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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 40-F

[Check one]
o	REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934
	OR
þ	ANNUAL REPORT PURSUANT TO SECTION 13(a) or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the fiscal year ended: December 31, 2010      Commission File Number:  1-34513

 

CENOVUS ENERGY INC.

(Exact name of Registrant as specified in its charter)

 

Not applicable

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

 

Canada

(Province or other jurisdiction of incorporation or organization)

 

1311

(Primary Standard Industrial

Classification Code Number (if applicable))

 

Not applicable

(I.R.S. Employer

Identification Number (if applicable))

 

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

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

 

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

(212) 894-8641

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

of agent for service in the United States)

 

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

 

 

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

 

None

(Title of Class)

 

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

 

None

(Title of Class)

 

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

 

 

þ Annual information form      þ Audited annual financial statements

 

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report:

 

752,674,701

 

Indicate by check mark whether the Registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to filing requirements for the past 90 days.

 

Yes þ   No o

 

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

 

Yes o   No o

 

The Annual Report on Form 40-F shall be incorporated by reference into or as an exhibit to, as applicable, each of the Registrant’s Registration Statements under the Securities Act of 1933: Form S-8 (File No. 333-163397), Form F-3 (File No. 333-166419), and Form F-9 (File No. 333-167876).

 

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Principal Documents

 

	The following documents have been filed as part of this Annual Report on Form 40-F, beginning on the following page:
	(a)	Annual Information Form of Cenovus Energy Inc. for the fiscal year ended December 31, 2010.
	(b)	Management’s Discussion and Analysis of Cenovus Energy Inc. for the fiscal year ended December 31, 2010.
	(c)	Consolidated Financial Statements of Cenovus Energy Inc. as at December 31, 2010 (Note 24 to the Consolidated Financial Statements relates to United States Generally Accepted Accounting Principles and Reporting (U.S. GAAP)).

 

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CENOVUS ENERGY INC.

 

 

ANNUAL INFORMATION FORM

 

FOR THE YEAR ENDED DECEMBER 31, 2010

 

 

February 24, 2011

 

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2010

 

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TABLE OF CONTENTS

 

FORWARD-LOOKING INFORMATION	1
CORPORATE STRUCTURE	2
GENERAL DEVELOPMENT OF OUR BUSINESS	3
NARRATIVE DESCRIPTION OF OUR BUSINESS	5
Oil Sands	6
Conventional	10
Refining and Marketing	13
RESERVES DATA AND OTHER OIL AND GAS INFORMATION	15
Disclosure of Reserves Data	15
Definitions, Notes to Reserves Data Tables and Pricing Assumptions	18
Future Development Costs	20
Reserves Reconciliation	21
Additional Information Relating to Reserves Data	22
Significant Factors or Uncertainties Affecting Reserves Data	24
Contingent and Prospective Resources	24
Other Oil and Gas Information	27
OTHER INFORMATION	40
Competitive Conditions	40
Environmental Considerations	40
Social and Environmental Policies	40
Employees	41
Foreign Operations	41
DIRECTORS AND EXECUTIVE OFFICERS	42
AUDIT COMMITTEE	47
DESCRIPTION OF CAPITAL STRUCTURE	49
DIVIDENDS	51
MARKET FOR SECURITIES	51
RISK FACTORS	52
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	61
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	62
MATERIAL CONTRACTS	62
INTERESTS OF EXPERTS	62
TRANSFER AGENTS AND REGISTRARS	62
ADDITIONAL INFORMATION	63
ABBREVIATIONS	64
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, 2010

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FORWARD-LOOKING INFORMATION

 

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

 

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

 

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

 

The risk factors and uncertainties that could cause our actual results to differ materially, include: volatility of and assumptions regarding oil and gas prices; the effectiveness of our risk management program, including the impact of derivative financial instruments and our access to various sources of capital; accuracy of cost estimates; fluctuations in commodity prices, currency and interest rates; fluctuations in product supply and demand; market competition, including from alternative energy sources; risks inherent in our marketing operations, including credit risks; maintaining a desirable debt to cash flow ratio; our ability to access external sources of debt and equity capital; success of hedging strategies; accuracy of our reserves, resources and future production estimates; our ability to replace and expand oil and gas reserves; the ability of us and ConocoPhillips to maintain our relationship and to successfully manage and operate our integrated heavy oil business; reliability of our assets; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; refining and marketing margins; potential failure of new products to achieve acceptance in the market; unexpected cost increases or technical difficulties in constructing or modifying manufacturing or refining facilities; unexpected difficulties in manufacturing, transporting or refining of crude oil into petroleum and chemical products at two refineries; risks associated with technology and its application to our business; the timing and the costs of well and pipeline construction; our ability to secure adequate product transportation; changes in Alberta’s regulatory framework, 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 www.cenovus.com.

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2010

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CORPORATE STRUCTURE

 

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

 

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

 

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

 

Intercorporate Relationships

 

The following table summarizes our principal subsidiaries and partnerships at January 1, 2011:

 

Subsidiaries & Partnerships		Percentage Owned (1)		Jurisdiction of Incorporation, Continuance, Formation or Organization
Cenovus FCCL Ltd.		100		Alberta
Cenovus US Refinery Holdings (2)		100		Delaware
FCCL Partnership (“FCCL”) (3)		50		Alberta
WRB Refining LP (“WRB”) (4)		50		Delaware

Notes:

(1)    Includes direct and indirect ownership.

(2)    A Delaware partnership; effective January 1, 2011, received assigned interest from Cenovus Refinery Services LLC.

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

(4)    On December 31, 2010, WRB Refining LLC was converted from a limited liability company to a limited partnership, WRB Refining LP.

 

The above table includes our subsidiaries and partnerships which have total assets that exceed 10 percent of our total consolidated assets, or sales and revenues which exceed 10 percent of our total consolidated sales and revenues. The assets and revenues of our unnamed subsidiaries and partnerships did not exceed 20 percent of our total consolidated assets or total consolidated sales and revenues at and for the year ended December 31, 2010.

 

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GENERAL DEVELOPMENT OF OUR BUSINESS

 

Cenovus is a Canadian oil company headquartered in Calgary, Alberta. Our operations include oil sands properties and established crude oil and natural gas production in Alberta and Saskatchewan. We also have ownership interests in two refineries in Illinois and Texas, U.S.A.

 

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

 

Our Business

 

Our operating and reportable segments are as follows:

 

·            Upstream, which includes Cenovus’s development and production of crude oil, natural gas and NGLs in Canada, is organized into two reportable operations:

 

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

 

o                 Conventional, which includes the development and production of conventional crude oil, natural gas and NGLs in western Canada.

 

·            Refining and Marketing, which is focused on the refining of crude oil products into petroleum and chemical products at two refineries located in the U.S. The refineries are jointly owned with and operated by ConocoPhillips. This segment also markets Cenovus’s crude oil and natural gas, as well as third-party purchases and sales of product that provide operational flexibility for transportation commitments, product type, delivery points and customer diversification.

 

·            Corporate and Eliminations, which primarily includes unrealized gains or losses recorded on derivative financial instruments as well as other Cenovus-wide costs for general and administrative and financing activities. As financial instruments are settled, 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 were changed from those presented in prior periods to better align with our long range business plan. All prior periods have been restated to reflect this presentation.

 

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Three Year History

 

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

 

2010

 

·            At the end of the second quarter, an application for the Narrows Lake project in the Christina Lake Region was submitted to the Energy Resources Conservation Board (“ERCB”) and Alberta Environment. The project is jointly owned with ConocoPhillips and is expected to be developed in two or three phases with a production capacity of 130,000 barrels per day of bitumen.

 

·            In the third quarter of 2010, regulatory approval was received for Foster Creek phases F, G and H. Planned production capacity for each expansion phase is 30,000 barrels per day for a total of 90,000 barrels per day of bitumen.

 

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

 

2009

 

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

 

·            In the second quarter of 2009, a joint regulatory application for Foster Creek phases F, G and H was submitted to the ERCB and Alberta Environment.

 

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

 

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

 

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

 

2008

 

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

 

·            In the third quarter of 2008, the Wood River refinery received regulatory approvals to start construction of the Coker and Refinery Expansion (“CORE”) project. The expansion is expected to more than double heavy crude oil refining capacity to approximately 240,000 barrels per day and increase crude oil refining capacity by 50,000 barrels per day to approximately 356,000 barrels per day.

 

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NARRATIVE DESCRIPTION OF OUR BUSINESS

 

The following map outlines the location of our assets, including our refining assets at December 31, 2010.

 

 

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Overview

 

One hundred percent of our reserves and production are located in Canada. At December 31, 2010, we had a land base of approximately 7.2 million net acres and proved reserves (our share before royalties) of approximately 1,154 million barrels of bitumen, 169 million barrels of heavy oil, 111 million barrels of light and medium oil and NGLs and 1,390 billion cubic feet of natural gas. The estimated proved reserves life index at December 31, 2010 was approximately 18 years. We also had probable reserves (our share before royalties) of approximately 523 million barrels of bitumen, 97 million barrels of heavy oil, 49 million barrels of light and medium oil and NGLs and 410 billion cubic feet of natural gas at December 31, 2010.

 

The following narrative describes our operations in greater detail.

 

Oil Sands

 

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

 

FCCL owns the Foster Creek, Christina Lake and Narrows Lake properties, as well as other bitumen interests. Cenovus FCCL Ltd., our wholly owned subsidiary, is the operating 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 2010, the capital investment of $867 million in our Oil Sands business was primarily related to the expansion of FCCL’s production capacity. FCCL plans to increase production capacity to approximately 218,000 barrels per day of bitumen from the combined facilities at Foster Creek and Christina Lake following the completion of Christina Lake phase C, expected in 2011 and phase D expansion, expected in 2013. In 2010, we received regulatory approval for the next three phases of expansion at Foster Creek, phases F, G and H. Oil Sands also continued to develop our new resource play assets, including the drilling of stratigraphic test wells. In 2010, capital investment for Pelican Lake was primarily related to capital maintenance and polymer injection investment on producing assets.

 

Plans for 2011 include significant capital expenditures on our expansion phases at both Foster Creek and Christina Lake, additional capital investment at our Pelican Lake property, as well as an active stratigraphic test well program in order to enhance our understanding of our new resource play assets and move projects toward the submission of regulatory applications.

 

At December 31, 2010, we held bitumen rights of approximately 1,162,000 gross acres (859,000 net acres) within the Athabasca and Cold Lake areas, as well as the exclusive rights to lease an additional 582,880 net acres on our behalf and/or our assignee’s behalf on the Cold Lake Air Weapons Range.

 

The following table summarizes our landholdings at December 31, 2010.

 

																Average
Landholdings – Oil Sands		Developed				Undeveloped				Total						Working
(thousands of acres)		Gross		Net		Gross		Net		Gross			Net			Interest
Foster Creek		7		4		65		32		72		36				50%
Christina Lake		1		-		24		12		25		12				50%
Pelican Lake		134		133		294		279		428		412				96%
Athabasca		528		448		345		280		873		728				83%
Other		26		12		1,117		852		1,143		864				76%
Total		696		597		1,845		1,455		2,541		2,052				81%

 

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

 

Production – Oil Sands		Crude Oil and NGLs (bbls/d)				Natural Gas (MMcf/d)				Total Production (BOE/d)
(annual average)		2010		2009		2010		2009		2010		2009
Foster Creek		51,147		37,725		-		-		51,147		37,725
Christina Lake		7,898		6,698		-		-		7,898		6,698
Pelican Lake		22,966		24,870		-		-		22,966		24,870
Athabasca		-		-		40		50		6,667		8,333
Other		-		3,057		3		3		500		3,557
Total		82,011		72,350		43		53		89,178		81,183

 

The following table summarizes our interests in producing wells at December 31, 2010. These figures exclude wells which were capable of producing, but that were not producing as of December 31, 2010.

 

Producing Wells – Oil Sands		Producing Oil Wells				Producing Gas Wells				Total Producing Wells
(number of wells)		Gross		Net		Gross		Net		Gross		Net
Foster Creek		183		91		-		-		183		91
Christina Lake		19		10		-		-		19		10
Pelican Lake		448		448		11		11		459		459
Athabasca		-		-		459		436		459		436
Other		-		-		20		20		20		20
Total		650		549		490		467		1,140		1,016

 

Foster Creek

 

We have a 50 percent interest in Foster Creek, an oil sands property which uses steam-assisted gravity drainage (“SAGD”) technology and produces from the McMurray formation. We hold surface access rights from the Governments of Canada and Alberta and bitumen rights from the Government of Alberta for exploration, development and transportation from areas within the Cold Lake Air Weapons Range. In addition, we hold exclusive rights to lease several hundred thousand acres of bitumen rights in other areas on the Cold Lake Air Weapons Range on our behalf and/or our assignee’s behalf.

 

In the first quarter of 2009, two new expansion phases were completed at Foster Creek adding gross production capacity of approximately 60,000 barrels per day of bitumen and increasing total gross production capacity to approximately 120,000 barrels per day of bitumen.

 

In the third quarter of 2010, we received regulatory approval for phases F, G and H which are expected to add approximately 90,000 barrels per day of gross bitumen production capacity.

 

We have successfully piloted and implemented technology at Foster Creek whereby an additional well, a wedge well, is drilled between two producing well pairs to produce bitumen that is heated by proximity to a steam chamber, but is not recoverable by the adjacent production wells. This technology requires minimal additional steam, thus it helps reduce the overall steam-oil ratio. In 2010, we drilled 20 wedge wells (2009 - 18 wells), and at December 31, 2010, there were 33 wedge wells producing.

 

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

 

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Christina Lake

 

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

 

Christina Lake phase C was approximately 88 percent complete at December 31, 2010, on budget and on schedule for first production in the third quarter of 2011. This phase is expected to increase total gross bitumen production capacity to approximately 58,000 barrels per day.

 

We have accelerated the planned completion of phase D by approximately six months and it is expected to be completed in 2013. Regulatory approval for this additional phase was received in 2008.

 

Additionally, we drilled four wedge wells at Christina Lake in 2010, and at December 31, 2010, there was one wedge well producing.

 

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

 

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

 

Pelican Lake

 

Using a pattern, horizontal well polymer flood, we produce heavy oil from the Cretaceous Wabiskaw formation at our Pelican Lake property, which is located within the Greater Pelican Region in northeast Alberta. In 2010, expansion of the facility infrastructure continued in order to accommodate higher total fluid production volumes associated with infill drilling as well as the continued rollout of the polymer injection program. The polymer flood program was expanded by six new injection wells and 11 new production wells in 2010.

 

We hold a 38 percent non-operated interest in a 110-kilometre, 20-inch diameter crude oil pipeline which connects the Pelican Lake area to a major pipeline that transports crude oil from northern Alberta to crude oil markets.

 

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

 

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New Resource Play assets

 

Our new resource play assets include our emerging oil sands properties such as Narrows Lake, Grand Rapids and Telephone Lake.

 

Through our interest in FCCL, we hold an approximate 50 percent interest in the Narrows Lake property, which is located within the Christina Lake Region. In the first quarter of 2010, we initiated the regulatory approval process for Narrows Lake by filing proposed terms of reference for an environmental impact assessment (“EIA”) and began public consultation for the project. In the second quarter of 2010, final terms of reference were issued by Alberta Environment and a joint application and EIA was filed. The project includes gross production capacity of 130,000 barrels per day of bitumen to be added in three phases, with the first phase expected to have production capacity of approximately 40,000 barrels per day of bitumen. The project is expected to begin producing in 2016. Our submitted application includes the option to implement the SAP technology at Narrows Lake which would allow the project to be developed in two phases of 65,000 barrels per day, rather than three phases.

 

Our Grand Rapids project is located in the Greater Pelican Region, where large deposits of bitumen have been identified in the Cretaceous Grand Rapids formation. During the second quarter of 2010, we received approval from the ERCB to begin a pilot project at Grand Rapids. In the fourth quarter of 2010, we received approval from Alberta Environment to start this pilot project. The drilling of a SAGD well pair and construction of associated facilities is complete and steam injection commenced in late 2010. If this pilot is successful, we expect to file a regulatory application by the end of 2011 for a commercial operation with bitumen production capacity of 180,000 barrels per day.

 

Our Telephone Lake property is located in the Borealis Region. A joint application and EIA was submitted in 2007 to the ERCB and Alberta Environment for the development of the property, including the construction of a facility with production capacity of 35,000 barrels per day of bitumen. We plan to file an updated joint application and EIA in the fourth quarter of 2011.

 

Athabasca Gas

 

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

 

Natural gas production continues to be impacted by ERCB decisions made between 2003 and 2009 to shut-in natural gas production from the McMurray, Wabiskaw and Clearwater formations that may put at risk the recovery of bitumen resources in the area. The decisions resulted in a decrease in annualized natural gas production of approximately 23 million cubic feet per day in 2010 (25 million cubic feet per day in 2009). The Government of Alberta’s Department of Energy is providing financial assistance in the form of a royalty credit, which is equal to approximately 50 percent of the cash flow lost as a result of the shut-in wells.

 

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Conventional

 

We have conventional crude oil and natural gas development and production activities in Alberta and Saskatchewan. Conventional also includes the Weyburn carbon dioxide (“CO2”) miscible flood project as well as our emerging Bakken and Shaunavon properties.

 

At December 31, 2010, we had an established land position of approximately 5.4 million gross acres (5.2 million net acres), of which approximately 3.7 million gross acres (3.5 million net acres) are developed. The mineral rights on approximately 60 percent of our net landholdings are owned in fee title by Cenovus, which means that production is subject to a mineral tax that is generally less than the Crown royalty imposed on production from land where the government owns the mineral rights. We may lease out a portion of our fee lands in areas where the land is not consistent with our long range business plan. We lease Crown lands in some areas in Alberta, mainly in the Early Cretaceous geological formations, primarily in the Suffield and Wainwright areas. In Saskatchewan, the majority of our current production comes from lands leased from the Province of Saskatchewan.

 

In 2010, we had capital investment of approximately $523 million and drilled approximately 676 net wells. Of our capital expenditures, 68 percent was oil focused, while 32 percent was natural gas focused.

 

Plans for 2011 include continued drilling, well optimizations, well recompletions (including coalbed methane (“CBM”)) and investment in facility infrastructure necessary for continued development of our assets.

 

The following table summarizes our landholdings at December 31, 2010.

 

														Average
Landholdings – Conventional		Developed				Undeveloped				Total				Working
(thousands of acres)		Gross		Net		Gross		Net		Gross		Net		Interest
Suffield		916		907		89		86		1,005		993		99%
Brooks North		570		568		8		8		578		576		100%
Langevin		761		720		415		399		1,176		1,119		95%
Drumheller		359		348		16		13		375		361		96%
Wainwright		361		336		210		205		571		541		95%
Boyer		594		559		280		235		874		794		91%
Weyburn		100		89		384		364		484		453		94%
Shaunavon / Bakken		3		3		72		71		75		74		99%
Other		3		3		261		261		264		264		100%
Total		3,667		3,533		1,735		1,642		5,402		5,175		96%

 

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

 

		Crude Oil
		and NGLs				Natural Gas				Total Production
Production – Conventional		(bbls/d)				(MMcf/d)				(BOE/d)
(annual average)		2010		2009		2010		2009		2010		2009
Suffield		12,742		13,822		200		223		46,075		50,989
Brooks North		1,637		1,104		240		260		41,637		44,437
Langevin		7,728		8,386		152		181		33,062		38,553
Drumheller		2,109		2,127		72		82		14,109		15,794
Wainwright		4,414		5,589		3		5		4,914		6,422
Boyer		13		13		24		29		4,013		4,846
Weyburn		16,537		17,791		-		-		16,537		17,791
Shaunavon / Bakken		1,996		656		3		4		2,496		1,323
Total		47,176		49,488		694		784		162,843		180,155

 

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The following table summarizes our interests in producing wells at December 31, 2010. These figures exclude wells which were capable of producing, but that were not producing, as of December 31, 2010.

 

		Producing				Producing					Total
Producing Wells – Conventional		Oil Wells				Gas Wells					Producing Wells
(number of wells)		Gross		Net		Gross		Net		Gross			Net
Suffield		741		741		10,705		10,683		11,446			11,424
Brooks North		80		80		7,546		7,417		7,626			7,497
Langevin		244		240		4,856		4,840		5,100			5,080
Drumheller		103		100		1,597		1,540		1,700			1,640
Wainwright		452		417		14		4		466			421
Boyer		6		1		1,152		1,150		1,158			1,151
Weyburn		751		457		-		-		751			457
Shaunavon / Bakken		25		25		-		-		25			25
Total		2,402		2,061		25,870		25,634		28,272			27,695

 

Oil Properties

 

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

 

We have a 62 percent working interest (50 percent economic interest) in the unitized portion of the Weyburn crude oil field in southeast Saskatchewan. The Weyburn unit produces light and medium sour crude from the Mississippian Midale formation and covers 78 sections of land. Cenovus is the operator and we are increasing ultimate recovery of crude oil with a CO2 miscible flood project. At December 31, 2010, approximately 70 percent of the approved CO2 flood pattern development at the Weyburn unit was complete. Since the inception of the project, approximately 16.5 million tonnes of CO2 have been injected as part of the program. The CO2 is delivered by pipeline directly to the Weyburn facility from a coal gasification project in North Dakota.

 

In 2010, we continued evaluating and started developing medium and light oil prospects in the Bakken and lower Shaunavon zones in Saskatchewan, where we drilled 36 wells and increased production to approximately 2,000 barrels per day. Most of the sections of land that we hold in these areas are Crown land.

 

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

 

						Production
Net Wells Drilled and		Net Wells Drilled				Light/Medium (bbls/d)				Heavy Oil (bbls/d)
Production (annual average)		2010		2009		2010		2009		2010		2009
Suffield		43		40		-		-		12,717		13,798
Brooks North		41		18		1,458		894		-		-
Langevin		22		14		7,529		8,160		-		-
Drumheller		30		28		1,403		1,421		-		-
Wainwright		3		-		452		1,472		3,942		4,090
Boyer		-		-		12		12		-		-
Weyburn		3		-		16,534		17,784		-		-
Shaunavon / Bakken		36		5		1,958		651		-		-
Other		2		-		-		-		-		-
Total		180		105		29,346		30,394		16,659		17,888

 

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Natural Gas Properties

 

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

 

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

 

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

 

Net Wells Drilled and		Net Wells Drilled				Gas Production (MMcf/d)
Production (annual average)		2010		2009		2010		2009
Suffield		292		170		200		223
Brooks North		149		163		240		260
Langevin		24		109		152		181
Drumheller		29		56		72		82
Other		1		4		30		38
Total		495		502		694		784

 

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

 

Included in the Brooks North and Langevin areas is the Belly River Cretaceous formation where Cenovus is producing CBM. In 2010, approximately 900 wells were recompleted which added approximately 17 million cubic feet per day of natural gas production by the end of the year. The CBM assets are long-life and low decline and are expected to generate production for future growth in a capital efficient manner.

 

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Refining and Marketing

 

Refining

 

Through WRB Refining LP (“WRB”) we have a 50 percent interest in both the Wood River and Borger Refineries located in Roxana, Illinois and Borger, Texas respectively. ConocoPhillips is the operator and manager of WRB. WRB has a management committee, which is composed of three Cenovus representatives and three ConocoPhillips representatives, with each company holding equal voting rights.

 

At December 31, 2010, WRB had processing capability to refine approximately 452,000 barrels per day of crude oil. With the completion of the CORE project, the Wood River Refinery will have the ability to process a wider variety of heavy crude oil feedstocks. Our two refineries will then have a combined capacity to process as much as 275,000 barrels per day of heavy crude oil.

 

Wood River Refinery

 

At December 31, 2010, the Wood River refinery had a processing capacity of approximately 306,000 barrels per day of crude oil. It processes light, low-sulphur and heavy, high-sulphur crude oil that it receives from North American crude oil pipelines to produce gasoline, diesel and jet fuel, petrochemical feedstocks and asphalt. The gasoline and diesel are transported via pipelines to markets in the upper Midwest. Other products are transported via pipeline, truck, barge and railcar to markets in the U.S. Midwest. In 2007, the refinery completed the construction of a proprietary sulphur removal unit that produces low-sulphur gasoline. In September 2008, regulatory approval was received to proceed with the construction of the CORE project at Wood River. At December 31, 2010, the CORE project was approximately 91 percent complete. Commissioning of several of the process units has been completed with an expected coker start up in the fourth quarter of 2011. At the time of coker start up, we expect that CORE expenditures will reach approximately US$3.7 billion (US$1.85 billion net to Cenovus). The total estimated cost of the CORE project is expected to be approximately US$3.9 billion (US$1.95 billion net to Cenovus), or about 10 percent higher than originally forecast. The expansion is expected to increase crude oil refining capacity by 50,000 barrels per day to 356,000 barrels per day and more than double heavy crude oil refining capacity at Wood River to 240,000 barrels per day.

 

Borger Refinery

 

At December 31, 2010, the Borger refinery had a processing capacity of approximately 146,000 barrels per day of crude oil, including approximately 35,000 barrels per day of heavy crude oil, and approximately 45,000 barrels per day of NGLs. It processes mainly medium, high-sulphur and heavy, high-sulphur crude oil and NGLs that it receives from North American pipeline systems to produce gasoline, diesel and jet fuel along with NGLs and solvents. The refined products are transported via pipelines to markets in Texas, New Mexico, Colorado and the U.S. Mid-Continent. In July 2007, a new coker with a capacity of approximately 25,000 barrels per day was brought into service along with a new vacuum unit and revamped gas, oil and distillate hydrotreaters. This project has enabled the refinery to process heavy oil blends, particularly Canadian heavy oil, and comply with clean fuel regulations for ultra-low sulphur diesel and low-sulphur gasoline. The project has also enabled compliance with required reductions of sulphur dioxide and other air emissions.

 

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

 

Refinery Operations(1)		2010		2009
Crude Oil Capacity (Mbbls/d)		452		452
Crude Oil Runs (Mbbls/d)		386		394
Crude Utilization (%)		86		87
Refined Products (Mbbls/d)
Gasoline		204		223
Distillates		123		120
Other		78		74
Total		405		417

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 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 those 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, 2010.

 

Crude Oil Marketing

 

We manage the transportation and marketing of crude oil for our upstream operations. Our objective is to sell production to achieve the best price within the constraints of a diverse sales portfolio, as well as to obtain and manage condensate supply, inventory and storage to meet diluent requirements. During 2010, our blend volumes (which include diluent added to create a product suitable for pipeline transportation) marketed on behalf of FCCL were 163,472 barrels per day (2009 - 120,894 barrels per day), while our wholly-owned blend, light and medium crude oil volumes marketed were 73,238 barrels per day (2009 - 78,303 barrels per day).

 

Natural Gas Marketing

 

Our natural gas is primarily marketed to industrials, other producers and energy marketing companies. In 2010, approximately 20 percent of our sales of natural gas were directly marketed by us to industrials (2009 – approximately 25 percent). The remaining 80 percent of sales of natural gas were marketed to other producers and energy marketing companies (2009 – approximately 75 percent). Prices received by us are based primarily upon prevailing index prices for natural gas. Prices are impacted by competing fuels in such markets and by North American regional supply and demand for natural gas.

 

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RESERVES 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”). Prior to the year ended December 31, 2010, we presented our reserves estimates in accordance with U.S. disclosure requirements pursuant to an exemption from certain of the NI 51-101 requirements. The exemption expired at the end of 2010. As a result, reserves information for the year ending December 31, 2009 is presented as previously disclosed, using 2009 12 month average constant prices and costs as prescribed by the U.S. Securities and Exchange Commission (“SEC”), and has also been restated to comply with NI 51-101, using McDaniel & Associates Consultants Ltd. (“McDaniel”) January 1, 2010 forecast prices and costs, consistent with the presentation format for December 31, 2010 reserves disclosures, which use McDaniel January 1, 2011 forecast prices and costs. The reserves, contingent resources and prospective resources information provided herein conforms with the disclosure requirements of NI 51-101.

 

We retain two independent qualified reserves evaluators (“IQREs”), 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 annually. McDaniel evaluated approximately 93 percent of our total proved reserves, located throughout Alberta and Saskatchewan, and GLJ evaluated approximately seven percent of our total proved reserves, located at Boyer and Weyburn. We also engaged McDaniel to evaluate 100 percent of our contingent and prospective bitumen resources.

 

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

 

The company’s reserves are located in Alberta and Saskatchewan, Canada. 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 “Definitions, Notes to Reserves Data Tables and Pricing Assumptions” in conjunction with the disclosure in this statement. The estimates of bitumen, light and medium oil, heavy oil, NGLs, natural gas and CBM reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates disclosed. See “Risk Factors – Uncertainty of Reserves, Resources and Future Net Revenue Estimates” in this AIF for additional information.

 

This reserves data and other oil and gas information contained in this AIF is dated February 16, 2011, with an effective date of December 31, 2010. McDaniel’s preparation date of the information is February 16, 2011, and GLJ’s preparation date is January 26, 2011.

 

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, cost associated with environmental regulations, the impact of any hedging activities or the liability associated with certain abandonment and all well, pipeline, facilities and reclamation costs. Future net revenues have been presented on a before and after tax basis.

 

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We hold significant freehold title rights which generate production for our account from third parties leasing those lands (“Royalty Interest production”). The Before Royalty volumes presented do not include reserves (“Royalty Interest reserves”) associated with this Royalty Interest production. The After Royalty volumes presented include our Royalty Interest reserves. See “Definitions, Notes to Reserves Tables Data, and Pricing Assumptions” below for further information on our Royalty Interests.

 

Summary of Oil and Gas Reserves at December 31, 2010

(Forecast Prices and Costs)

 

Company Interest Before Royalties(1)

 

Reserves Category		Bitumen (MMbbls)		Heavy Oil (MMbbls)		Light & Medium Oil & NGLs (MMbbls)		Natural Gas & CBM (Bcf)
Proved Reserves
Developed Producing		126		111		79		1,292
Developed Non-Producing		20		13		5		62
Undeveloped		1,008		45		27		36
Total Proved Reserves		1,154		169		111		1,390
Probable Reserves		523		97		49		410
Total Proved plus Probable Reserves		1,677		266		160		1,800

Note:

(1)  Does not include Royalty Interest reserves associated with Royalty Interest production received by Cenovus.

 

Bitumen accounts for approximately 69 percent of our proved reserves Before Royalties, heavy oil accounts for approximately 10 percent, light and medium oil and NGLs account for approximately seven percent, and natural gas and CBM for approximately 14 percent. Before Royalties, approximately 87 percent of Cenovus’s proved bitumen reserves are undeveloped. The distinction between developed and undeveloped bitumen reserves, and the strategy for their development, is described further under “Undeveloped Reserves”.

 

Company Interest After Royalties(1)

 

Reserves Category		Bitumen (MMbbls)		Heavy Oil (MMbbls)		Light & Medium Oil & NGLs (MMbbls)		Natural Gas & CBM (Bcf)
Proved Reserves
Developed Producing		96		92		67		1,292
Developed Non-Producing		14		10		4		61
Undeveloped		760		36		21		36
Total Proved Reserves		870		138		92		1,389
Probable Reserves		404		72		39		391
Total Proved plus Probable Reserves		1,274		210		131		1,780

Note:

(1)  Includes Royalty Interest reserves associated with Royalty Interest production received by Cenovus.

 

After Royalties, bitumen accounts for approximately 65 percent of our proved reserves, heavy oil accounts for approximately 10 percent, light and medium oil and NGLs account for approximately seven percent, and natural gas and CBM for approximately 18 percent. In the presented After Royalties reserves, Royalty Interest reserves constitute approximately three percent of natural gas, approximately five percent of light and medium oil and NGL reserves, and approximately one percent of heavy oil reserves. We have no bitumen Royalty Interest reserves.

 

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Summary of Net Present Value of Future Net Revenue at December 31, 2010

(Forecast Prices and Costs)

 

		Before Income Taxes Discounted at %/year ($ millions)													Unit Value Before Income Tax Discounted at 10%(1)
Reserves Category		0%		5%		10%		15%		20%					$/BOE
Proved Reserves
Developed Producing		16,118		12,796		10,619		9,102		7,986					22.60
Developed Non-Producing		1,423		888		604		435		325					15.53
Undeveloped		36,936		13,789		6,302		3,300		1,872					7.66
Total Proved Reserves		54,477		27,473		17,525		12,837		10,183					13.16
Probable Reserves		21,163		12,192		6,879		4,031		2,466					11.84
Total Proved plus Probable Reserves		75,640		39,665		24,404		16,868		12,649					12.76

Note:

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

 

		After Income Taxes(1) Discounted at %/year ($ millions)
Reserves Category		0%		5%		10%		15%		20%
Proved Reserves
Developed Producing		12,683		10,153		8,480		7,308		6,443
Developed Non-Producing		1,070		666		454		328		245
Undeveloped		27,637		10,359		4,720		2,442		1,349
Total Proved Reserves		41,390		21,178		13,654		10,078		8,037
Probable Reserves		15,783		9,073		5,076		2,923		1,737
Total Proved plus Probable Reserves		57,173		30,251		18,730		13,001		9,774

 

Note:

(1)  After income tax values are calculated by considering the Company’s existing tax pools

 

Total Future Net Revenue (undiscounted) at December 31, 2010

(Forecast Prices and Costs) ($ millions)

 

Reserves Category		Revenue		Royalties		Operating Costs		Development Costs		Abandonment Costs (1)		Future Net Revenue Before Income Taxes		Income Taxes		Future Net Revenue After Income Taxes
Proved Reserves		132,911		29,190		38,802		9,414		1,028		54,477		13,087		41,390
Proved plus Probable Reserves		186,276		40,718		53,511		15,234		1,173		75,640		18,467		57,173

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.

 

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Future Net Revenue by Production Group at December 31, 2010

(Forecast Prices and Costs)

 

Notes:

(1)  Including solution gas and other by-products

(2)  Including by-products, but excluding solution gas from oil wells

 

 

Definitions, Notes to Reserves Data Tables and Pricing Assumptions

 

The following pricing assumptions, definitions and notes are applicable to the disclosure in this AIF. For definitions in relation to our contingent and prospective resources disclosure, see “Contingent and Prospective Resources” below.

 

Definitions

 

1.              After Royalties means volumes after deduction of royalties and including any royalty interests.

 

2.              Before Royalties means volumes before deduction of royalties and excluding any royalty interests.

 

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

 

4.              Gross means:

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

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

 

5.              Net means:

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

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

 

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

 

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

 

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

 

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·                   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 (proved and probable) 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 into producing and non-producing.

 

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

 

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

 

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

 

7.              Royalty Interest means:

(a)         in relation to reserves, those reserves related to our royalty entitlement on lands to which we hold freehold title which have been leased to third parties, or reserves related to other royalty interests, such as overriding royalties to which we are entitled.

(b)         in relation to production, the production generated for Cenovus’s account pursuant to leasing agreements of our freehold title lands, and other royalty entitlement agreements.

 

Notes to Reserves Data Tables

 

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

 

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

 

·                   Only estimated future well abandonment costs related to reserves wells have been taken into account by the IQREs in determining the aggregate future net revenue therefrom. Further, 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 from reserves excludes cash flows related to our risk management activities.

 

Cenovus Energy Inc. Annual Information Form for the year ended December 31, 2010

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Table of Contents

 

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, 2011 price forecast as referred to in the McDaniel & Associates Consultants Ltd. Summary of Price Forecasts dated January 1, 2011.

 

 

 

Future Development Costs

 

The following table outlines development costs deducted in the estimation of future net revenue calculated utilizing forecast prices and costs, undiscounted and using a discount rate of 10 percent per annum for the years indicated.

 

Reserves Category ($ millions)	2011	2012	2013	2014	2015	Remainder	Total Undiscounted	Total Discounted at 10%
Proved Reserves	790	745	436	327	195	6,921	9,414	3,388
Proved plus Probable Reserves	1,080	1,258	1,106	921	710	10,159	15,234	6,680

 

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 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, 2010

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