

 

472

 

466

 

99

%

Drumheller

 

406

 

392

 

76

 

74

 

482

 

466

 

97

%

Wainwright

 

356

 

334

 

204

 

199

 

560

 

533

 

95

%

Other

 

55

 

29

 

167

 

133

 

222

 

162

 

73

%

Saskatchewan

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weyburn

 

116

 

101

 

341

 

320

 

457

 

421

 

92

%

Bakken

 

17

 

16

 

253

 

251

 

270

 

267

 

99

%

Other

 

9

 

6

 

19

 

20

 

28

 

26

 

93

%

Manitoba

 

4

 

4

 

263

 

263

 

267

 

267

 

100

%

Total

 

3,300

 

3,166

 

2,078

 

1,991

 

5,378

 

5,157

 

96

%

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2013

 

11



 

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)

 

2013

 

2012

 

2013

 

2012

 

2013

 

2012

 

Alberta

 

 

 

 

 

 

 

 

 

 

 

 

 

Brooks North

 

3,183

 

2,866

 

205

 

225

 

37,350

 

40,366

 

Suffield

 

11,391

 

11,691

 

149

 

167

 

36,224

 

39,524

 

Langevin

 

8,754

 

7,719

 

101

 

109

 

25,587

 

25,886

 

Pelican Lake

 

24,254

 

22,552

 

 

 

24,254

 

22,552

 

Drumheller

 

4,537

 

3,653

 

47

 

54

 

12,370

 

12,653

 

Wainwright

 

4,668

 

4,417

 

3

 

3

 

5,168

 

4,917

 

Other

 

9

 

11

 

2

 

5

 

342

 

844

 

Saskatchewan

 

 

 

 

 

 

 

 

 

 

 

 

 

Weyburn

 

16,361

 

16,278

 

 

 

16,361

 

16,278

 

Shaunavon(1)

 

2,095

 

4,411

 

 

 

2,095

 

4,411

 

Bakken

 

1,508

 

2,065

 

1

 

1

 

1,676

 

2,232

 

Other

 

15

 

4

 

 

 

15

 

4

 

Total

 

76,775

 

75,667

 

508

 

564

 

161,442

 

169,667

 

 


Note:

(1)  In the third quarter of 2013, our Lower Shaunavon tight oil asset in southern Saskatchewan was sold.

 

The following table summarizes our interests in producing wells at December 31, 2013. These figures exclude wells which were capable of producing, but that were not producing, at December 31, 2013:

 

 

 

Producing
Oil Wells

 

Producing
Gas Wells

 

Total
Producing Wells

 

Producing Wells – Conventional

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Alberta

 

 

 

 

 

 

 

 

 

 

 

 

 

Brooks North

 

168

 

167

 

7,499

 

7,400

 

7,667

 

7,567

 

Suffield

 

795

 

795

 

10,645

 

10,627

 

11,440

 

11,422

 

Langevin

 

271

 

268

 

4,803

 

4,790

 

5,074

 

5,058

 

Pelican Lake

 

567

 

567

 

5

 

5

 

572

 

572

 

Drumheller

 

237

 

231

 

1,584

 

1,527

 

1,821

 

1,758

 

Wainwright

 

463

 

432

 

12

 

3

 

475

 

435

 

Other

 

7

 

1

 

20

 

19

 

27

 

20

 

Saskatchewan

 

 

 

 

 

 

 

 

 

 

 

 

 

Weyburn

 

670

 

423

 

 

 

670

 

423

 

Bakken

 

34

 

23

 

 

 

34

 

23

 

Other

 

5

 

5

 

 

 

5

 

5

 

Total

 

3,217

 

2,912

 

24,568

 

24,371

 

27,785

 

27,283

 

 

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 field in southeastern 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, 2013, approximately 92 percent of the approved CO2 flood pattern development at the Weyburn unit was complete. Since the inception of the project, approximately 22 million tonnes of CO2 have been injected as part of the program. The CO2 is delivered by pipeline directly to the Weyburn facility from

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2013

 

12



 

a coal gasification project in North Dakota, U.S. A new contract was executed in 2012 for the purchase of CO2 from Saskatchewan Power Corporation providing an additional source of CO2 beginning in 2014.

 

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 northeastern Alberta. 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 major pipelines that transport crude oil from northern Alberta to crude oil markets.

 

In 2013, our capital was invested primarily in drilling and facilities work at Weyburn, infill drilling to progress the polymer flood at Pelican Lake, and drilling, completion and facilities work in our tight oil opportunities in Alberta.

 

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

 

 

 

Net

 

Average
Production (bbls/d)

 

 

 

 Wells Drilled

 

Light/Medium

 

Heavy

 

Net Wells Drilled and Production

 

2013

 

2012

 

2013

 

2012

 

2013

 

2012

 

Alberta

 

 

 

 

 

 

 

 

 

 

 

 

 

Brooks North

 

21

 

52

 

3,034

 

2,707

 

 

 

Suffield

 

24

 

38

 

 

 

11,375

 

11,667

 

Langevin

 

36

 

44

 

8,625

 

7,551

 

 

 

Drumheller

 

23

 

33

 

3,970

 

3,051

 

 

 

Wainwright

 

39

 

57

 

40

 

58

 

4,616

 

4,348

 

Pelican Lake

 

49

 

76

 

 

 

24,254

 

22,552

 

Other

 

6

 

2

 

8

 

11

 

 

 

Saskatchewan

 

 

 

 

 

 

 

 

 

 

 

 

 

Weyburn

 

14

 

6

 

16,229

 

16,277

 

 

 

Shaunavon(1)

 

 

36

 

2,095

 

4,411

 

 

 

Bakken

 

 

4

 

1,451

 

2,001

 

 

 

Other

 

 

4

 

15

 

4

 

 

 

Total

 

212

 

352

 

35,467

 

36,071

 

40,245

 

38,567

 

 


Note:

(1)  In the third quarter of 2013, our Lower Shaunavon tight oil asset in southern Saskatchewan was sold.

 

Natural Gas Properties

 

We hold natural gas 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.

 

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

 

2013

 

2012

 

2013

 

2012

 

Brooks North

 

 

 

205

 

225

 

Suffield

 

 

 

149

 

167

 

Langevin

 

 

 

101

 

109

 

Drumheller

 

 

 

47

 

54

 

Wainwright

 

 

 

3

 

3

 

Other

 

 

 

3

 

6

 

Total

 

 

 

508

 

564

 

 

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

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2013

 

13



 

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.

 

Natural gas assets are an important component of our financial foundation, generating operating cash flow well in excess of their ongoing capital investment requirements. The natural gas business also acts as an economic hedge against price fluctuations because natural gas partially 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 2014, on a 100 percent basis, our refineries have a combined stated processing capacity of approximately 460,000 bbls/d of crude oil (2013 — 457,000 bbls/d), including heavy crude oil processing capability of up 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 2013, the Wood River Refinery had stated processing capacity of 311,000 bbls/d. Since the start-up of the CORE project that was substantially completed in 2011, the Wood River Refinery has demonstrated the benefits of this project, including Canadian heavy crude oil processing capability of up to 220,000 bbls/d. In 2013, almost two-thirds of the crude oil processed at the Wood River Refinery consisted of Canadian heavy crude oil, including a significant proportion of high total acid number (“TAN”) crudes.

 

For 2014, the Wood River Refinery’s stated processing capacity is 314,000 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.

 

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 2013 and for 2014, the Borger Refinery’s stated processing capacity is 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.

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2013

 

14



 

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

 

Refinery Operations(1)

 

2013

 

2012

 

Crude Oil Capacity (Mbbls/d)

 

457

 

452

 

Crude Oil Runs (Mbbls/d)

 

442

 

412

 

Heavy Oil

 

222

 

198

 

Light/Medium

 

220

 

214

 

Crude Utilization (%)

 

97

 

91

 

Refined Products (Mbbls/d)

 

 

 

 

 

Gasoline

 

232

 

216

 

Distillates

 

144

 

138

 

Other

 

87

 

79

 

Total

 

463

 

433

 

 


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, 2013.

 

Crude Oil Marketing

 

This group manages the transportation and marketing of crude oil for our upstream operations. Cenovus’s 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, railcar transportation as well as tankage and terminalling of both crude oil blend and condensate volumes.

 

In 2013, in conjunction with the Company’s priority to ensure future market access, we entered into various firm transportation commitments totaling over $11 billion, most of which are subject to regulatory approval. The company’s longer term target is to commit to transportation solutions for up to 50 percent of marketable production, including growing rail capacity by up to 10 percent of marketable production.

 

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 and by North American regional supply and demand for natural gas.

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2013

 

15



 

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 retained 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 CBM reserves. 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 bitumen contingent and prospective resources.

 

The Reserves Committee of our Board of Directors (“Board”), composed of independent directors, 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 independently with Management and each IQRE to determine whether any restrictions affect the ability of the IQRE to report on the reserves data without reservation. In addition, the Reserves Committee reviews the reserves and resources data and the report of the IQRE and provides a recommendation regarding 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 — Operational Risks — Uncertainty of Reserves 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 11, 2014, with an effective date of December 31, 2013. McDaniel’s preparation date of the information is January 13, 2014, and GLJ’s preparation date is January 10, 2014.

 

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 income 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, 2013, 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, 2013

 

16



 

Summary of Company Interest Oil and Gas Reserves at December 31, 2013

(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

 

192

 

129

 

89

 

834

 

Developed Non-Producing

 

25

 

3

 

11

 

27

 

Undeveloped

 

1,629

 

47

 

15

 

4

 

Total Proved Reserves

 

1,846

 

179

 

115

 

865

 

Probable Reserves

 

683

 

140

 

50

 

300

 

Total Proved plus Probable Reserves

 

2,529

 

319

 

165

 

1,165

 

 

After Royalties(2)

 

Reserves Category

 

Bitumen
(MMbbls)

 

Heavy Oil
(MMbbls)

 

Light & Medium
Oil & NGLs
(MMbbls)

 

Natural Gas
& CBM
(Bcf)

 

Proved Reserves

 

 

 

 

 

 

 

 

 

Developed Producing

 

149

 

108

 

78

 

846

 

Developed Non-Producing

 

18

 

3

 

8

 

27

 

Undeveloped

 

1,241

 

40

 

12

 

4

 

Total Proved Reserves

 

1,408

 

151

 

98

 

877

 

Probable Reserves

 

522

 

107

 

42

 

283

 

Total Proved plus Probable Reserves

 

1,930

 

258

 

140

 

1,160

 

 

Royalty Interest

 

Reserves Category

 

Bitumen
(MMbbls)

 

Heavy Oil
(MMbbls)

 

Light & Medium
Oil & NGLs
(MMbbls)

 

Natural Gas
& CBM
(Bcf)

 

Proved Reserves

 

 

 

 

 

 

 

 

 

Developed Producing

 

 

1

 

6

 

42

 

Developed Non-Producing

 

 

 

 

 

Undeveloped

 

 

 

 

 

Total Proved Reserves

 

 

1

 

6

 

42

 

Probable Reserves

 

 

 

2

 

11

 

Total Proved plus Probable Reserves

 

 

1

 

8

 

53

 

 


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, 2013

(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

 

15,530

 

12,761

 

10,868

 

9,514

 

8,498

 

22.81

 

Developed Non-Producing

 

1,467

 

1,042

 

802

 

644

 

536

 

23.84

 

Undeveloped

 

48,111

 

22,625

 

11,899

 

6,710

 

3,915

 

9.20

 

Total Proved Reserves

 

65,108

 

36,428

 

23,569

 

16,868

 

12,949

 

13.07

 

Probable Reserves

 

28,265

 

13,055

 

6,916

 

4,079

 

2,599

 

9.63

 

Total Proved plus Probable Reserves

 

93,373

 

49,483

 

30,485

 

20,947

 

15,548

 

12.09

 

 


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, 2013

 

17



 

After Income Taxes(1)

 

 

 

Discounted at %/year ($ millions)

 

Reserves Category

 

0%

 

5%

 

10%

 

15%

 

20%

 

Proved Reserves

 

 

 

 

 

 

 

 

 

 

 

Developed Producing

 

12,564

 

10,370

 

8,854

 

7,765

 

6,946

 

Developed Non-Producing

 

1,103

 

782

 

603

 

487

 

407

 

Undeveloped

 

36,916

 

17,043

 

8,842

 

4,920

 

2,827

 

Total Proved Reserves

 

50,583

 

28,195

 

18,299

 

13,172

 

10,180

 

Probable Reserves

 

21,448

 

9,785

 

5,105

 

2,966

 

1,864

 

Total Proved plus Probable Reserves

 

72,031

 

37,980

 

23,404

 

16,138

 

12,044

 

 


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, 2013.

 

Total Future Net Revenue (undiscounted) at December 31, 2013

(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

 

169,590

 

37,328

 

48,065

 

17,795

 

1,294

 

65,108

 

14,525

 

50,583

 

Proved plus Probable Reserves

 

243,782

 

54,094

 

68,067

 

26,731

 

1,517

 

93,373

 

21,342

 

72,031

 

 


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, 2013

(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

 

16,758

 

11.90

 

 

 

Heavy Oil

 

2,589

 

17.17

 

 

 

Light & Medium Oil and NGLs

 

2,723

 

27.72

 

 

 

Natural Gas

 

1,499

 

10.25

 

 

 

Total

 

23,569

 

13.07

 

 

 

 

 

 

 

 

 

Proved plus Probable Reserves

 

Bitumen

 

20,760

 

10.76

 

 

 

Heavy Oil

 

4,192

 

16.27

 

 

 

Light & Medium Oil and NGLs

 

3,558

 

25.33

 

 

 

Natural Gas

 

1,975

 

10.21

 

 

 

Total

 

30,485

 

12.09

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2013

 

18



 

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 may be rounded and tables may not add due to rounding.

 

Definitions

 

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

 

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

 

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 our working interest.

 

6.              Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on analysis of drilling, geological, geophysical and engineering data, the use of established technology and specified economic conditions, which are generally accepted as being reasonable, and shall be disclosed.

 

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:

 

·                  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.

 

·                  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., when compared 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.

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2013

 

19



 

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

 

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

 

Pricing Assumptions

 

The forecast price and cost assumptions assume the continuance of current laws and take into account inflation with respect to future operating and capital costs. The forecast prices are provided in the table below and reflect McDaniel’s January 1, 2014 price forecast as referred to in the McDaniel & Associates Consultants Ltd. Summary of Price Forecasts dated January 1, 2014. For historical prices realized during 2013, see “Production History” in this AIF.

 

 

 

 

 

Natural

 

 

 

 

 

 

 

Oil

 

Gas

 

 

 

 

 

 

 

 

 

Edmonton

 

 

 

 

 

 

 

 

 

 

 

 

 

Year

 

WTI
Cushing
Oklahoma
($US/bbl)

 

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)

 

2014

 

95.00

 

95.00

 

89.30

 

67.50

 

76.50

 

4.00

 

2.0

 

0.950

 

2015

 

95.00

 

96.50

 

90.70

 

70.40

 

79.60

 

4.25

 

2.0

 

0.950

 

2016

 

95.00

 

97.50

 

91.70

 

71.20

 

80.40

 

4.55

 

2.0

 

0.950

 

2017

 

95.00

 

98.00

 

92.10

 

71.50

 

80.90

 

4.75

 

2.0

 

0.950

 

2018

 

95.30

 

98.30

 

92.40

 

71.80

 

81.10

 

5.00

 

2.0

 

0.950

 

2019

 

96.60

 

99.60

 

93.60

 

72.70

 

82.20

 

5.25

 

2.0

 

0.950

 

2020

 

98.50

 

101.60

 

95.50

 

74.20

 

83.80

 

5.35

 

2.0

 

0.950

 

2021

 

100.50

 

103.60

 

97.40

 

75.60

 

85.50

 

5.45

 

2.0

 

0.950

 

2022

 

102.50

 

105.70

 

99.40

 

77.20

 

87.20

 

5.55

 

2.0

 

0.950

 

2023

 

104.60

 

107.90

 

101.40

 

78.80

 

89.00

 

5.65

 

2.0

 

0.950

 

2024

 

106.70

 

110.00

 

103.40

 

80.30

 

90.80

 

5.75

 

2.0

 

0.950

 

There-after

 

+2%/yr

 

+2%/yr

 

+2%/yr

 

+2%/yr

 

+2%/yr

 

+2%/yr

 

2.0

 

0.950

 

 

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)

 

2014

 

2015

 

2016

 

2017

 

2018

 

Remainder

 

Total

 

Proved Reserves

 

1,502

 

1,115

 

1,172

 

754

 

1,107

 

12,145

 

17,795

 

Proved plus Probable Reserves

 

1,602

 

1,468

 

1,582

 

1,328

 

1,524

 

19,227

 

26,731

 

 

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, 2013

 

20



 

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, 2013, 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, 2012

 

1,717

 

184

 

115

 

955

 

Extensions and Improved Recovery

 

134

 

21

 

11

 

24

 

Discoveries

 

 

 

 

 

Technical Revisions

 

32

 

(12

)

6

 

76

 

Economic Factors

 

 

 

 

 

Acquisitions

 

 

 

 

 

Dispositions

 

 

 

(5

)

 

Production(1)

 

(37

)

(14

)

(12

)

(190

)

December 31, 2013

 

1,846

 

179

 

115

 

865

 

 

Probable

 

 

 

Bitumen
(MMbbls)

 

Heavy Oil
(MMbbls)

 

Light &
Medium
Oil & NGLs
(MMbbls)

 

Natural
Gas & CBM
(Bcf)

 

December 31, 2012

 

676

 

105

 

56

 

338

 

Extensions and Improved Recovery

 

28

 

55

 

 

5

 

Discoveries

 

78

 

 

 

 

Technical Revisions

 

(99

)

(20

)

(4

)

(43

)

Economic Factors

 

 

 

 

 

Acquisitions

 

 

 

 

 

Dispositions

 

 

 

(2

)

 

Production(1)

 

 

 

 

 

December 31, 2013

 

683

 

140

 

50

 

300

 

 

Proved plus Probable

 

 

 

Bitumen
(MMbbls)

 

Heavy Oil
(MMbbls)

 

Light &
Medium
Oil & NGLs
(MMbbls)

 

Natural
Gas & CBM
(Bcf)

 

December 31, 2012

 

2,393

 

289

 

171

 

1,293

 

Extensions and Improved Recovery

 

162

 

76

 

11

 

29

 

Discoveries

 

78

 

 

 

 

Technical Revisions

 

(67

)

(32

)

2

 

33

 

Economic Factors

 

 

 

 

 

Acquisitions

 

 

 

 

 

Dispositions

 

 

 

(7

)

 

Production(1)

 

(37

)

(14

)

(12

)

(190

)

December 31, 2013

 

2,529

 

319

 

165

 

1,165

 

 


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 FCCL for steam generation, but does not include Royalty Interest Production.

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2013

 

21



 

Proved and proved plus probable bitumen reserves increased by approximately eight and six percent, respectively. Increases at Christina Lake were primarily a result of receiving approval to expand the development area and planned increases to future well density. Increases at Foster Creek were primarily a result of development area expansion.

 

Heavy oil proved reserves decreased by approximately three percent primarily as a result of production exceeding expanded polymer flood and infill drilling areas at Pelican Lake. Heavy oil probable reserves increased by approximately 33 percent also primarily based on expanding pad development using increased well density at Pelican Lake. Overall, heavy oil proved plus probable reserves increased by approximately 10 percent.

 

Light and medium oil and NGLs proved reserves remained unchanged, with production being offset by expanding waterflood and CO2 flood areas and their successful performance at Weyburn. Light and medium oil and NGLs probable reserves decreased by approximately 11 percent primarily as a result of the conversion of probable reserves to proved reserves. Overall, light and medium oil and NGLs proved plus probable reserves decreased by approximately four percent, primarily as a result of additions being offset by production and the Lower Shaunavon disposition.

 

Natural gas proved reserves declined by approximately nine percent as extensions and technical revisions did not offset production. Probable natural gas reserves and proved plus probable natural gas reserves declined by approximately 11 percent and 10 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 50 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

 

1,108

 

1,008

 

60

 

45

 

50

 

27

 

300

 

36

 

2011

 

325

 

1,287

 

13

 

55

 

3

 

25

 

 

24

 

2012

 

284

 

1,532

 

20

 

61

 

3

 

22

 

 

6

 

2013

 

158

 

1,629

 

1

 

47

 

3

 

15

 

 

4

 

 

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

 

804

 

506

 

43

 

37

 

28

 

21

 

54

 

30

 

2011

 

113

 

467

 

14

 

47

 

1

 

22

 

 

35

 

2012

 

182

 

646

 

9

 

42

 

5

 

24

 

 

16

 

2013

 

145

 

649

 

56

 

86

 

1

 

17

 

 

16

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2013

 

22



 

Development of Proved Undeveloped Reserves

 

Bitumen

 

At the end of 2013, we had proved undeveloped bitumen reserves of 1,629 million barrels Before Royalties, or approximately 88 percent of our total proved bitumen reserves. Of our 683 million barrels of probable bitumen reserves, 649 million barrels, or approximately 95 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 in the McMurray formation is a minimum of eight wells per section with 3D seismic, or 16 wells per section with no seismic. In other formations, such as Grand Rapids or Grosmont carbonates, there may be some variation in the standard. 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 45 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 five years, and CO2 flood advancement continuing many years beyond that. At Pelican Lake, investment in proved undeveloped reserves is projected to continue for 25 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

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2013

 

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of the risk factors and uncertainties affecting reserves data, see “Risk Factors — Operational Risks - Uncertainty of Reserves and Future Net Revenue Estimates”.

 

Contingent and Prospective Resources

 

We retain McDaniel to evaluate and prepare reports on all of our contingent and prospective bitumen resources. The evaluations by McDaniel are conducted from the fundamental petrophysical, geological, engineering, financial and accounting data. Processes and procedures are in place to ensure that McDaniel is in receipt of all relevant information. Contingent and prospective resources are estimated using volumetric calculations of the in-place quantities, combined with performance from analog reservoirs. The assets currently producing from the McMurray-Wabiskaw formation at Foster Creek and Christina Lake are used as performance analogs for contingent and prospective resources estimation within these areas. Other regional analogs are used for contingent and prospective resources estimation in the Cretaceous Grand Rapids formation at the 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 vast majority of our bitumen resources will be recovered and produced using SAGD, with only a minor portion of our resources likely to be developed using 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 sub-classified 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 commodity price assumptions that were used for the 2013 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. Technical contingencies include available

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2013

 

24



 

infrastructure and project justification. The outstanding contingencies applicable to our disclosed economic contingent resources do not include economic contingencies.

 

Our bitumen contingent resources are located in four general regions: Foster Creek, Christina Lake, Borealis, and the Greater Pelican Region. At Foster Creek and Christina Lake, we have economic contingent resources located outside the currently approved development project areas. Regulatory approval to expand the development project area is necessary to enable the reclassification of these economic contingent resources as reserves. The timing of these applications is dependent on the rate of development drilling, which ties to an orderly development plan that maximizes utilization of steam generation facilities and ultimately optimizes production, capital utilization and value.

 

In the Borealis Region, we submitted an application for a development project at the Telephone Lake property which, if approved, is expected to enable the reclassification of certain economic contingent resources to reserves. Other areas in the Borealis Region require additional results from delineation drilling and seismic activity to submit regulatory applications for development projects. Stratigraphic test well drilling and seismic activity are continuing in these areas to bring them to project readiness. Currently, sufficient pipeline capacity is also considered a contingency.

 

In the Greater Pelican Region, we submitted an application in the fourth quarter of 2011 for initial development project approval at the Grand Rapids property. We expect to receive regulatory approval in the first quarter of 2014. Pilot project work is underway to examine optimal development strategies.

 

Prospective resources are those quantities of bitumen 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 sub-classified 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 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 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, 2013

 

25



 

Bitumen Economic Contingent and Prospective Resources

 

Company Interest Before Royalties, Billions of Barrels

 

December 31,
2013

 

December 31,
2012

 

Economic Contingent Resources(1)

 

 

 

 

 

Low Estimate

 

7.0

 

7.1

 

Best Estimate

 

9.8

 

9.6

 

High Estimate

 

13.6

 

12.8

 

Prospective Resources(2)

 

 

 

 

 

Low Estimate

 

4.5

 

5.0

 

Best Estimate

 

7.5

 

8.5

 

High Estimate

 

12.6

 

14.8

 

 


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.

 

Bitumen best estimate economic contingent resources increased 0.2 billion barrels or two percent compared to 2012. This increase is primarily a result of stratigraphic test well drilling successfully converting prospective resources to contingent resources, the net acquisition of contingent resources through a property exchange, offset by the reduction of recovery factors at Steepbank and portions of the Grand Rapids formations and the loss of contingent resources due to the cancellation of mineral rights by the Alberta government for future urban development. Refer to “Risk Factors — Environment & Regulatory Risks — Alberta’s Land-Use Framework” for more information.

 

Bitumen best estimate prospective resources declined 1.0 billion barrels or approximately 11 percent compared to 2012, primarily due to stratigraphic drilling, dispositions and cancellation of mineral rights by the Alberta government.

 

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, 2012

 

2.393

 

9.6

 

8.5

 

Transfers between Categories

 

 

 

 

 

 

 

Additions from other resource categories

 

0.113

 

0.4

 

(0.4

)

Reductions to other resource categories

 

 

(0.1

)

 

Additions and Revisions Net of Transfers

 

0.060

 

(0.3

)

(0.3

)

Net Acquisitions and Dispositions

 

 

0.2

 

(0.3

)

Production

 

(0.037

)

 

 

December 31, 2013

 

2.529

 

9.8

 

7.5

 

 


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, the stratigraphic well drilling program in the Steepbank area 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, 2013

 

26



 

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, 2013:

 

Producing Wells(1)(2)

 

 

 

Oil

 

Gas

 

Total

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Alberta

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil Sands

 

338

 

171

 

299

 

299

 

637

 

470

 

Conventional

 

2,508

 

2,461

 

24,568

 

24,371

 

27,076

 

26,832

 

Total Alberta

 

2,846

 

2,632

 

24,867

 

24,670

 

27,713

 

27,302

 

Saskatchewan

 

709

 

451

 

 

 

709

 

451

 

Total

 

3,555

 

3,083

 

24,867

 

24,670

 

28,422

 

27,753

 

 


Notes:

(1)               Cenovus also has varying royalty interests in 9,093 natural gas wells and 3,671 crude oil wells which are producing.

(2)               Includes wells containing multiple completions as follows: 22,455 gross natural gas wells (22,287 net wells) and 1,127 gross crude oil wells (1,002 net wells).

 

Non-Producing Wells(1)

 

 

 

Oil

 

Gas

 

Total

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Alberta

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil Sands

 

47

 

27

 

508

 

432

 

555

 

459

 

Conventional

 

830

 

794

 

768

 

742

 

1,598

 

1,536