United States

Securities and Exchange Commission
Washington, D.C. 20549

FORM 40-F

[    ] Registration Statement pursuant to section 12 of the Securities Exchange Act of 1934

[ 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, 2015

Commission File Number: 333-12138

CANADIAN NATURAL RESOURCES LIMITED (Exact name of Registrant as specified in its charter)

ALBERTA, CANADA (Province or other jurisdiction of incorporation or organization)

1311 (Primary Standard Industrial Classification Code Numbers)

Not Applicable (I.R.S. Employer Identification Number (if applicable))

2100, 855-2nd Street S.W., Calgary, Alberta, Canada, T2P 4J8 Telephone: (403) 517-7345 (Address and telephone number of Registrant’s principal executive offices)

CT Corporation System, 111-Eighth Avenue, New York, New York 10011 (212) 894-8940 (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 for which there is a reporting obligation pursuant to Section 15(d) of the Act:  None

For annual reports, indicate by check mark the information filed with this Form:

[ X ] Annual information form

[ X ] Audited annual financial statements

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.

1,094,667,814 Common Shares outstanding as of December 31, 2015

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

Yes [X]

No [  ]

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 (s.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).

 

This Annual Report on Form 40-F shall be incorporated by reference into, or as an exhibit to, as applicable, the Registrant’s Registration Statement on Form F-10 (File No. 333-207578) under the Securities Act of 1933 as amended.

All dollar amounts in this Annual Report on Form 40-F are expressed in Canadian dollars.  On March 22, 2016 the reported Bank of Canada noon rate for one Canadian dollar was US$0.7662. On March 22, 2016 the reported Bank of Canada noon rate for one U. S. dollar was C$1.3051.

The following documents have been filed as part of this Annual Report on Form 40-F, starting on the following page:

A.

Annual Information Form

B.

Audited Annual Financial Statements

C.

Management’s Discussion and Analysis

Supplementary Oil & Gas Information

For Canadian Natural’s Supplementary Oil & Gas Information for the year ended December 31, 2015, see Exhibit 99.1 to this Annual Report on Form 40-F.

 

 

ANNUAL INFORMATION FORM

FOR THE YEAR ENDED DECEMBER 31, 2015

 

March 24, 2016

 

 

 

 

 

 

TABLE OF CONTENTS

DEFINITIONS AND ABBREVIATIONS	3
SPECIAL NOTES REGARDING FORWARD-LOOKING STATEMENTS	5
CORPORATE STRUCTURE	7
GENERAL DEVELOPMENT OF THE BUSINESS	8
DESCRIPTION OF THE BUSINESS	9
A.   ENVIRONMENTAL MATTERS	10
B.   REGULATORY MATTERS	11
C.   COMPETITIVE FACTORS	13
D.   RISK FACTORS	13
FORM 51-101F1 STATEMENT OF RESERVES DATA AND OTHER INFORMATION	17
SELECTED FINANCIAL INFORMATION	47
DIVIDEND HISTORY	47
DESCRIPTION OF CAPITAL STRUCTURE	47
MARKET FOR CANADIAN NATURAL RESOURCES LIMITED SECURITIES	49
DIRECTORS AND OFFICERS	50
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	56
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	56
TRANSFER AGENTS AND REGISTRAR	57
MATERIAL CONTRACTS	57
INTERESTS OF EXPERTS	57
AUDIT COMMITTEE INFORMATION	57
ADDITIONAL INFORMATION	58
SCHEDULE “A” FORM 51-101F2 REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR	59
SCHEDULE “B” FORM 51-101F3 REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE	61
SCHEDULE “C” CHARTER OF THE AUDIT COMMITTEE	63

 

 

 

2	Canadian Natural Resources Limited

DEFINITIONS AND ABBREVIATIONS

The following are definitions and selected abbreviations used in this Annual Information Form:

API	Specific gravity measured in degrees on the American Petroleum Institute scale
ARO	Asset retirement obligations
bbl	barrel
bbl/d	barrels per day
Bcf	billion cubic feet
BOE	barrels of oil equivalent
BOE/d	barrels of oil equivalent per day
“Canadian Natural Resources Limited”, “Canadian Natural”, “Company”, “Corporation”	Canadian Natural Resources Limited and includes, where applicable, reference to subsidiaries of and partnership interests held by Canadian Natural Resources Limited and its subsidiaries
CBM	Coal Bed Methane
CO2	Carbon dioxide
CO2e	Carbon dioxide equivalents
Crude oil, natural gas and NGLs	The Company’s light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, synthetic crude oil, bitumen (thermal oil), natural gas and natural gas liquids
CSS	Cyclic Steam Simulation
development well	Well drilled inside the established limits of an oil or gas reservoir or in close proximity to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive
dry well	Well that proves to be incapable of producing either crude oil or natural gas in sufficient quantities to justify completion
EOR	Enhanced Oil Recovery
exploratory well	Well that is not a development well, a service well, or a stratigraphic test well
extension well	Well that is drilled to test if a known reservoir extends beyond what had previously been believed to be the outer reservoir perimeter
fee title interest	Absolute ownership of legal title to mineral lands, subject to conditional interests that may have been granted from the title, such as petroleum and natural gas leases
FPSO	Floating Production, Storage and Offloading vessel
GHG	Greenhouse gas
gross acres	Total number of acres in which the Company has a working interest or fee title interest
gross wells	Total number of wells in which the Company has a working interest
Horizon	Horizon Oil Sands
IFRS	International Financial Reporting Standards
Mbbl	thousand barrels
Mcf	thousand cubic feet
Mcf/d	thousand cubic feet per day
MD&A	Management’s Discussion and Analysis
MMbbl	million barrels
MMBOE	million barrels of oil equivalent
MMBtu	million British thermal units
MMcf	million cubic feet
MMcf/d	million cubic feet per day

 

 

Canadian Natural Resources Limited

3

 

MM$	million Canadian dollars
NGLs	Natural gas liquids
net acres	Gross acres multiplied by the percentage working interest or fee title interest therein owned
net asset value	Calculated as net present value, discounted at 10%, of the future net revenue (before income tax and excluding the ARO for development existing as at December 31, 2015) of the Company’s total proved plus probable crude oil, natural gas and NGLs reserves prepared using forecast prices and costs, plus the estimated market value of core unproved property, less net debt.  Net debt is long term debt plus/minus the working capital deficit/surplus.  Future development costs and abandonment and reclamation costs attributable to future development activity have been applied against the future net revenue
net wells	Gross wells multiplied by the percentage working interest therein owned by the Company
NYSE	New York Stock Exchange
productive well	Exploratory, development or extension well that is not dry
proved property	Property or part of a property to which reserves have been specifically attributed
PRT	Petroleum Revenue Tax
SAGD	Steam-Assisted Gravity Drainage
SCO	Synthetic crude oil
SEC	United States Securities and Exchange Commission
service well	Well drilled or completed for the purpose of supporting production in an existing field and drilled for the specific purposes of gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for combustion
stratigraphic test well	Drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition and ordinarily drilled without the intention of being completed for hydrocarbon production
TSX	Toronto Stock Exchange
UK	United Kingdom
unproved property	Property or part of a property to which no reserves have been specifically attributed
US	United States
working interest	Interest held by the Company in a crude oil or natural gas property, which interest normally bears its proportionate share of the costs of exploration, development, and operation as well as any royalties or other production burdens
WTI	West Texas Intermediate reference location at Cushing, Oklahoma

 

 

 

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements relating to Canadian Natural Resources Limited (the “Company”) in this document or documents incorporated herein by reference constitute forward-looking statements or information (collectively referred to herein as “forward-looking statements”) within the meaning of applicable securities legislation. Forward-looking statements can be identified by the words “believe”, “anticipate”, “expect”, “plan”, “estimate”, “target”, “continue”, “could”, “intend”, “may”, “potential”, “predict”, “should”, “will”, “objective”, “project”, “forecast”, “goal”, “guidance”, “outlook”, “effort”, “seeks”, “schedule”, “proposed” or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to expected future commodity pricing, forecast or anticipated production volumes, royalties, operating costs, capital expenditures, income tax expenses, and other guidance provided throughout this Annual Information Form (“AIF”) constitute forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including but not limited to the Horizon Oil Sands operations and future expansions, Primrose thermal projects, Pelican Lake water and polymer flood project, the Kirby Thermal Oil Sands Project, the construction and future operations of the North West Redwater bitumen upgrader and refinery, construction by third parties of new or expansion of existing pipeline capacity or other means of transportation of bitumen, crude oil, natural gas or SCO that the Company may be reliant upon to transport its products to market and reference to the 2016 activity provided also constitute forward-looking statements. This forward-looking information is based on annual budgets and multi-year forecasts, and is reviewed and revised throughout the year as necessary in the context of targeted financial ratios, project returns, product pricing expectations and balance in project risk and time horizons. These statements are not guarantees of future performance and are subject to certain risks. The reader should not place undue reliance on these forward-looking statements as there can be no assurances that the plans, initiatives or expectations upon which they are based will occur.

In addition, statements relating to “reserves” are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of proved and proved plus probable crude oil, natural gas and NGLs reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserve and production estimates.

The forward-looking statements are based on current expectations, estimates and projections about the Company and the industry in which the Company operates, which speak only as of the date such statements were made or as of the date of the report or document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such risks and uncertainties include, among others: general economic and business conditions which will, among other things, impact demand for and market prices of the Company’s products; volatility of and assumptions regarding crude oil and natural gas prices; fluctuations in currency and interest rates; assumptions on which the Company’s current guidance is based; economic conditions in the countries and regions in which the Company conducts business; political uncertainty, including actions of or against terrorists, insurgent groups or other conflict including conflict between states; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; impact of competition; the Company’s defense of lawsuits; availability and cost of seismic, drilling and other equipment; ability of the Company and its subsidiaries to complete capital programs; the Company’s and its subsidiaries’ ability to secure adequate transportation for its products; unexpected disruptions or delays in the resumption of the mining, extracting or upgrading of the Company’s bitumen products; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; ability of the Company to attract the necessary labour required to build its thermal and oil sands mining projects; operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas and in mining, extracting or upgrading the Company’s bitumen products; availability and cost of financing; the Company’s and its subsidiaries’ success of exploration and development activities and its ability to replace and expand crude oil and natural gas reserves; timing and success of integrating the business and operations of acquired companies; production levels; imprecision of reserve estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs not currently classified as proved; actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations and the impact of climate change initiatives on capital and operating costs); asset retirement obligations; the adequacy of the Company’s provision for taxes; and other circumstances affecting revenues and expenses.

The Company’s operations have been, and in the future may be, affected by political developments and by federal, provincial and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations. Should one or more of these risks or uncertainties materialize, or should any of the Company’s assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors,

 

and the Company’s course of action would depend upon its assessment of the future considering all information then available. For additional information refer to the “Risks Factors” section of this AIF.

Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed in this AIF could also have material adverse effects on forward-looking statements. Although the Company believes that the expectations conveyed by the forward-looking statements are reasonable based on information available to it on the date such forward-looking statements are made, no assurances can be given as to future results, levels of activity and achievements. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Except as required by law, the Company assumes no obligation to update forward-looking statements, whether as a result of new information, future events or other factors, or the foregoing factors affecting this information, should circumstances or Management’s estimates or opinions change.

Special Note Regarding Currency, Financial Information, Production and Reserves

In this document, all references to dollars refer to Canadian dollars unless otherwise stated. Reserves and production data are presented on a before royalties basis unless otherwise stated. In addition, reference is made to crude oil and natural gas in common units called barrel of oil equivalent ("BOE"). A BOE is derived by converting six thousand cubic feet of natural gas to one barrel of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.  In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value.

The comparative Consolidated Financial Statements and the Company’s MD&A for the most recently completed fiscal year ended December 31, 2015, herein incorporated by reference, and certain information included in this AIF, have been prepared in accordance with IFRS, as issued by the International Accounting Standards Board.

For the year ended December 31, 2015, the Company retained Independent Qualified Reserves Evaluators (“IQRE”), Sproule Associates Limited and Sproule International Limited (together as “Sproule”) and GLJ Petroleum Consultants Ltd. (“GLJ”), to evaluate and review all of the Company’s proved and proved plus probable reserves with an effective date of December 31, 2015 and a preparation date of February 1, 2016.  Sproule evaluated the North America and International light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), natural gas and NGLs reserves.  GLJ evaluated the Horizon SCO reserves.  The evaluation and review was conducted in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and disclosed in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) requirements.

The Company annually discloses net proved reserves and the standardized measure of discounted future net cash flows using 12-month average prices and current costs in accordance with United States Financial Accounting Standards Board Topic 932 “Extractive Activities - Oil and Gas” in the Company’s annual report on Form 40-F filed with the SEC in the “Supplementary Oil and Gas Information” section of the Company’s Annual Report on pages 92 to 99 which is incorporated herein by reference.

Special Note Regarding Non GAAP Financial Measures

This AIF includes references to financial measures commonly used in the crude oil and natural gas industry, such as adjusted net earnings from operations, cash flow from operations, adjusted cash production costs, and net asset value. These financial measures are not defined by IFRS and therefore are referred to as non-GAAP measures. The non-GAAP measures used by the Company may not be comparable to similar measures presented by other companies. The Company uses these non-GAAP measures to evaluate its performance. The non-GAAP measures should not be considered an alternative to or more meaningful than net earnings, as determined in accordance with IFRS, as an indication of the Company’s performance. The non-GAAP measures adjusted net earnings from operations and cash flow from operations are reconciled to net earnings (loss), as determined in accordance with IFRS in the “Net Earnings (Loss) and Cash Flow from Operations” section of the Company’s MD&A which is incorporated by reference into this document.  The derivation of adjusted cash production costs is included in the “Operating Highlights – Oil Sands Mining and Upgrading” section of the Company’s MD&A which is incorporated by reference into this document.

 

CORPORATE STRUCTURE

Canadian Natural Resources Limited was incorporated under the laws of the Province of British Columbia on November 7, 1973 as AEX Minerals Corporation (N.P.L.) and on December 5, 1975 changed its name to Canadian Natural Resources Limited. Canadian Natural was continued under the Companies Act of Alberta on January 6, 1982 and was further continued under the Business Corporations Act (Alberta) on November 6, 1985. The head, principal and registered office of the Company is located in Calgary, Alberta, Canada at 2100, 855 - 2nd Street S.W., T2P 4J8.

The Company has amalgamated pursuant to the Business Corporations Act (Alberta) under the name Canadian Natural Resources Limited with the following:

October 1, 2000 - Ranger Oil Limited (“Ranger”)

January 1, 2003 - Rio Alto Exploration Ltd. (“RAX”)

January 1, 2004 - CanNat Resources Inc.

January 1, 2007 - ACC-CNR Resources Corporation

January 1, 2008 - Ranger Oil (International) Ltd.; 764968 Alberta Inc.; CNR International (Norway) Limited; Renata Resources Inc.

January 1, 2012 - Aspect Energy Ltd.; Creo Energy Ltd.; 1585024 Alberta Ltd.

January 1, 2014 - Barrick Energy Inc.

January 1, 2015 - EOG Resources Canada Inc.

The main operating subsidiaries and partnerships of the Company, percentage of voting securities owned either directly or indirectly, and their jurisdictions of incorporation are as follows:

Jurisdiction of Incorporation			% Ownership
Subsidiary
Canadian Natural Upgrading Limited	Alberta			100
CanNat Energy Inc.	Delaware			100
CNR (ECHO) Resources Inc.	Alberta			100
CNR International (U.K.) Investments Limited	England			100
CNR International (U.K.) Limited	England			100
CNR International (Côte d’Ivoire) SARL	Côte d’Ivoire			100
CNR International (Olowi) Limited	Bahamas			100
CNR International (South Africa) Limited	Alberta			100
Horizon Construction Management Ltd.	Alberta			100
Partnership
Canadian Natural Resources	Alberta			100
Canadian Natural Resources Northern Alberta Partnership	Alberta			100
Canadian Natural Resources 2005 Partnership	Alberta			100

Canadian Natural, as the managing partner, CNR (ECHO) Resources Inc. and Canadian Natural Resources 2005 Partnership are the partners of Canadian Natural Resources, a general partnership. Canadian Natural, as the managing partner, CNR (ECHO) Resources Inc., Canadian Natural Resources and Canadian Natural Resources 2005 Partnership are partners of Canadian Natural Resources Northern Alberta Partnership, a general partnership. Canadian Natural, as the managing partner, and CNR (ECHO) Resources Inc. are the partners of Canadian Natural Resources 2005 Partnership, a general partnership.

In the ordinary course of business, Canadian Natural restructures its subsidiaries and partnerships to maintain efficient operations and to facilitate acquisitions and divestitures.

 

Canadian Natural Resources Limited

7

The consolidated financial statements of Canadian Natural include the accounts of the Company and all of its subsidiaries and wholly owned partnerships.

GENERAL DEVELOPMENT OF THE BUSINESS

2013

In 2011, the Company announced that it had entered into a partnership agreement with North West Upgrading Inc. to move forward with detailed engineering regarding the construction and operation of a bitumen upgrader and refinery (“the Project”) near Redwater, Alberta. In addition, the partnership has entered into processing agreements that target to process bitumen for the Company of 12,500 bbl/d and bitumen for the Alberta Petroleum Marketing Commission (“APMC”), an agent of the Government of Alberta, of 37,500 bbl/d under a 30 year fee-for-service tolling agreement under the Bitumen Royalty In Kind initiative. In 2012, the Project was sanctioned by the Board of Directors of each partner of the North West Redwater Partnership (“Redwater Partnership”), and the associated target toll amounts were accepted by Redwater Partnership, the Company and the APMC. In December 2013, Redwater Partnership, the Company and APMC agreed in principle to amend certain terms of the processing agreements. In conjunction with these amendments, the Company, along with APMC, each committed to provide additional funding up to $350 million to attain Project completion based on the revised Project cost estimate of approximately $8,500 million. The additional funding is in the form of subordinated debt bearing interest at prime plus 6%, which is anticipated to form part of the equity toll. Should final Project costs exceed the revised cost estimate, the Company and APMC have agreed, subject to the Company being able to meet certain funding conditions, to fund any shortfall in available third party commercial lending required to attain Project completion. Under its processing agreement, beginning on the earlier of the commercial operations date of the refinery and June 1, 2018, the Company is unconditionally obligated to pay its 25% pro rata share of the debt portion of the monthly cost of service toll, including interest, fees and principal repayments, of the Redwater Partnership’s syndicated credit facility and bonds, over the tolling period of 30 years.

During 2013, the Company discovered bitumen emulsion at surface in areas of the Primrose field. The Company continues to work with the regulator on the causation review of the bitumen emulsion seepage. The Company’s near-term steaming plan at Primrose has been modified, with steaming being reduced in certain areas.

During 2013, the Company acquired all the issued and outstanding shares of Barrick Energy Inc. and 1729580 Alberta Ltd., subsidiaries of Barrick Gold Corporation for approximately $173 million.

During 2013, the Company disposed of a 50% interest in its exploration right in South Africa, for a net cash consideration of US$255 million. In the event that a commercial crude oil or natural gas discovery occurs on this exploration right, resulting in the exploration right being converted into a production right, an additional cash payment would be due to the Company at such time, amounting to US$450 million for a commercial crude oil discovery and US$120 million for a commercial natural gas discovery.

During 2013, the Company entered into a 20 year transportation agreement to ship 80,000 bbl/d of crude oil on the proposed Energy East pipeline originating at Hardisty, Alberta with delivery points in Quebec City, Quebec and Saint John, New Brunswick. This pipeline is subject to regulatory approval.

During 2013, the Company issued $500 million of 2.89% medium-term notes due August 2020. Net proceeds from the sale were used to repay bank indebtedness and for general corporate purposes.

2014

In 2014, the Company completed the acquisition of certain Canadian crude oil and natural gas properties for cash consideration of approximately $3,110 million, subject to final closing adjustments. In connection with the agreement, the Company negotiated an additional $1,000 million unsecured bank credit facility with a two-year maturity and with terms similar to the Company’s current syndicated credit facilities. The acquired lands and production base are all located in Western Canada in areas adjacent to or near the Company’s current conventional operations, primarily in Northeast British Columbia, Northwest Alberta and Northern Plains areas.

In March 2014, the Company issued US$500 million floating rate unsecured notes due March 30, 2016 at a rate of 3 month LIBOR plus 0.375%, and US$500 million principal amount of 3.80% unsecured notes due April 15, 2024.  Net proceeds from the sale were used to repay bank indebtedness and for general corporate purposes.

In May 2014, the Company issued $500 million of 2.60% unsecured notes due December 3, 2019 and $500 million of 3.55% unsecured notes due June 3, 2024. Net proceeds from the sale were used to repay bank indebtedness and for general corporate purposes.

In November 2014, the Company issued US$600 million of 1.75% unsecured notes due January 15, 2018 and US$600 million of 3.90% unsecured notes due February 1, 2025. Net proceeds from the sale were used to repay bank indebtedness and for general corporate purposes.

2015

In response to declining commodity prices, the Company’s capital expenditures for 2015 reflected reductions in its capital program by approximately $3,400 million, as well as changes to its capital allocation strategy, including the decrease in drilling activity in North America, partially offset by the planned drilling activities in Offshore Africa.

In 2015, the Company’s existing $1,000 million non-revolving term credit facility was extended, maturing January 2017. The Company also entered into a new $1,500 million non-revolving term credit facility maturing April 2018. Both facilities were fully drawn at December 31, 2015. In addition, the Company’s $1,500 million revolving syndicated credit facility was increased to $2,425 million and the maturity date was extended to June 2019 from June 2016. The $3,000 million revolving syndicated credit facility was reduced to $2,425 million and the maturity date was extended to June 2020 from June 2017.

In June 2015, the Company issued $500 million of series 2 medium-term notes due August 2020 through the reopening of its previously issued 2.89% notes. Net proceeds from the sale were used to repay bank indebtedness and for general corporate purposes. The Company also repaid $400 million of 4.95% medium-term notes.

In 2014, the Company commenced a review of its royalty lands and royalty revenue portfolio. The review included a detailed examination of the Company’s freehold and royalty land position, production volumes, product mix, associated cash flow and collection of payments. In the fourth quarter of 2015, the Company disposed of its North America royalty income assets for total consideration of $1,658 million. Total consideration on the disposition was comprised of $673 million in cash, together with $985 million of non-cash consideration, comprised of approximately 44.4 million common shares of PrairieSky with a value of $22.16 per common share determined at the closing date. Subject to certain conditions, including applicable regulatory and/or shareholder approvals, the Company has agreed with PrairieSky that, by no later than December 31, 2016, it will distribute sufficient common shares of PrairieSky to the Company’s shareholders so that the Company, after such distribution, will hold less than 10% of the issued and outstanding common shares of PrairieSky.

2016

In the first quarter of 2016, the Company prepaid $250 million of the borrowings outstanding under the $1,000 million non-revolving term credit facility and extended the facility to February 2019 from January 2017. The Company also entered into a new $125 million non-revolving term credit facility maturing February 2019, which was fully drawn.

On March 21, 2016, the Court of Queen’s Bench of Alberta (the “Court”) granted an interim order under subsection 193(4) of the Business Corporations Act (Alberta), containing declarations and directions with respect to a Plan of Arrangement (the “Plan”) which, if approved by the Company’s shareholders at a subsequent meeting, will allow for the a return of capital to shareholders of the Company through the distribution of a minimum of 0.02 of a PrairieSky share in respect of each common share of the Company outstanding as of the effective time in accordance with the terms of the Plan. In the event that shareholder approval is obtained, the Company intends to apply to the Court for a final order approving the Plan, at which time the Company will have the discretion to proceed with the Plan as it stands or amend, alter or cancel the Plan.

DESCRIPTION OF THE BUSINESS

Canadian Natural is a Canadian based senior independent energy company engaged in the acquisition, exploration, development, production, marketing and sale of crude oil, natural gas and NGLs. The Company’s principal core regions of operations are western Canada, the UK sector of the North Sea and Offshore Africa.

The Company initiates, operates and maintains a large working interest in a majority of the prospects in which it participates. Canadian Natural’s objectives are to increase crude oil and natural gas production, reserves, cash flow and net asset value on a per common share basis through the development of its existing crude oil and natural gas properties and through the discovery and/or acquisition of new reserves.

 

Canadian Natural Resources Limited

9

The Company has a full complement of management, technical and support staff to pursue these objectives. As at December 31, 2015, the Company had the following full time equivalent permanent employees:

North America, Exploration and Production			4,513
North America, Oil Sands Mining and Upgrading			2,651
North Sea			372
Offshore Africa			32
Total Company			7,568

Operational discipline, safe, effective and efficient operations as well as cost control are fundamental to the Company. By consistently managing costs throughout all industry cycles, the Company believes it will achieve continued growth. Effective and efficient operations and cost control are attained by developing area knowledge and by maintaining high working interests and operator status in its properties. The Company has grown through a combination of internal growth and strategic acquisitions. Acquisitions are made with a view to either enter new core regions or increase presence in existing core regions.

The Company’s business approach is to maintain large project inventories and production diversification among each of the commodities it produces namely: natural gas and NGLs, light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, SCO from our oil sands mining operations and bitumen (thermal oil). The Company’s large diversified project portfolio enables the effective allocation of capital to higher return opportunities, which together provide complementary infrastructure and balance throughout the business cycle. Natural gas is the largest single commodity sold, accounting for 34% of 2015 production. Virtually all of the Company’s natural gas and NGLs production is located in the Canadian provinces of Alberta, British Columbia and Saskatchewan and is marketed in Canada and the US. Light and medium crude oil and NGLs, representing 16% of 2015 production, is located in the Company’s North Sea and Offshore Africa properties, and in the provinces of Alberta, British Columbia and Saskatchewan. Primary heavy crude oil accounting for 15% of 2015 production, Pelican Lake heavy crude oil accounting for 6% of 2015 production, and our bitumen (thermal oil) accounting for 15% of 2015 production are in the provinces of Alberta and Saskatchewan. SCO from our oil sands mining operations in Northern Alberta accounted for approximately 14% of 2015 production. Midstream assets, primarily comprised of two operated and one non operated pipeline systems, and an electricity cogeneration facility, provide cost effective infrastructure supporting the heavy crude oil and bitumen operations. The Company’s Midstream assets also include a 50% interest in the Redwater Partnership.

A. ENVIRONMENTAL MATTERS

The Company strives to carry out its activities in compliance with applicable regional, national and international regulations and industry standards. Environmental specialists in Canada and the UK track performance to numerous environmental performance indicators, review the operations of the Company’s world-wide interests and report on a regular basis to the senior management of the Company, which in turn reports on environmental matters directly to the Health, Safety, Asset Integrity and Environmental Committee of the Board of Directors.

The Company regularly meets with and submits to inspections by the various governments in the regions where the Company operates. The Company’s associated environmental risk management strategies focus on working with legislators and regulators to ensure that any new or revised policies, legislation or regulations properly reflect a balanced approach to sustainable development. Specific measures in response to existing or new legislation include a focus on the Company’s energy efficiency, air emissions management, released water quality, reduced fresh water use and the minimization of the impact on the landscape. Training and due diligence for operators and contractors are key to the effectiveness of the Company’s environmental management programs and the prevention of incidents. The Company believes that it meets all existing environmental standards and regulations and has included appropriate amounts in its capital expenditure budget to continue to meet current environmental protection requirements. Since these requirements apply to all operators in the crude oil and natural gas industry, it is not anticipated that the Company’s competitive position within the industry will be adversely affected by changes in applicable legislation.

The Company has internal procedures designed to ensure that the environmental aspects of new acquisitions and developments are taken into account prior to proceeding. The Company’s environmental management plan and operating guidelines focus on minimizing the environmental impact of operations while meeting regulatory requirements, regional management frameworks, industry operating standards and guidelines, and internal corporate standards. The Company’s proactive program includes: an internal environmental compliance audit and inspection program of the Company’s operating facilities; a suspended well inspection program to support future development or eventual abandonment; appropriate reclamation and decommissioning standards for wells and facilities ready for abandonment; an effective surface reclamation program; a due diligence program related to groundwater monitoring; an active program related to preventing and reclaiming

spill sites; a solution gas conservation program; a program to replace the majority of fresh water for steaming with brackish water; water programs to improve efficiency of use, recycle rates and water storage; environmental planning for all projects to assess environmental impacts and to implement avoidance and mitigation programs; reporting for environmental liabilities; a program to optimize efficiencies at the Company’s operated facilities; continued evaluation of new technologies to reduce environmental impacts and support for Canada’s Oil Sands Innovation Alliance (“COSIA”); CO₂ reduction programs including the injection of CO₂ into tailings and for use in EOR; a program in place related to progressive reclamation and tailings management for the Horizon facility through the operation of thickeners to reduce fluid tailings and the implementation of low fines mining to reduce fines from ore entering the bitumen extraction process and participation and support for the Joint Oil Sands Monitoring Program. The Company has also established operating standards in the following areas: exercising care with respect to all waste produced through effective waste management plans; using water-based, environmentally friendly drilling muds whenever possible; and minimizing produced water volumes offshore through cost-effective measures.  The Company has also adopted the Hydraulic Fracturing Operating Practices that were developed by the Canadian Association of Petroleum Producers (“CAPP”).  In 2015, Canadian Natural continued its environmental liability reduction program with the abandonment of 519 inactive wells.  In addition, reclamation was initiated at many of these sites with the eventual goal of reclamation certification. In 2015 the Company received 170 reclamation certificates representing 477 hectares of land. Further, decommissioning of inactive facilities and cleanup of active facilities was conducted to address environmental liabilities at operating assets. The Company participates in both the Canadian federal and provincial regulated GHG emissions reporting programs and continues to quantify annual GHG emissions for internal reporting purposes. The Company has participated in the CAPP Responsible Canadian Energy Program since 2000. The Company continues to invest in people, proven and new technologies, facilities and infrastructure to recover and process crude oil and natural gas resources efficiently and in an environmentally sustainable manner.

The Company, through CAPP, is working with Canadian legislators and regulators as they develop and implement new GHG emissions laws and regulations. Internally, the Company is pursuing an integrated emissions reduction strategy, to ensure it is able to comply with existing and future emissions reduction requirements, for both GHGs and air pollutants (such as sulphur dioxide and oxides of nitrogen). The Company continues to develop strategies that will enable it to deal with the risks and opportunities associated with new GHG and air emissions policies.  In addition, the Company is working with relevant parties to ensure that new policies encourage technological innovation, energy efficiency, and targeted research and development while not impacting competitiveness.

The Company continues to focus on reducing GHG emissions through improved efficiency, and on trading mechanisms to ensure compliance with requirements now in effect.  The Company is committed to managing air emissions through an integrated corporate approach which considers opportunities to reduce both air pollutants and GHG emissions. Air quality programs continue to be an essential part of the Company’s environmental work plan and are operated within all regulatory standards and guidelines. The Company strategy for managing GHG emissions is based on six core principles: improving energy conservation and efficiency; reducing emission intensity; developing and adopting innovative technology and supporting associated research and development; trading capacity, both domestically and globally; offsetting emissions; and considering life cycle costs of emission reductions in decision-making about project development.

The Company continues to implement flaring, venting, fuel and solution gas conservation programs. In 2015, the Company completed approximately 593 gas conservation projects in its primary heavy crude oil operations, resulting in a reduction of 3.3 million tonnes/year of CO₂e. Over the past five years the Company has spent over $102 million in its primary heavy crude oil and in situ oil sands operations to conserve the equivalent of over 18.5 million tonnes of CO₂e. The Company also monitors the performance of its compressor fleet as part of the Company’s compressor optimization initiative to improve fuel gas efficiency. These programs also influence and direct the Company’s plans for new projects and facilities. Horizon has incorporated advancements in technology to further reduce GHG emissions through maximizing heat integration, the use of cogeneration to meet steam and electricity demands and the design of the hydrogen production facility to enable CO₂ capture and the sequestration of CO₂ in oil sands tailings. The Company implemented a fuel gas import project in its North Sea operations to reduce diesel consumption in addition to continued focus on its flare reduction program in both the North Sea and Offshore Africa operations.

B. REGULATORY MATTERS

The Company’s business is subject to regulations generally established by government legislation and governmental agencies. The regulations are summarized in the following paragraphs.

Canada

The crude oil and natural gas industry in Canada operates under government legislation and regulations, which govern exploration, development, production, refining, marketing, transportation, prevention of waste and other activities.

 

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The Company’s Canadian properties are primarily located in Alberta, British Columbia, Saskatchewan, and Manitoba. Most of these properties are held under leases/licences obtained from the respective provincial or federal governments, which give the holder the right to explore for and produce crude oil and natural gas. The remainder of the properties are held under freehold (private ownership) lands.

Conventional petroleum and natural gas leases issued by the provinces of Alberta, Saskatchewan and Manitoba have a primary term from two to five years, and British Columbia leases/licences presently have a term of up to ten years. Those portions of the leases that are producing or are capable of producing at the end of the primary term will “continue” for the productive life of the lease.

An Alberta oil sands permit and oil sands primary lease is issued for five and fifteen years respectively. If the minimum level of evaluation of an oil sands permit is attained, a primary oil sands lease will be issued. A primary oil sands lease is continued based on the minimum level of evaluation attained on such lease. Continued primary oil sands leases that are designated as “producing” will continue for their productive lives and are not subject to escalating rentals while those designated as “non-producing” can be continued by payment of escalating rentals.

The provincial governments regulate the production of crude oil and natural gas as well as the removal of natural gas and NGLs from their respective province. Government royalties are payable on crude oil, natural gas and NGLs production from leases owned by the province. The royalties are determined by regulation and are generally calculated as a percentage of production varied by a number of different factors including selling prices, production levels, recovery methods, transportation and processing costs, location and date of discovery.

Alberta Oil Sands royalties are based on a sliding scale ranging from 1% to 9% on a gross revenue basis pre-payout and 25% to 40% on a net revenue basis post-payout, depending on benchmark crude oil pricing.

In January 2016, the Alberta government released its Royalty Review Panel Report (the “Panel Report”) recommending modernization of conventional crude oil and natural gas royalties effective for new wells drilled beginning in 2017 and also recommending no material change to the oil sands royalty framework. The Alberta government accepted the recommendations, subject to the terms being finalized, in the Panel Report and is expected to adopt the recommendations in 2016. Until the royalty terms to be implemented have been finalized, it is difficult to comment on the impact to industry of these changes.

During 2011, the Canadian federal government enacted legislation to implement several taxation changes. These changes include a requirement that, beginning in 2012, partnership income must be included in the taxable income of each corporate partner based on the tax year of the partner, rather than the fiscal year of the partnership.  The legislation includes a five year transition provision and has no impact on net earnings.

In June 2015, the Alberta government enacted legislation that increased the provincial corporate income tax rate from 10% to 12% effective July 1, 2015. The Company is subject to federal and provincial income taxes in Canada at a combined rate of approximately 26% in 2015 and 27% thereafter, after allowable deductions.

In Alberta, GHG reduction regulations came into effect July 1, 2007, affecting facilities emitting more than 100 kilotonnes of CO₂e annually. Five of the Company’s facilities, the Horizon facility, the Primrose/Wolf Lake in situ heavy crude oil facilities, the Kirby South in situ heavy crude oil facility, the Hays sour natural gas plant and the Wapiti gas plant are subject to compliance under the regulations. In British Columbia, carbon tax is currently being assessed at $30/tonne of CO₂e on fuel consumed and gas flared in the province. The Saskatchewan Government released draft GHG regulations that would regulate facilities emitting more than 50 kilotonnes of CO₂e annually and will likely require the North Tangleflags in situ heavy oil facility to meet the reduction target for its GHG emissions once the governing legislation comes into force.

In Canada, the federal government has indicated its intent to develop regulations to address industrial GHG emissions, as part of the national GHG reduction target. The federal government is also developing a comprehensive management system for air pollutants, and has released draft regulations pertaining to certain boilers, heaters and compressor engines operated by the Company.  In Alberta, the provincial government has implemented increases in both the carbon price and stringency of the existing large-emitter regulatory system for 2016 and 2017.  The Alberta Government has also announced additional changes to this system after 2017, as well as a program to reduce methane emissions from the upstream oil and gas sector, and a carbon price on combustion emissions from the upstream oil and gas sector beginning in 2023. In British Columbia, the provincial government is reviewing its climate change strategy with announcements on future changes expected in 2016.

United Kingdom

Under existing law, the UK government has broad authority to regulate the petroleum industry, including exploration, development, conservation and rates of production.

Crude oil and natural gas fields granted development approval before March 16, 1993 are subject to UK PRT of 50% charged on crude oil and natural gas profits. Approvals granted on or after March 16, 1993 are exempted from PRT. Profits for PRT purposes are calculated on a field-by-field basis by deducting field production costs and field development costs from production and third-party tariff revenue. In addition, certain statutory allowances are available, which may reduce the PRT payable. There is no PRT on profits of decommissioned fields subsequently redeveloped, subject to certain conditions being met.

In 2013, the UK government introduced a Decommissioning Relief Deed (“DRD”) which is a contractual mechanism whereby the UK government guarantees its participation in future field abandonments through a recovery of PRT and corporate income tax.

In March 2015, the UK government enacted legislation that reduced the supplementary charge on oil and gas profits from 32% to 20% effective January 1, 2015. In addition, the legislation reduced the PRT rate from 50% to 35% effective January 1, 2016. Allowable abandonment expenditures eligible for carryback to prior taxation years for PRT purposes are still recoverable at the previous tax rate of 50%. The legislation also replaced the existing Brownfield Allowance with a new Investment Allowance on qualifying capital expenditures, effective April 1, 2015. The new Investment Allowance is deductible for supplementary charge purposes, subject to certain restrictions.

The overall tax rate applicable to taxable income from oil and gas activities, including PRT and corporate and supplementary income tax charges, is 50% for non-PRT paying fields and for PRT paying fields is 75% in 2015 and 67.5% thereafter.

In March 2016, the UK government further reduced the PRT rate from 35% to 0%, effective January 1, 2016. The impact of the reduction to the Company is currently being determined. A proposed reduction to the supplementary charge from 20% to 10% was also introduced which remains subject to legislative approval.

In the UK, GHG regulations have been in effect since 2005. In Phase 1 (2005 – 2007) of the UK National Allocation Plan, the Company operated below its CO₂ allocation. In Phase 2 (2008 – 2012) the Company’s CO₂ allocation was decreased below the Company’s operations emissions.  In Phase 3 (2013 - 2020) the Company’s CO₂ allocation was further reduced. The Company continues to focus on implementing reduction programs based on efficiency audits to reduce CO₂ emissions at its major facilities and on trading mechanisms to ensure compliance with requirements now in effect.

Offshore Africa

Terms of licences, including royalties and taxes payable on production or profit sharing arrangements, as appropriate, vary by country and, in some cases, by concession within each country.

Development of the Espoir Field in Block CI-26 and the Baobab Field in Block CI-40, Offshore Côte d’Ivoire, are subject to Production Sharing Agreements (“PSA”) that deem tax or royalty payments to the government are met from the government’s share of profit oil. The current corporate income tax rate in Côte d’Ivoire is 25% which is applicable to non PSA income.

The Olowi Field (Offshore Gabon) is also under the terms of a PSA which deems tax or royalty payments to the government are met from the government’s share of profit oil. The current corporate income tax rate is 35% which is applicable to non PSA income.

In South Africa, for oil and gas companies, royalty rates range from 0.5% to 5% and the corporate income tax rate is 28%.

C. COMPETITIVE FACTORS

The energy industry is highly competitive in all aspects of the business including the exploration for and the development of new sources of supply, the construction and operation of crude oil and natural gas pipelines and related facilities, the acquisition of crude oil and natural gas interests, the transportation and marketing of crude oil, natural gas and NGLs, and electricity and the attraction and retention of skilled personnel.  The Company’s competitors include both integrated and non integrated crude oil and natural gas companies as well as other petroleum products and energy sources.

D. RISK FACTORS

Volatility of Crude Oil and Natural Gas Prices

The Company’s financial condition is substantially dependent on, and highly sensitive to the prevailing prices of crude oil and natural gas. Significant declines in crude oil or natural gas prices could have a material adverse effect on the Company’s operations and financial condition and the value and amount of its reserves. Prices for crude oil and natural gas fluctuate in response to changes in the supply of and demand for, crude oil and natural gas, market uncertainty and a variety of additional factors beyond the Company’s control. Crude oil prices are primarily determined by international supply and

 

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demand. Factors which affect crude oil prices include the actions of the Organization of Petroleum Exporting Countries, the condition of the Canadian, United States, European and Asian economies, government regulation, political stability in the Middle East and elsewhere, the foreign supply of crude oil, the price of foreign imports, the ability to secure adequate transportation for products which could be affected by pipeline constraints, the construction by third parties of new or expansion of existing pipeline capacity and other factors, and the availability of alternate fuel sources and weather conditions. Natural gas prices realized by the Company are affected primarily in North America by supply and demand, weather conditions, industrial demand, and prices of alternate sources of energy. Any substantial or extended decline in the prices of crude oil or natural gas could result in a delay or cancellation of existing or future drilling, development or construction programs, including but not limited to Horizon, Primrose, Pelican Lake, the Kirby Thermal Oil Sands Project, the North West Redwater bitumen upgrader and refinery and international projects, or curtailment in production at some properties, or result in unutilized long-term transportation commitments, all of which could have a material adverse effect on the Company’s financial condition.

Approximately 36% of the Company’s 2015 production on a BOE basis was primary heavy crude oil, Pelican Lake heavy crude oil, and bitumen (thermal oil). The market prices for these products may differ from the established market indices for light and medium grades of crude oil due principally to quality differences.  As a result, the price received for these products may differ from the benchmark they are priced against. Future quality differentials are uncertain and a significant increase in differential could have a material adverse effect on the Company’s financial condition.

Canadian Natural conducts assessments of the carrying value of its assets in accordance with IFRS. If crude oil and natural gas forecast prices decline, the carrying value of related property, plant and equipment could be subject to downward revisions, and net earnings could be adversely affected.

Operational Risk

Exploring for, producing, mining, extracting, upgrading and transporting crude oil, natural gas and NGLs involves many risks, which even a combination of experience, knowledge and careful evaluation may not be able to overcome. These activities are subject to a number of hazards which may result in fires, explosions, spills, blow outs or other unexpected or dangerous conditions causing personal injury, property damage, environmental damage, interruption of operations and loss of production, whether caused by human error or nature.  In addition to the foregoing, the Horizon operations are also subject to loss of production, potential shutdowns and increased production costs due to the integration of the various component parts.

Environmental Risks

All phases of the crude oil and natural gas business are subject to environmental regulation pursuant to a variety of Canadian, United States, United Kingdom, European Union, African and other federal, provincial, state and municipal laws and regulations as well as international conventions (collectively, "environmental legislation").

Environmental legislation imposes, among other things, restrictions, liabilities and obligations in connection with the generation, handling, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances to the environment. Environmental legislation also requires that wells, facility sites and other properties associated with the Company’s operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, certain types of operations including exploration and development projects and significant changes to certain existing projects may require the submission and approval of environmental impact assessments or permit applications. Compliance with environmental legislation can require significant expenditures and failure to comply with environmental legislation may result in the imposition of fines and penalties. The costs of complying with environmental legislation in the future may have a material adverse effect on the Company’s financial condition.

The crude oil and natural gas industry is experiencing incremental increases in costs related to environmental regulation, particularly in North America and the North Sea. Existing and expected legislation and regulations may require the Company to address and mitigate the effect of its activities on the environment. Increasingly stringent laws and regulations, including any new regulations the US may impose to limit purchases of crude oil in favour of less energy intensive sources, may have a material adverse effect on the Company’s financial condition.

There are a number of unresolved issues in relation to Canadian federal and provincial GHG regulatory requirements. Key among them is the form of regulation, an appropriate common facility emissions level, availability and duration of compliance mechanisms and resolution of federal/provincial harmonization agreements. In November 2015, the Government of Alberta announced a Climate Leadership Plan, including measures to reduce methane emissions, implement an emissions limit for oil sands, introduce a broad-based carbon price (with phase-in for the upstream industry), and modify the existing regulatory system for large emitting facilities. The Company continues to pursue GHG emission reduction initiatives including: solution

14	Canadian Natural Resources Limited

gas conservation, compressor optimization to improve fuel gas efficiency, CO₂ capture and sequestration in oil sands tailings, CO₂ capture and storage in association with EOR and participation in COSIA. 

The US Environmental Protection Agency (“EPA”) is proceeding to regulate GHGs under the Clean Air Act.  This EPA action has been subject to legal and political challenges, the outcome of which cannot be predicted. The ultimate form of Canadian regulation is anticipated to be strongly influenced by the regulatory and judicial decisions made within the United States.  Various states in the United States have enacted or are evaluating low carbon fuel standards, which may affect access to market for crude oils with higher emissions intensity. In March 2016 the US and Canadian governments issued a joint statement regarding a commitment to lowering methane emissions from the oil and gas sector by 2025. This reduction is expected to be implemented through a combination of federal and provincial actions, such as those announced by the Alberta government in November 2015.

The additional requirements of enacted or proposed GHG regulations on the Company’s operations may increase capital expenditures and production expense, including those related to Horizon and the Company’s other existing and certain planned oil sands projects. This may have an adverse effect on the Company’s financial condition.

Air pollutant standards and guidelines are being developed federally and provincially and the Company is participating in these discussions. Ambient air quality and sector based reductions in air emissions are being reviewed. Through Company and industry participation with stakeholders, guidelines are being developed that adopt a structured process to emission reductions that is commensurate with technological development and operational requirements.

In February 2009, the Energy Resources Conservation Board (ERCB), now the Alberta Energy Regulator or AER, released Directive 74 - Tailings Performance Criteria and Requirements for Oil Sands Mining Schemes. In March 2015, Alberta Environment and Parks released the Tailings Management Framework (TMF) policy and the AER suspended Directive 74. In September 2015 the AER released a draft Directive to replace Directive 74, Fluid Tailings Management for Oil Sands Mining Projects. The proposed Directive establishes performance criteria for tailings operations and sets out the requirements for approval, monitoring and reporting in respect of tailings ponds and tailings management plans. The Company will submit an updated Tailings Management Plan application in 2016 to meet the proposed Directive criteria. There is a risk the Company will not be successful in meeting the stipulated performance criteria once the new tailings process commences which could have an adverse effect on the Company’s financial condition.

Need to Replace Reserves

Canadian Natural’s future crude oil and natural gas reserves and production, and therefore its cash flows and results of operations, are highly dependent upon success in exploiting its current reserve base and acquiring or discovering additional reserves. Without additions to reserves through exploration, acquisition or development activities, the Company’s production will decline over time as reserves are depleted. The business of exploring for, developing or acquiring reserves is capital intensive. To the extent the Company’s cash flows from operations are insufficient to fund capital expenditures and external sources of capital become limited or unavailable, the Company’s ability to make the necessary capital investments to maintain and expand its crude oil and natural gas reserves will be impaired. In addition, Canadian Natural may be unable to find and develop or acquire additional reserves to replace its crude oil and natural gas production at acceptable costs.

Uncertainty of Reserve Estimates

There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond the Company’s control. In general, estimates of economically recoverable crude oil, natural gas and NGLs reserves and the future net cash flow therefrom are based upon a number of factors and assumptions made as of the date on which the reserve estimates were determined, such as geological and engineering estimates which have inherent uncertainties, the assumed effects of regulation by governmental agencies and estimates of future commodity prices and production costs, all of which may vary considerably from actual results. All such estimates are, to some degree, uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For these reasons, estimates of the economically recoverable crude oil, natural gas and NGLs reserves attributable to any particular group of properties, the classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Canadian Natural’s actual production, revenues, royalties, taxes and development, abandonment and operating expenditures with respect to its reserves will likely vary from such estimates, and such variances could be material.

Estimates of reserves that may be developed in the future are often based upon volumetric calculations and upon analogy to actual production history from similar reservoirs and wells. Subsequent evaluation of the same reserves based upon production history will result in variations in the previously estimated reserves.

 

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Sources of Liquidity

The ability of the Company to fund current and future capital projects and carry out our business plan is dependent on our ability to raise capital in a timely manner under favourable terms and conditions and is impacted by our credit ratings and the condition of the capital and credit markets. In addition, changes in credit ratings may affect the Company's ability to, and the associated costs of, entering into ordinary course derivative or hedging transactions, as well as entering into and maintaining ordinary course contracts with customers and suppliers on acceptable terms. The Company also enters into various transactions with counterparties and is subject to credit risk related to non-payment for sales contracts or non-performance by counterparties to contracts.

Dividends

The Company’s payment of future dividends on common shares is dependent on, among other things, its financial condition and other business factors considered relevant by the Board of Directors. The dividend policy undergoes periodic review by the Board of Directors and is subject to change.

Foreign Investments

The Company’s foreign investments involve risks typically associated with investments in developing countries such as uncertain political, economic, legal and tax environments. These risks may include, among other things, currency restrictions and exchange rate fluctuations, loss of revenue, property and equipment as a result of hazards such as expropriation, nationalization, war, insurrection and other political risks, risk of increases in taxes and governmental royalties, renegotiation of contracts with governmental entities and quasi-governmental agencies, changes in laws and policies governing operations of foreign based companies, including compliance with existing and emerging anti-corruption laws, and other uncertainties arising out of foreign government sovereignty over the Company’s international operations. In addition, if a dispute arises in its foreign operations, the Company may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the jurisdiction of a court in Canada or the United States.

Canadian Natural’s arrangement for the exploration and development of crude oil and natural gas properties in Canada and the UK sector of the North Sea differs distinctly from its arrangement for the exploration and development in other foreign crude oil and natural gas properties. In some foreign countries in which the Company does and may do business in the future, the state generally retains ownership of the minerals and consequently retains control of, and in many cases participates in, the exploration and production of reserves. Accordingly, operations may be materially affected by host governments through royalty payments, export taxes and regulations, surcharges, value added taxes, production bonuses and other charges. In addition, changes in prices and costs of operations, timing of production and other factors may affect estimates of crude oil and natural gas reserve quantities and future net cash flows attributable to foreign properties in a manner materially different than such changes would affect estimates for Canadian properties. Agreements covering foreign crude oil and natural gas operations also frequently contain provisions obligating the Company to spend specified amounts on exploration and development, or to perform certain operations or forfeit all or a portion of the acreage subject to the contract.

Risk Management Activities

In response to fluctuations in commodity prices, foreign exchange, and interest rates, the Company may utilize various derivative financial instruments and physical sales contracts to manage its exposure under a defined hedging program. The terms of these arrangements may limit the benefit to the Company of favourable changes in these factors and may also result in royalties being paid on a reference price which is higher than the hedged price. There is also increased exposure to counterparty credit risk.

Other Business Risks

Other business risks which may negatively impact the Company’s financial condition include regulatory issues, risk of increases in government taxes and changes to the royalty regime, risk of litigation, risk to the Company’s reputation resulting

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from operational activities that may cause personal injury, property damage or environmental damage, labour risk associated with securing the manpower necessary to complete capital projects in a timely and cost effective manner, severe weather conditions, timing and success of integrating the business and operations of acquired companies, and the dependency on third party operators for some of the Company’s assets. The Company utilizes a variety of information systems in its operations. A significant interruption or failure of the Company’s information technology systems and related data and control systems or a significant breach of security could adversely affect the Company’s operations. The majority of the Company’s assets are held in one or more corporate subsidiaries or partnerships.  In the event of the liquidation of any corporate subsidiary, the assets of the subsidiary would be used first to repay the indebtedness of the subsidiary, including trade payables or obligations under any guarantees, prior to being used by the Company to pay its indebtedness.

FORM 51-101F1 STATEMENT OF RESERVES DATA AND OTHER INFORMATION

For the year ended December 31, 2015, the Company retained Independent Qualified Reserves Evaluators (“IQRE”), Sproule Associates Limited and Sproule International Limited (together as “Sproule”) and GLJ Petroleum Consultants Ltd. (“GLJ”), to evaluate and review all of the Company’s proved and proved plus probable reserves with an effective date of December 31, 2015 and a preparation date of February 1, 2016.  Sproule evaluated the North America and International light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), natural gas and NGLs reserves.  GLJ evaluated the Horizon SCO reserves.  The evaluation and review was conducted in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and disclosed in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) requirements.

The Reserves Committee of the Company’s Board of Directors has met with and carried out independent due diligence procedures with each of the Company’s IQRE to review the qualifications of and procedures used by each IQRE in determining the estimate of the Company’s quantities and related net present value of future net revenue of the remaining reserves.

The Company annually discloses net proved reserves and the standardized measure of discounted future net cash flows using 12-month average prices and current costs in accordance with United States Financial Accounting Standards Board Topic 932 “Extractive Activities - Oil and Gas” in the Company’s Form 40-F filed with the SEC in the “Supplementary Oil and Gas Information” section of the Company’s Annual Report on pages 92 to 99 which is incorporated herein by reference.

The estimates of future net revenue presented in the tables below do not represent the fair market value of the reserves.

There is no assurance that the price and cost assumptions contained in the forecast case will be attained and variances could be material. The recovery and reserves estimates of crude oil, natural gas and NGLs reserves provided herein are estimates only and there is no guarantee the estimated reserves will be recovered.  Actual crude oil, natural gas and NGLs reserves may be greater or less than the estimate provided herein.

 

 

 

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Summary of Company Gross Reserves

As of December 31, 2015
Forecast Prices and Costs

		Light and Medium Crude Oil (MMbbl)				Primary Heavy Crude Oil (MMbbl)				Pelican Lake Heavy Crude Oil (MMbbl)				Bitumen (Thermal Oil) (MMbbl)				Synthetic Crude Oil (MMbbl)				Natural Gas (Bcf)				Natural Gas Liquids (MMbbl)				Barrels of Oil Equivalent (MMBOE)
North America
Proved
Developed Producing			102				112				222				351				2,283				3,848				99				3,810
Developed Non-Producing			8				20				4				-				-				270				6				83
Undeveloped			28				81				42				874				125				1,920				90				1,560
Total Proved			138				213				268				1,225				2,408				6,038				195				5,453
Probable			54				81				120				1,182				1,225				2,300				88				3,134
Total Proved plus Probable			192				294				388				2,407				3,633				8,338				283				8,587
North Sea
Proved
Developed Producing			3																				26								7
Developed Non-Producing			21																				9								23
Undeveloped			134																				4								135
Total Proved			158																				39								165
Probable			126																				57								135
Total Proved plus Probable			284																				96								300
Offshore Africa
Proved
Developed Producing			50																				22								54
Developed Non-Producing			1																				-								1
Undeveloped			39																				7								40
Total Proved			90																				29								95
Probable			52																				45								59
Total Proved plus Probable			142																				74								154
Total Company
Proved
Developed Producing			155				112				222				351				2,283				3,896				99				3,871
Developed Non-Producing			30				20				4				-				-				279				6				107
Undeveloped			201				81				42				874				125				1,931				90				1,735
Total Proved			386				213				268				1,225				2,408				6,106				195				5,713
Probable			232				81				120				1,182				1,225				2,402				88				3,328
Total Proved plus Probable			618				294				388				2,407				3,633				8,508				283				9,041

 

Summary of Company Net Reserves

As of December 31, 2015
Forecast Prices and Costs

		Light and Medium Crude Oil (MMbbl)				Primary Heavy Crude Oil (MMbbl)				Pelican Lake Heavy Crude Oil (MMbbl)				Bitumen (Thermal Oil) (MMbbl)				Synthetic Crude Oil (MMbbl)				Natural Gas (Bcf)				Natural Gas Liquids (MMbbl)				Barrels of Oil Equivalent (MMBOE)
North America
Proved
Developed Producing			90				96				168				276				1,926				3,495				73				3,211
Developed Non-Producing			7				16				3				-				-				239				5				71
Undeveloped			25				69				33				700				87				1,649				71				1,260
Total Proved			122				181				204				976				2,013				5,383				149				4,542
Probable			45				66				82				908				993				1,978				67				2,491
Total Proved plus Probable			167				247				286				1,884				3,006				7,361				216				7,033
North Sea
Proved
Developed Producing			3																				26								7
Developed Non-Producing			21																				9								22
Undeveloped			134																				4								135
Total Proved			158																				39								164
Probable			126																				57								136
Total Proved plus Probable			284																				96								300
Offshore Africa
Proved
Developed Producing			43																				15								46
Developed Non-Producing			-																				-								-
Undeveloped			31																				6								32
Total Proved			74																				21								78
Probable			39																				29								43
Total Proved plus Probable			113																				50								121
Total Company
Proved
Developed Producing			136				96				168				276				1,926				3,536				73				3,264
Developed Non-Producing			28				16				3				-				-				248				5				93
Undeveloped			190				69				33				700				87				1,659				71				1,427
Total Proved			354				181				204				976				2,013				5,443				149				4,784
Probable			210				66				82				908				993				2,064				67				2,670
Total Proved plus Probable			564				247				286				1,884				3,006				7,507				216				7,454

 

Canadian Natural Resources Limited

19

NOTES

1.

“Company gross reserves” are Canadian Natural’s working interest share of reserves before deduction of royalties and without including any royalty interests of the Company.

2.

“Company net reserves” are the company gross reserves less all royalties payable to others plus royalties receivable from others.

3.

References to “light and medium crude oil” means “light crude oil and medium crude oil combined”.

4.

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

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

Each of the reserve categories (proved and probable) may be divided into developed and undeveloped categories:

5.

The reserve evaluation involved data supplied by the Company with respect to geological and engineering data, adjustments for product quality, heating value and transportation, interests owned, royalties payable, production costs, capital costs and contractual commitments. This data was found by the IQRE to be reasonable.

6.

Amendments to NI 51-101 effective July 1, 2015 included changes to the definition of natural gas. Natural gas reserves disclosure is consistent with the prior year.

7.

BOE values as presented may not calculate due to rounding.

A report on reserves data by the Evaluators is provided in Schedule “A” to this AIF. A report by the Company’s management and directors on crude oil, natural gas and NGLs reserves disclosure is provided in Schedule “B” to this AIF.

 

20	Canadian Natural Resources Limited

Summary of Net Present Values of Future Net Revenue Before Income Taxes

As of December 31, 2015
Forecast Prices and Costs

MM$		Discount @ 0%				Discount @ 5%				Discount @ 10%				Discount @ 15%				Discount @ 20%				Unit Value Discounted at 10%/year $/BOE (1)
North America
Proved
Developed Producing			140,590				58,766				36,051				26,450				21,124				11.23
Developed Non-Producing			1,592				1,214				953				773				644				13.42
Undeveloped			39,900				38,964				24,741				15,630				10,245				19.64
Total Proved			182,082				98,944				61,745				42,853				32,013				13.59
Probable			152,865				45,391				19,341				10,843				7,195				7.76
Total Proved plus Probable			334,947				144,335				81,086				53,696				39,208				11.53
North Sea
Proved
Developed Producing			(985	)			(289	)			(79	)			(7	)			23				(11.29	)
Developed Non-Producing			(164	)			(143	)			(128	)			(118	)			(109	)			(5.82	)
Undeveloped			3,884				2,648				1,790				1,218				833				13.26
Total Proved			2,735				2,216				1,583				1,093				747				9.65
Probable			8,995				5,085				3,114				2,049				1,432				22.90
Total Proved plus Probable			11,730				7,301				4,697				3,142				2,179				15.66
Offshore Africa
Proved
Developed Producing			1,399				1,224				1,049				906				794				22.80
Developed Non-Producing			24				18				14				12				9				-
Undeveloped			1,912				1,224				852				632				492				26.63
Total Proved			3,335				2,466				1,915				1,550				1,295				24.55
Probable			3,361				2,019				1,329				938				699				30.91
Total Proved plus Probable			6,696				4,485				3,244				2,488				1,994				26.81
Total Company
Proved
Developed Producing			141,004				59,701				37,021				27,349				21,941				11.34
Developed Non-Producing			1,452				1,089				839				667				544				9.02
Undeveloped			45,696				42,836				27,383				17,480				11,570				19.19
Total Proved			188,152				103,626				65,243				45,496				34,055				13.64
Probable			165,221				52,495				23,784				13,830				9,326				8.91
Total Proved plus Probable			353,373				156,121				89,027				59,326				43,381				11.94

(1)	Unit values are based on company net reserves.

 

Canadian Natural Resources Limited

21

As of December 31, 2015
Forecast Prices and Costs

MM$		Discount @ 0%				Discount @ 5%				Discount @ 10%				Discount @ 15%				Discount @ 20%
North America
Proved
Developed Producing			105,376				46,041				29,102				21,764				17,617
Developed Non-Producing			1,150				879				688				556				461
Undeveloped			28,456				27,753				17,256				10,554				6,614
Total Proved			134,982				74,673				47,046				32,874				24,692
Probable			112,574				33,130				13,992				7,782				5,129
Total Proved plus Probable			247,556				107,803				61,038				40,656				29,821
North Sea
Proved
Developed Producing			(987	)			(296	)			(90	)			(20	)			8
Developed Non-Producing			(195	)			(170	)			(152	)			(139	)			(128	)
Undeveloped			2,883				1,691				1,055				676				433
Total Proved			1,701				1,225				813				517				313
Probable			4,256				2,426				1,528				1,045				763
Total Proved plus Probable			5,957				3,651				2,341				1,562				1,076
Offshore Africa
Proved
Developed Producing			1,019				925				805				701				618
Developed Non-Producing			19				14				11				9				7
Undeveloped			1,445				933				655				491				385
Total Proved			2,483				1,872				1,471				1,201				1,010
Probable			2,513				1,522				1,010				717				538
Total Proved plus Probable			4,996				3,394				2,481				1,918				1,548
Total Company
Proved
Developed Producing			105,408				46,670				29,817				22,445				18,243
Developed Non-Producing			974				723				547				426				340
Undeveloped			32,784				30,377				18,966				11,721				7,432
Total Proved			139,166				77,770				49,330				34,592				26,015
Probable			119,343				37,078				16,530				9,544				6,430
Total Proved plus Probable			258,509				114,848				65,860				44,136				32,445

(1)

After-tax net present values consider the Company’s existing tax pool balances and current tax regulations and do not represent an estimate of the value at the consolidated entity level, which may be significantly different. For information at the consolidated entity level, refer to the Company’s Consolidated Financial Statements and the Management’s Discussion and Analysis for the year ended December 31, 2015.

 

 

22	Canadian Natural Resources Limited

Additional Information Concerning Future Net Revenue

The following table summarizes the undiscounted future net revenue as at December 31, 2015 using forecast prices and costs.

Total Future Net Revenue (Undiscounted)

		North America								North Sea								Offshore Africa								Total
MM$		Proved				Proved plus Probable				Proved				Proved plus Probable				Proved				Proved plus Probable				Proved				Proved plus Probable
Revenue			451,421				785,008				18,185				33,814				6,891				10,960				476,497				829,782
Royalties			79,276				147,943				37				57				236				402				79,549				148,402
Production Costs			136,945				229,930				9,315				14,039				2,322				2,566				148,582				246,535
Development Costs			43,911				61,640				4,050				5,324				758				1,027				48,719				67,991
Abandonment and Reclamation Costs – Future Development(1)			573				892				16				193				19				48				608				1,133
Abandonment and Reclamation Costs – Existing Development(1)			8,634				9,656				2,032				2,471				221				221				10,887				12,348
Future Net Revenue Before Income Taxes			182,082				334,947				2,735				11,730				3,335				6,696				188,152				353,373
Income Taxes			47,100				87,391				1,034				5,773				852				1,700				48,986				94,864
Future Net Revenue After Income Taxes (2)			134,982				247,556				1,701				5,957				2,483				4,996				139,166				258,509

(1)

Due to amendments to NI 51-101 effective July 1, 2015, abandonment and reclamation costs included in the calculation of the future net revenue for 2015 consist of both forecast estimates of abandonment and reclamation costs attributable to future development activity, as well as certain costs already included in the Company’s ARO for development existing as at December 31, 2015. The Company’s estimated ARO at December 31, 2015 was $1,415 million, discounted at 10% (unescalated and undiscounted ARO at December 31, 2015 was $12,137 million). Approximately $8,188 million of this unescalated and undiscounted amount was also included in the future net revenue and is escalated at 1.5% per year. Specifically, for North America (excluding SCO assets), future net revenue includes the costs associated with abandonment and reclamation of wells (wells, well sites, wellsite equipment and pipelines) with assigned reserves. For SCO assets, future net revenue includes the costs associated with the abandonment and reclamation of the mine site and all mining and upgrading facilities. For North Sea and Offshore Africa, future net revenue includes the costs associated with the abandonment and reclamation of offshore wells and facilities with assigned reserves.

(2)	Future net revenue is prior to provision for interest, general and administrative expenses and the impact of any risk management activities.

 

 

 

The following table summarizes the future net revenue by production group as at December 31, 2015 using forecast prices and costs.

	Future Net Revenue By Product Type (1) (2)
Reserves Category	Production Group		Future Net Revenue Before Income Taxes (discounted at 10%/year) (MM$)				Unit Value ($/BOE)
Proved Reserves	Light and Medium Crude Oil (including solution gas and other by-products)			6,924				16.43
	Primary Heavy Crude Oil (including solution gas)			3,109				16.99
	Pelican Lake Heavy Crude Oil (including solution gas)			3,650				17.84
	Bitumen (Thermal Oil)			13,806				14.14
	Synthetic Crude Oil			33,009				16.40
	Natural Gas (including by-products but excluding solution gas and by-products from oil wells)			5,416				5.49
	Abandonment and Reclamation Costs – Existing Development			(671	)			-
	Total			65,243				13.64
Proved Plus Probable Reserves	Light and Medium Crude Oil (including solution gas and other by-products)			12,445				18.51
	Primary Heavy Crude Oil (including solution gas)			4,619				18.47
	Pelican Lake Heavy Crude Oil (including solution gas)			4,923				17.15
	Bitumen (Thermal Oil)			19,875				10.55
	Synthetic Crude Oil			40,230				13.38
	Natural Gas (including by-products but excluding solution gas and by-products from oil wells)			7,725				5.70
	Abandonment and Reclamation Costs – Existing Development			(790	)			-
	Total			89,027				11.94

 

Pricing Assumptions

The crude oil, natural gas and NGLs reference pricing and the inflation and exchange rates used in the preparation of reserves and related future net revenue estimates are as per the Sproule price forecast dated December 31, 2015. The following is a summary of the Sproule price forecast.

		2016				2017				2018				2019				2020				Average annual increase thereafter
Crude Oil and NGLs
WTI(1) (US$/bbl)		$	45.00			$	60.00			$	70.00			$	80.00			$	81.20				1.50	%
WCS(2) (C$/bbl)		$	45.26			$	57.96			$	65.88			$	75.11			$	77.03				1.50	%
Canadian Light Sweet(3) (C$/bbl)		$	55.20			$	69.00			$	78.43			$	89.41			$	91.71				1.50	%
Cromer LSB(4) (C$/bbl)		$	54.20			$	68.00			$	77.43			$	88.41			$	90.71				1.50	%
Edmonton C5+(5) (C$/bbl)		$	59.10			$	73.88			$	83.98			$	95.73			$	98.19				1.50	%
North Sea Brent(6) (US$/bbl)		$	45.00			$	60.00			$	70.00			$	80.00			$	81.20				1.50	%
Natural Gas
AECO(7) (C$/MMBtu)		$	2.25			$	2.95			$	3.42			$	3.91			$	4.20				1.50	%
BC Westcoast Station 2(8) (C$/MMBtu)		$	1.45			$	2.55			$	3.02			$	3.51			$	3.80				1.50	%
Henry Hub(9) (US$/MMBtu)		$	2.25			$	3.00			$	3.50			$	4.00			$	4.25				1.50	%

(1)	"WTI” refers to the price of West Texas Intermediate crude oil at Cushing, Oklahoma.

(2)	“WCS” refers to Western Canadian Select, a blend of heavy crude oils and bitumen with sweet synthetic and condensate diluents at Hardisty, Alberta; reference price used in the preparation of primary heavy crude oil, Pelican Lake heavy crude oil and bitumen (thermal oil) reserves.

(3)	“Canadian Light Sweet” refers to the price of light gravity (40˚ API), low sulphur content Mixed Sweet Blend (MSW) crude oil at Edmonton, Alberta; reference price used in the preparation of light and medium crude oil and SCO reserves.

(4)	"Cromer LSB” refers to the price of light sour blend (35˚ API) physical crude oil at Cromer, Manitoba; reference price used in the preparation of light and medium crude oil in SE Saskatchewan and SW Manitoba reserves.

(5)	“Edmonton C5+” refers to pentanes plus at Edmonton, Alberta; reference price used in the preparation of NGLs reserves; also used in determining the diluent costs associated with primary heavy crude oil and bitumen (thermal oil) reserves.

(6)	“North Sea Brent” refers to the benchmark price for European, African and Middle Eastern crude oil; reference price used in the preparation of North Sea and Offshore Africa light crude oil reserves.

(7)	“AECO” refers to the Alberta natural gas trading price at the AECO-C hub in southeast Alberta; reference price used in the preparation of North America (excluding British Columbia) natural gas reserves.

(8)	“BC Westcoast Station 2” refers to the natural gas delivery point on the Spectra Energy system at Chetwynd, British Columbia; reference price used in the preparation of British Columbia natural gas reserves.

(9)	“Henry Hub” refers to a distribution hub on the natural gas pipeline system in Erath, Louisiana and is the pricing point for natural gas futures on the New York Mercantile Exchange.

The forecast prices and costs assume the continuance of current laws and regulations, and any increases in wellhead selling prices also take inflation into account. Sales prices are based on reference prices as detailed above and adjusted for quality and transportation on an individual property basis. A foreign exchange rate of 0.7500 US$/C$ for 2016, 0.8000 US$/C$ for 2017, 0.8300 US$/C$ for 2018 and 0.8500 US$/C$ after 2018 was used in the 2015 evaluation.

Production costs are escalated at Sproule’s cost inflation rate of 0% per year for 2016 to 2017 and 1.5% per year after 2017 for all products.  Capital costs are escalated at Sproule’s cost inflation rate of 0% per year for 2016, 4% per year for 2017 to 2019 and 1.5% per year after 2019 for North America light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil and natural gas.  Capital costs are escalated at Sproule’s cost inflation rate of 1.5% per year for bitumen (thermal oil), SCO and International light and medium crude oil.

The Company’s 2015 average pricing, net of blending costs and excluding risk management activities, was $59.72/bbl for light and medium crude oil, $40.71/bbl for primary heavy crude oil, $41.09/bbl for Pelican Lake heavy crude oil, $34.37/bbl for bitumen (thermal oil), $61.39/bbl for SCO, $23.30/bbl for NGLs and $3.16/Mcf for natural gas.

Reconciliation of Company Gross Reserves

As of December 31, 2015
Forecast Prices and Cost

PROVED
North America		Light and Medium Crude Oil (MMbbl)				Primary Heavy Crude Oil (MMbbl)				Pelican Lake Heavy Crude Oil (MMbbl)				Bitumen (Thermal Oil) (MMbbl)				Synthetic Crude Oil (MMbbl)				Natural Gas (Bcf)				Natural Gas Liquids (MMbbl)				Barrels of Oil Equivalent (MMBOE)
December 31, 2014			145				229				274				1,217				2,158				5,869				188				5,189
Discoveries			1				-				-				-				-				14				2				5
Extensions			1				4				-				23				220				252				10				300
Infill Drilling			4				10				-				-				-				298				7				71
Improved Recovery			-				-				2				26				-				-				-				28
Acquisitions			5				4				-				7				-				414				8				93
Dispositions			(3	)			-				-				-				-				(7	)			-				(4	)
Economic Factors			(6	)			(3	)			-				-				7				(385	)			(6	)			(72	)
Technical Revisions			10				16				10				(1	)			68				190				1				135
Production			(19	)			(47	)			(18	)			(47	)			(45	)			(607	)			(15	)			(292	)
December 31, 2015			138				213				268				1,225				2,408				6,038				195				5,453
North Sea
December 31, 2014			204																				83								218
Discoveries			-																				-								-
Extensions			-																				-								-
Infill Drilling			-																				-								-
Improved Recovery			-																				-								-
Acquisitions			-																				-								-
Dispositions			-																				-								-
Economic Factors			(2	)																			(7	)							(3	)
Technical Revisions			(36	)																			(24	)							(40	)
Production			(8	)																			(13	)							(10	)
December 31, 2015			158																				39								165
Offshore Africa