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, 2018 | Commission File Number: 001-12138 |
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, 28 Liberty Street, New York, New York 10005 (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:
Title of Each Class: | Name of each exchange on which registered: |
Common Shares, no par value | New York Stock Exchange |
Securities registered or to be registered pursuant to Section 12(g) of the Act:
Title of Each Class: None
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 |
Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.
1,201,885,667 Common Shares outstanding as of December 31, 2018
Canadian Natural Resources Limited | 1 | Year Ended December 31, 2018 |
Indicate by check mark whether the Registrant by filing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934 (the "Exchange Act"). If "Yes" is marked, indicate the file number assigned to the Registrant in connection with such Rule.
Yes [ ] | No [X] |
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 is an emerging growth company as defined in Rule 12b-2 of the Exchange Act.
Emerging Growth Company | [ ___ ] |
If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
[ ___ ] | |
† The term new or revised financial accounting standard refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.
This Annual Report on Form 40-F shall be incorporated by reference into, or as an exhibit to, as applicable, the Registrant’s Registration Statements on Form F-10 (File Nos. 333-219366 and 333-219367) 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 6, 2019 the reported Bank of Canada noon rate for one Canadian dollar was US$0.7438. On March 6, 2019 the reported Bank of Canada noon rate for one U.S. dollar was C$1.3444.
Principal Documents
The following documents have been filed as part of this Annual Report on Form 40-F, starting on the following page:
A. | Annual Information Form | |
B. | Audited Annual Financial Statements | |
C. | Management’s Discussion and Analysis | |
The following document is filed as an exhibit to this Annual Report on Form 40-F and is incorporated by reference herein:
Canadian Natural Resources Limited | 2 | Year Ended December 31, 2018 |
A. | Supplementary Oil & Gas Information (Unaudited) | |
Canadian Natural Resources Limited | 3 | Year Ended December 31, 2018 |
ANNUAL INFORMATION FORM
FOR THE YEAR ENDED DECEMBER 31, 2018
March 27, 2019
TABLE OF CONTENTS
Canadian Natural Resources Limited | 2 | Year Ended December 31, 2018 |
DEFINITIONS AND ABBREVIATIONS
AOSP | Athabasca Oil Sands Project |
API | specific gravity measured in degrees on the American Petroleum Institute scale |
ARO | asset retirement obligations |
bbl | barrel |
bbl/d | barrels per day |
Bcf | billion cubic feet |
bitumen | naturally occurring solid or semi-solid hydrocarbon, consisting mainly of heavier hydrocarbons that are too heavy or thick to flow at reservoir conditions, and recoverable at economic rates using thermal in-situ recovery methods |
BOE | barrels of oil equivalent |
BOE/d | barrels of oil equivalent per day |
C$ or $ | Canadian dollars |
“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 |
CO2 | carbon dioxide |
CO2e | carbon dioxide equivalents |
crude oil | includes light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, synthetic crude oil and bitumen (thermal oil) |
CSS | Cyclic Steam Stimulation |
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 |
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 | discounted value of crude oil and natural gas reserves plus value of unproved land, less net debt |
net wells | gross wells multiplied by the percentage working interest therein owned by the Company |
NYSE | New York Stock Exchange |
Canadian Natural Resources Limited | 3 | Year Ended December 31, 2018 |
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 |
Quest | Quest Carbon Capture and Storage ("CCS") project |
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 |
Canadian Natural Resources Limited | 4 | Year Ended December 31, 2018 |
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements relating to Canadian Natural Resources Limited (the “Company”) in this Annual Information Form (“AIF”) 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, production expenses, capital expenditures, income tax expenses, and other guidance provided throughout this 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, AOSP and Primrose thermal projects, the Pelican Lake water and polymer flood project, the Kirby Thermal Oil Sands Project, the cost and timing of construction and future operations of the North West Redwater bitumen upgrader and refinery, and construction by third parties of new or expansion of existing pipeline capacity or other means of transportation of bitumen, crude oil, natural gas, NGLs or SCO that the Company may be reliant upon to transport its products to market, development and deployment of technology and technological innovations, the assumption of operations at processing facilities, and the "2019 Activity" section of this AIF with respect to budgeted capital expenditures for 2019, also constitute forward-looking statements. These forward-looking statements are based on annual budgets and multi-year forecasts, and are 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 reserves 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, natural gas and NGL 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; the 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; the 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; the timing and success of integrating the business and operations of acquired companies and assets; production levels; imprecision of reserves 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 expenditures and production expenses); 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 national, 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
Canadian Natural Resources Limited | 5 | Year Ended December 31, 2018 |
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 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 applicable 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 the Company's estimates or opinions change.
SPECIAL NOTE REGARDING CURRENCY, FINANCIAL INFORMATION, PRODUCTION AND RESERVES
In this AIF, all references to dollars refer to Canadian dollars unless otherwise stated. Reserves and production data are presented on a "before royalties" or " company gross" basis unless otherwise stated and realized prices are net of blending and feedstock costs and exclude the effects of risk management activities. 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:1bbl conversion 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, 2018, 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, 2018, 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, 2018 and a preparation date of February 4, 2019. Sproule evaluated and reviewed 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 Oil Sands Mining and Upgrading SCO reserves. The evaluations and reviews were 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 and in the “Supplementary Oil and Gas Information” section of the Company’s Annual Report on pages 98 to 105 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 (loss) from operations; adjusted funds flow (previously referred to as funds flow from operations); net capital expenditures; 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 (loss), cash flows from operating activities, and cash flows used in investing activities, as determined in accordance with IFRS, as an indication of the Company’s performance. The non-GAAP measure adjusted net earnings (loss) from operations is reconciled to net earnings (loss), as determined in accordance with IFRS in the “Financial and Operational Highlights" section of the MD&A for the year ended December 31, 2018. Additionally, the non-GAAP measure adjusted funds flow is reconciled to cash flows from operating activities, as determined in accordance with IFRS, in the "Financial and Operational Highlights" section of the MD&A. The non-GAAP measure net capital expenditures is
Canadian Natural Resources Limited | 6 | Year Ended December 31, 2018 |
reconciled to cash flows used in investing activities, as determined in accordance with IFRS, in the "Net Capital Expenditures" section of the MD&A. The derivation of adjusted cash production costs is included in the “Operating Highlights – Oil Sands Mining and Upgrading” section of the MD&A. The non-GAAP measure free cash flow represents cash flows from operating activities as presented in the Company's consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital from operating activities, abandonment, certain movements in other long-term assets, less net capital expenditures and dividends paid on common shares of the Company.
Canadian Natural Resources Limited | 7 | Year Ended December 31, 2018 |
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 |
January 1, 2003 - Rio Alto Exploration Ltd. |
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. |
January 1, 2019 - Laricina Energy Ltd. |
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 (Gabon) Limited | Gabon | 100 |
CNR International (South Africa) Limited | Alberta | 100 |
CNR (Redwater) Limited | Alberta | 100 |
Horizon Construction Management Ltd. | Alberta | 100 |
Sukunka Natural Resources Inc. | Alberta | 100 |
Partnership | ||
Canadian Natural Resources | Alberta | 100 |
Canadian Natural Resources Northern Alberta Partnership | Alberta | 100 |
Canadian Natural Resources 2005 Partnership | Alberta | 100 |
CNRI (Gabon) SCS | Gabon | 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. CNR International (South Africa) Limited, as the limited partner, and CNR International (Gabon) Limited, as the general partner, are the partners of CNRI (Gabon) SCS.
Canadian Natural Resources Limited | 8 | Year Ended December 31, 2018 |
In the ordinary course of business, Canadian Natural restructures its subsidiaries and partnerships to maintain efficient operations.
The consolidated financial statements of Canadian Natural include the accounts of the Company and all of its subsidiaries and wholly owned partnerships as well as certain of the Company's activities which are conducted through joint arrangements.
GENERAL DEVELOPMENT OF THE BUSINESS
2016
In June 2016, the Company completed the net distribution of approximately 21.8 million PrairieSky Royalty Ltd. ("PrairieSky") common shares to the shareholders of record of the Company as at June 3, 2016, completing a previously announced Plan of Arrangement. As part of an earlier transaction, the Company agreed with PrairieSky that, by no later than December 31, 2016, it would distribute sufficient common shares of PrairieSky to the Company's shareholders so that the Company, after such distribution, would hold less than 10% of the issued and outstanding common shares of PrairieSky. The distribution was recognized as a return of capital of $546 million. Subsequent to the distribution, the Company’s ownership interest in PrairieSky was less than 10% of the issued and outstanding common shares of PrairieSky.
During 2016, the Company disposed of its ownership interest in the Cold Lake Pipeline. Net consideration on the disposition was comprised of $349 million in cash, together with $190 million of non-cash share consideration of approximately 6.4 million common shares of Inter Pipeline Ltd. with a value of $29.57 per common share, determined as of the closing date.
During 2016, the Company issued $1,000 million of 3.31% medium term notes due February 2022 and entered into a new $125 million non-revolving term credit facility maturing February 2019, which was fully drawn at December 31, 2016. As well, the Company prepaid $250 million of the borrowings outstanding under the previously outstanding $1,000 million non-revolving term credit facility and extended the facility to February 2019 from January 2017. This $750 million facility was fully drawn at December 31, 2016. In addition, the Company repaid US$250 million of 6% notes and US$500 million of three-month LIBOR plus 0.375% notes.
2017
On May 31, 2017, the Company completed its acquisition of a direct and indirect 70% interest in AOSP, including 70% of the Scotford Upgrader and the Quest Carbon Capture and Storage ("CCS") project, as well as additional working interests in other producing and non-producing oil sands leases through a transaction with Shell Canada Limited and certain of its subsidiaries ("Shell”) and Marathon Oil Corporation (“Marathon Oil”).
Total purchase consideration of $12,541 million, subject to closing adjustments, was comprised of cash payments of $8,217 million, approximately 97.6 million common shares of the Company issued to Shell with a value of approximately $3,818 million as determined at the closing date, and deferred purchase consideration of $506 million (US$375 million). To finance the acquisition of the AOSP, the Company entered into a $3,000 million non-revolving term credit facility maturing May 2020. At December 31, 2017, this facility was fully drawn. As well, the Company issued $1,800 million of medium term notes comprised of $900 million 2.05% notes due June 2020, $600 million 3.42% notes due December 2026 and $300 million 4.85% notes due May 2047. The Company also issued US$3,000 million of debt securities comprised of US$1,000 million 2.95% notes due January 2023, US$1,250 million 3.85% notes due June 2027 and US$750 million 4.95% notes due June 2047.
In addition, in 2017 the Company extended $2,095 million of the $2,425 million revolving syndicated credit facility originally due June 2019 to June 2021 with the remaining $330 million maturing June 2019 and the Company's $1,500 million non-revolving term credit facility was increased to $2,200 million with the maturity date being extended to October 2019 from April 2018. As well, the Company repaid US$1,100 million of 5.70% notes.
In the third quarter of 2017, the Company acquired assets in the Greater Pelican Lake region and other miscellaneous assets in northern Alberta with production of approximately 19,600 BOE/d, for gross cash consideration of $975 million.
In the fourth quarter of 2017, the Company completed the construction and commissioning of its Horizon Phase 3 expansion.
In December 2017, the Company announced a number of senior management promotions positioning it for continued growth in both the long life low decline assets and low capital exposure assets.
Canadian Natural Resources Limited | 9 | Year Ended December 31, 2018 |
2018
In March 2018, the Company paid the deferred purchase consideration of US$375 million to Marathon Oil in connection with the AOSP acquisition.
In the second quarter of 2018, the Company extended its $2,425 million revolving syndicated credit facility originally maturing in June 2020 to June 2022 and extended its $2,200 million non-revolving facility from October 2019 to October 2020. In 2018, the Company also extended the $750 million non-revolving credit facility originally due February 2019 to February 2021, fully repaid and canceled the $125 million non-revolving credit facility maturing February 2019, repaid and canceled $1,200 million of the $3,000 million non-revolving term credit facility maturing May 2020, and repaid US$600 million of 1.75% notes and US$400 million of 5.90% notes.
In September, 2018, the Company completed the acquisition of all of the issued and outstanding common shares and senior notes of Laricina Energy Ltd. ("Laricina") for a total purchase price of $95 million. Laricina was amalgamated with the Company on January 1, 2019.
In September 2018, the Company also completed its acquisition of a 100% working interest in the Joslyn oil sands project for a total purchase consideration of $100 million cash on closing and annual cash payments of $25 million over each of the subsequent five years.
In 2018, the Gabonese Republic approved cessation of production from the Company’s Olowi field and the terms of termination of the Olowi Production Sharing Contract and the surrender of the permit area back to the Gabonese Republic.
In November 2018, the Company announced certain senior management promotions positioning it for continued growth in both the long life low decline assets and low capital exposure assets.
2019
The government of Alberta announced a mandatory curtailment of crude oil and bitumen production on December 2, 2018, which took effect on January 1, 2019. The amount of the curtailment is subject to monthly adjustment by the government.
Canadian Natural Resources Limited | 10 | Year Ended December 31, 2018 |
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 and cash flow 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.
The Company has a full complement of management, technical and support staff to pursue these objectives. As at December 31, 2018, the Company had the following full time equivalent permanent employees:
North America, Exploration and Production | 4,395 |
North America, Oil Sands Mining and Upgrading | 4,948 |
North Sea and Offshore Africa | 366 |
Total Company | 9,709 |
Operational discipline, together with safe, effective and efficient operations and cost control, are fundamental to the Company. By consistently managing costs throughout all industry cycles, the Company believes it will achieve continued growth. Safe operations that are effective and efficient 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 entering new core regions or increasing the Company's presence in existing core regions.
The Company’s business approach is to maintain large project inventories and production diversification among each of its products: SCO, natural gas, light and medium crude oil and NGLs, bitumen (thermal oil), primary heavy crude oil and Pelican Lake heavy crude 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. SCO from the oil sands mining and upgrading operations in Northern Alberta accounted for 39% of 2018 production. Natural gas, primarily produced in Alberta, British Columbia and Saskatchewan, accounted for 24% of 2018 production. Light and medium crude oil and NGLs represented 13% of 2018 production, and were produced from Alberta, British Columbia, Saskatchewan and Manitoba, as well as from the Company’s North Sea and Offshore Africa operations. Also produced from Alberta and Saskatchewan were bitumen (thermal oil), which accounted for 10% of 2018 production, primary heavy crude oil which accounted for 8% of 2018 production, and and Pelican Lake heavy crude oil, which accounted for 6% of 2018 production. The Company's Midstream assets, primarily comprised of two operated pipeline systems, and an electricity cogeneration facility, provide cost effective infrastructure supporting the heavy crude oil and bitumen operations. Midstream assets also include a 50% interest in the North West Redwater Partnership.
In addition, the Company has entered into a 20 year transportation agreement to ship 75,000 bbl/d of crude oil on the proposed Trans Mountain Pipeline Expansion. The National Energy Board has provided its recommendation that construction of the pipeline should proceed and related consultations by the federal government with Indigenous communities are ongoing. Subject to federal cabinet approval, the project could be issued a revised Certificate of Public Convenience and Necessity this summer with construction re-starting as early as August 2019. The Company has also entered into a 20 year transportation agreement to ship 175,000 bbl/d of crude oil on the proposed TransCanada Keystone XL Pipeline. The proponent is awaiting the completion of a new supplemental environmental review addressing issues raised through litigation in a Montana Federal Court case. A decision is also expected in April 2019 on the Nebraska Public Service Commission's route approval. Pre-construction activities have started and the proponent is working to maintain a 2021 in-service date.
A. ENVIRONMENTAL MATTERS
The Company carries 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 government regulatory authorities in the regions where the Company operates. The Company’s associated environmental risk management strategies focus on
Canadian Natural Resources Limited | 11 | Year Ended December 31, 2018 |
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, water management and land management to minimize disturbance impacts. 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. In Canada, these requirements apply to all operators in the crude oil and natural gas industry and 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 (the "Plan") along with the Company's operating guidelines focus on minimizing the environmental impact of operations while meeting regulatory requirements, regional management frameworks for air, water and biodiversity, industry operating standards and guidelines, and internal corporate standards. Training and due diligence for operators and contractors is key to the effectiveness of the Company's environmental management programs and the prevention of incidents to protect the environment. The Company, as a part of its Plan, has implemented programs that include: environmental planning to assess impacts and implement avoidance and mitigation programs in order to preserve high value biodiversity; continued evaluation of new technologies to reduce environmental impacts including support for Canada’s Oil Sands Innovation Alliance (“COSIA”), the Petroleum Technology Alliance Canada and other research institutions; CO2 reduction programs including carbon capture, CO2 injection for EOR, CO2 sequestration in tailings and the Quest carbon capture and storage facility; a methane emission reduction program, including solution gas conservation to reduce methane venting and an equipment retrofit program to reduce methane emissions from pneumatic equipment; optimization of efficiencies at the Company's facilities; water programs to improve efficiency of use and recycle rates as well as reduce fresh water use; and an effective reclamation and decommissioning program across the Company's operations, returning sites to their former state. In North America, the Company has implemented: programs for well abandonment and progressive reclamation of large contiguous areas of land, which advances biodiversity and establishes functional wildlife habitats; tailings management in Oil Sands Mining to minimize fine tailings and promote reclamation; monitoring programs to assess changes to biodiversity, wildlife and fisheries in order to manage construction and operation effects and to assess reclamation success; participation and support for the Oil Sands Monitoring Program of regionally important resources; groundwater monitoring for all thermal in situ and mine operations; an active spill prevention and management program; and an internal environmental compliance audit and inspection program of operating facilities.
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 2018, Canadian Natural continued its environmental liability reduction program with the abandonment of 1,293 inactive wells. In addition, reclamation was initiated at many of these sites with the eventual goal of reclamation certification. In 2018, the Company received 717 reclamation certificates representing 1,383 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 provincially regulated GHG emissions reporting programs and continues to quantify annual GHG emissions for internal reporting purposes. 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.
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’s integrated GHG emissions reduction strategy includes: integrating emission reduction in project planning and operations; leveraging technology to create value and enhance performance; investing in research and development and supporting collaboration; focusing on continuous improvement to drive long-term emissions reduction; leading in carbon capture and sequestration/storage; engaging in policy and regulatory development (including trading capacity and offsetting emissions); and considering and developing new business opportunities and trends.
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 continues to enhance its integrated emissions reduction strategy, to ensure it is able to comply with existing and future emissions reduction requirements, for both GHG 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.
Canadian Natural Resources Limited | 12 | Year Ended December 31, 2018 |
The Company also continues to implement flaring, venting, fuel and solution gas conservation programs, which influence and direct its future plans for new projects and facilities. In 2018, the Company completed approximately 425 gas conservation projects in its primary heavy crude oil operations, resulting in a reduction of approximately 2.4 million tonnes/year of CO2e. Over the past five years, the Company has spent over $72 million in its primary heavy crude oil and in situ oil sands operations to conserve the equivalent of over 16.8 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 and has ongoing methane reduction programs for pneumatic devices. Oil Sands Mining 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 that enables CO2 capture, the sequestration of CO2 in oil sands tailings, and recovery of hydrocarbon liquids from refinery fuel gas. 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 through 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 legislation and regulations, which govern exploration, development, production, refining, marketing, transportation, prevention of waste and other activities.
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 federal or respective provincial governments, which give the holder the right to explore for and produce bitumen, crude oil, and natural gas. The remainder of the properties are held under freehold (private ownership) leases.
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 royalties on oil sands projects 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.
Effective January 1, 2017, the Alberta government adopted the Modernized Royalty Framework (MRF) for conventional crude oil, natural gas and NGLs royalties. Alberta will have a parallel royalty regime system with the existing Alberta Royalty Framework (ARF) for 10 years until December 31, 2026 and the MRF will apply to wells drilled on or after January 1, 2017. Under the MRF, conventional royalty rates will range from a minimum of 5% to a maximum of 36% for natural gas and NGLs and a minimum 5% to a maximum 40% for crude oil.
The Company is subject to federal and provincial income taxes in Canada at a combined rate of approximately 27% after allowable deductions.
In Canada, the federal government has ratified the Paris climate change agreement, with a commitment to reduce GHG emissions by 30% from 2005 levels by 2030. Canada has also committed to reduce methane emissions from the upstream oil and natural gas sector by 40-45% by 2025, as compared to 2012 levels. The federal government is also developing (i) a comprehensive management system for air pollutants and has released regulations pertaining to certain boilers, heaters and compressor engines operated by the Company; and (ii) a Clean Fuel Standard, which may affect production and consumption of fuels in Canada.
Canadian Natural Resources Limited | 13 | Year Ended December 31, 2018 |
Effective January 1, 2018, the Alberta government implemented the Carbon Competitiveness Incentive Regulation (CCIR) to replace the Specified Gas Emitters Regulation, for the regulation of GHG emissions from large facilities. The Alberta government has also finalized regulations to reduce methane emissions from the upstream oil and gas sector (consistent with the federal reduction target), with the first regulatory requirements coming into effect January 1, 2020. A previously announced carbon price on combustion emissions from the upstream oil and gas sector is scheduled to begin in 2023. In British Columbia, the provincial government has announced a methane reduction target, comparable to the federal target, and has released final regulations to achieve this target. The Saskatchewan government has also released a regulation to reduce methane emissions from crude oil production facilities, effective 2020. In Alberta, GHG reduction regulations came into effect July 1, 2007, affecting facilities emitting more than 100 kilotonnes of CO2e annually, or for those facilities that elect to "opt-in" to the regulations. The carbon price in Alberta is currently $30/tonne for emissions above the regulated limits. Eight of the Company’s operated facilities (the Horizon and AOSP facilities, the Primrose/Wolf Lake in situ heavy crude oil facilities, the Kirby South in situ heavy crude oil facility, the Peace River in situ heavy crude oil facility, the Hays sour natural gas plant, the Wapiti gas plant and the Brintnell power generation facility) are subject to compliance under the regulation. The non-operated Scotford Upgrader is also subject to compliance under the regulations. The non-operated North West Redwater bitumen upgrader and refinery will not be subject to a reduction target until 2020. In British Columbia, carbon tax is currently being assessed at $35/tonne of CO2e on fuel consumed and gas flared in the province, with the rate increasing to $40/tonne on April 1, 2019. The British Columbia government will be increasing the carbon tax at a rate of $5 per tonne of CO2e annually to $50 per tonne of CO2e on April 1, 2021. The British Columbia government is implementing a program (the CleanBC Plan) to partially mitigate the impact of the carbon tax increases on emission intensive trade exposed (EITE) sectors. The Saskatchewan government has released a regulation that applies to facilities emitting more than 25 kilotonnes of CO2e annually and will require the North Tangleflags in situ heavy crude oil facility and the Senlac in situ heavy crude oil facility to meet reduction targets for GHG emissions effective 2019. The government of Canada has determined that a federal “backstop” carbon pricing system will apply beginning in 2019 in specific provinces and territories within Canada, including the provinces of Saskatchewan and Manitoba in which the Company operates. The federal backstop system will consist of an output-based pricing system for facilities that emit more than 25 kilotonnes CO2e annually, and a fuel charge that applies to facilities with emissions below this level.
The International Maritime Organization (IMO) will implement a new regulation (IMO 2020) effective January 1, 2020, that places sulphur content limits (currently 3.5% to 0.5%) on marine fuel oil consumed by vessels. In our North American operations, IMO 2020 is anticipated to have a net positive impact due to SCO from the Company's Oil Sands Mining and Upgrading operations, a large percentage of which can be processed and refined into low-sulphur diesel.
United Kingdom
Under existing law, the UK government has broad authority to regulate the petroleum industry, including exploration, development, conservation and rates of production.
Effective January 1, 2016 the PRT rate, which is a charge on certain crude oil and natural gas profits, was reduced to 0%. Allowable abandonment expenditures eligible for carryback to 2015 and prior taxation years for PRT purposes remain recoverable at 50%. In addition, the supplementary charge on oil and gas profits was reduced to 10%. An Investment Allowance on qualifying capital expenditures is deductible for supplementary charge purposes, subject to certain restrictions. As a result of these changes, the overall tax rate applicable to taxable income from oil and gas activities is 40%.
During 2013, the UK government introduced a Decommissioning Relief Deed (“DRD”) which is a regulatory and contractual mechanism whereby the UK government guarantees its participation in future field abandonments through a recovery of PRT and corporate income tax.
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
Canadian Natural Resources Limited | 14 | Year Ended December 31, 2018 |
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.
During the fourth quarter of 2018, the Gabonese Republic approved cessation of production from the Company’s Olowi Field and associated decommissioning obligations, as well as the terms of termination of the Olowi Production Sharing Contract and the surrender of the permit area back to the government.
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 price for 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 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, government mandated curtailment, the availability of alternate fuel sources and weather conditions, and other factors. Natural gas prices realized by the Company are affected primarily in North America by supply and demand, weather conditions, industrial demand and the ability to secure adequate transportation for products which could also be affected by pipeline constraints, government mandated curtailment, and prices of alternate sources of energy. Crude oil and natural gas producers in Canada may receive discounted prices for their production relative to international prices due in part to constraints on the ability to transport and sell products to international markets. A failure to resolve such constraints may result in continued discounted or reduced commodity prices realized by crude oil and natural gas producers, including the Company.
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, AOSP, Primrose, Pelican Lake, the Kirby Thermal Oil Sands Project, 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 24% of the Company’s 2018 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 currently differs 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 currently differs 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 periodic 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.
Canadian Natural Resources Limited | 15 | Year Ended December 31, 2018 |
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 oil sands mining and upgrading operations are also subject to loss of production, potential shutdowns and increased production expenses due to the integration of the various component parts.
The Company's business also carries risks associated with environmental and safety performance, which are closely scrutinized by governments, the public and the media, and could result in the suspension of or the inability to obtain regulatory approvals and permits, or, in the case of a major incident, fines, civil suits, and/or criminal charges against the Company.
The jurisdictions where Canadian Natural operates are subject to labour legislation and regulations that if changed may impact its operations. In addition, labour risk associated with work interruptions and the securing of necessary manpower may impact the timely and cost effective manner in which projects are completed.
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 national, 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 compliance, particularly in North America and the North Sea. In respect of its offshore operations, the Company also participates with regulators and industry partners in addressing environmental monitoring and emergency response protocols that are applicable to the Company's operations in these jurisdictions. 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 may have a material adverse effect on the Company’s financial condition, including the following:
l Greenhouse Gas Emissions Management
Current and potential climate change policies and regulations are considered when making decisions to advance the Company’s business strategy. The Company is tracking the development of policies and regulations at the international, national, federal and provincial level. In Canada, the government of Alberta has proceeded with implementing the measures in the Climate Leadership Plan that were announced in November 2015, 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 modification of the existing regulatory system for large emitting facilities. The Company continues to pursue GHG emission reduction initiatives including: solution gas conservation, compressor optimization to improve fuel gas efficiency, reductions in pneumatic devices, CO2 capture and sequestration in oil sands tailings, CO2 capture and storage in association with EOR, CO2 capture and storage at Quest, and participation in COSIA.
Various jurisdictions have enacted or are evaluating low carbon fuel standards, which may affect access to market for crude oils with higher emissions intensity. The Canadian government and certain provincial governments have published regulations to reduce methane emissions from the oil and natural gas sector, in support of a joint commitment made by the US and Canadian governments to lower emissions from the sector by 2025.
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 the Company’s existing and planned oil sands projects. This may have an adverse effect on the Company’s financial condition.
Canadian Natural Resources Limited | 16 | Year Ended December 31, 2018 |
l Air Emissions Management
The Company could face additional costs to retrofit certain equipment to meet the requirements of the federal Multi-Sector Air Pollutants Regulations in Canada. Additional costs may be required to retrofit other equipment in specific regions to meet ambient air quality objectives, as part of regional air zone management.
l Tailings Management
In March 2015, Alberta Environment and Parks released the Tailings Management Framework (TMF) policy. In July 2016, the Alberta Energy Regulator (AER), released Directive 85 - Fluid Tailings Management for Oil Sands Mining Projects which was updated in October 2017. The 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.
In 2018, the Company continued to implement and adhere to the conditions stipulated in the approved Tailings Management Plans for the Horizon Mine (the "Horizon TMP"), and the AOSP's Muskeg River Mine and Jackpine Mine and thereby met the requirements of the government of Alberta’s Tailings Management Framework (2015) and the Alberta Energy Regulator’s Directive 85. In the future, there is the potential risk of deviating above the approved site-specific tailings profiles resulting in the requirement to post additional security under the Mining Financial Security Plan as well as the potential application of a compliance levy.
In September 2018, the Company acquired the Joslyn oil sands project (now referred to as “Horizon South”). Prior to development, the AER requires the Company to prepare an updated mine plan that will incorporate tailings and closure planning considerations by November 13, 2019. As a result, it is anticipated that, in 2019, further updates will be required to the Horizon TMP to integrate the development of Horizon South.
In December 2018, Alberta Environment and Parks released the new Dam and Canal Safety Directive (the "Directive"). The Directive outlines a detailed process for all fluid holding infrastructure in Alberta (including tailings ponds), on application requirements, performance monitoring and reporting, and decommissioning and closure process. The Company is working with the regulator to determine how the Directive will be implemented and enforced. Muskeg River Mine has obtained several authorizations as it works through the decommissioning process for its External Tailings Facility, reducing the mine's environmental risk and liability.
l Regulatory and Policy Effectiveness
The Company operates under government regulation and policy for the crude oil and natural gas sector including, land tenure, royalties, taxes, production rates, environmental management, and safety performance. Before proceeding with major projects, the Company must follow a determined regulatory process to obtain project approvals and permits. These processes may include Indigenous and stakeholder consultation, environmental impact assessments and public hearings. Canadian Natural’s project execution and timelines could be impacted by delays experienced through the regulatory processes or by conditions placed on its operations through permit approvals. Changes in government policy, such as the federal government’s Bill-69, have the potential to impact the certainty and timelines for the regulatory process on large energy projects, including increased requirements for Indigenous consultation. The Company is working with industry peers, CAPP and others to ensure that its concerns regarding Bill C-69 are communicated to the Canadian government.
l Land Use, Water and Wildlife Management
Legislation and policies related to land management may affect development and operations risk through changes in regional limits on operating standards for air emissions, water use, land disturbance and reclamation. Land planning is used to set aside areas for conservation, reclamation and biodiversity that places limits on crude oil and natural gas development. Management frameworks establish limits and triggers for surface and ground water quality and quantity, land disturbance and air emissions that could increase the standards for operation of facilities.
Water licencing, use and release standards are becoming increasingly stringent both in the process of obtaining access to water and to manage it efficiently. Sub-basin water use licence restrictions and the inability to manage allocations of water licences effectively by transferring water to alternate uses has the potential to increase production expenses. Alberta Wetland Policy changes may increase requirements and payments for new project development.
The Species at Risk Act (Canada) requires the maintenance of habitat for a variety of species. In the case of Woodland Caribou, the requirements of undisturbed habitat combined with minimum herd population from all cumulative land changes may impact plans for crude oil and natural gas expansion. The presence of other species at risk such as birds or amphibians requires that operations be managed to avoid or mitigate effects resulting in potential operational inefficiencies and delays.
Canadian Natural Resources Limited | 17 | Year Ended December 31, 2018 |
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 reserves 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 flow is 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 Reserves Estimates
There are numerous uncertainties inherent in estimating quantities of reserves, including many factors, both internal and external, beyond the Company’s control. Revisions are often necessary resulting in changes in technical data acquired, historical performance, fluctuations in production costs, development costs and product pricing, economic conditions, changes in royalty regimes and environmental regulations and future technology improvements. In general, estimates of economically recoverable crude oil, natural gas and NGLs reserves and the future net revenue therefrom are based upon a number of factors and assumptions made as of the date on which the reserves estimates were determined, such as geological and engineering estimates which have inherent uncertainties, the assumed effects of royalty regimes, environmental and other regulation by governmental agencies and estimates of future commodity prices, production costs and the timing and amount of future development expenditures, 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.
Project Risk
Canadian Natural has a variety of exploration, development and construction projects underway at any given time. Project delays may result in delayed revenue receipts and cost overruns may result in projects being uneconomic. The Company’s ability to complete projects is dependent on general business and market conditions as well as other factors beyond the Company’s control including the availability of skilled labour and manpower, the availability and proximity of pipeline capacity, weather, fires, environmental and regulatory matters, ability to access lands, availability of drilling and other equipment, and availability of processing capacity.
Sources of Liquidity
The ability to fund current and future capital projects and carry out the business plan is dependent on Canadian Natural's ability to generate cash flow as well as raise capital in a timely manner under favourable terms and conditions and is impacted by the Company's credit ratings and the condition of the capital and credit markets. In addition, changes in credit ratings may affect the 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.
Canadian Natural Resources Limited | 18 | Year Ended December 31, 2018 |
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 of crude oil and natural gas properties in other foreign jurisdictions. 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 reserves quantities and future net revenues 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 periodically 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.
Information Security
The nature and complexity of information security risks that may negatively impact the Company continues to evolve as cyber criminals develop new schemes to target businesses and perpetrate cyber-related frauds that target the information technology and business systems of the Company. 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. Notwithstanding the Company’s proactive approach to combating cybersecurity threats, such threats frequently change and require evolving monitoring and detection efforts. Examples of such threats include unauthorized access to information technology systems due to social engineering, hacking, viruses and other causes. A successful cyber-attack could result in the loss, disclosure or theft of confidential information related to the Company’s proprietary business activities and the personnel files of its employees. The Company has implemented cybersecurity protocols and procedures to address this risk.
Other cybersecurity risks include cyber-related fraud and theft or destruction of financial and other assets of the Company whereby perpetrators attempt to spoof, manipulate, or take control of electronic communications from Company executives, suppliers, or other business partners, to divert payments and assets to accounts controlled by perpetrators of the scheme. A successful cyber-related fraud of this nature could result in the financial losses to the Company, remediation and recovery costs, and reputational issues with suppliers, customers and business partners who may also be impacted by the scheme. The Company has implemented training programs that allow personnel to identify potential threats of this nature in addition to the internal accounting and process controls implemented to address this 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 royalty regimes, risk of litigation, risk to the Company’s reputation resulting 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,
Canadian Natural Resources Limited | 19 | Year Ended December 31, 2018 |
severe weather conditions, timing and success of integrating the business and operations of acquired companies and businesses, and the dependency on third party operators for certain of the Company’s assets.
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 to repay the indebtedness of the Company.
Canadian Natural Resources Limited | 20 | Year Ended December 31, 2018 |
FORM 51-101F1 STATEMENT OF RESERVES DATA AND OTHER INFORMATION
For the year ended December 31, 2018, 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, 2018 and a preparation date of February 4, 2019. Sproule evaluated and reviewed 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 Oil Sands Mining and Upgrading SCO reserves. The evaluations and reviews were 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 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 98 to 105 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. See "Special Note Regarding Forward-Looking Statements", "Special Note Regarding Currency, Financial Information, Production and Reserves", and "Risk Factors".
Canadian Natural Resources Limited | 21 | Year Ended December 31, 2018 |
Summary of Company Gross Reserves
As of December 31, 2018
Forecast Prices and Costs
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 | 114 | 97 | 248 | 311 | 6,091 | 3,477 | 101 | 7,541 | ||||||||
Developed Non-Producing | 14 | 16 | — | 123 | — | 326 | 10 | 218 | ||||||||
Undeveloped | 66 | 69 | 57 | 1,106 | — | 2,794 | 156 | 1,920 | ||||||||
Total Proved | 194 | 182 | 305 | 1,540 | 6,091 | 6,597 | 267 | 9,679 | ||||||||
Probable | 74 | 70 | 140 | 1,519 | 941 | 3,036 | 130 | 3,379 | ||||||||
Total Proved plus Probable | 268 | 252 | 445 | 3,059 | 7,032 | 9,633 | 397 | 13,058 | ||||||||
North Sea | ||||||||||||||||
Proved | ||||||||||||||||
Developed Producing | 34 | 23 | 38 | |||||||||||||
Developed Non-Producing | 4 | — | 4 | |||||||||||||
Undeveloped | 81 | 4 | 82 | |||||||||||||
Total Proved | 119 | 27 | 124 | |||||||||||||
Probable | 67 | 11 | 69 | |||||||||||||
Total Proved plus Probable | 186 | 38 | 193 | |||||||||||||
Offshore Africa | ||||||||||||||||
Proved | ||||||||||||||||
Developed Producing | 41 | 17 | 44 | |||||||||||||
Developed Non-Producing | — | — | — | |||||||||||||
Undeveloped | 45 | 11 | 46 | |||||||||||||
Total Proved | 86 | 28 | 90 | |||||||||||||
Probable | 35 | 35 | 41 | |||||||||||||
Total Proved plus Probable | 121 | 63 | 131 | |||||||||||||
Total Company | ||||||||||||||||
Proved | ||||||||||||||||
Developed Producing | 189 | 97 | 248 | 311 | 6,091 | 3,517 | 101 | 7,623 | ||||||||
Developed Non-Producing | 18 | 16 | — | 123 | — | 326 | 10 | 222 | ||||||||
Undeveloped | 192 | 69 | 57 | 1,106 | — | 2,809 | 156 | 2,048 | ||||||||
Total Proved | 399 | 182 | 305 | 1,540 | 6,091 | 6,652 | 267 | 9,893 | ||||||||
Probable | 176 | 70 | 140 | 1,519 | 941 | 3,082 | 130 | 3,489 | ||||||||
Total Proved plus Probable | 575 | 252 | 445 | 3,059 | 7,032 | 9,734 | 397 | 13,382 | ||||||||
Canadian Natural Resources Limited | 22 | Year Ended December 31, 2018 |
Summary of Company Net Reserves
As of December 31, 2018
Forecast Prices and Costs
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 | 101 | 81 | 189 | 252 | 5,125 | 3,183 | 80 | 6,358 | ||||||||
Developed Non-Producing | 12 | 14 | — | 104 | — | 303 | 8 | 189 | ||||||||
Undeveloped | 56 | 59 | 48 | 911 | (8 | ) | 2,519 | 131 | 1,616 | |||||||
Total Proved | 169 | 154 | 237 | 1,267 | 5,117 | 6,005 | 219 | 8,163 | ||||||||
Probable | 61 | 57 | 100 | 1,210 | 761 | 2,676 | 104 | 2,740 | ||||||||
Total Proved plus Probable | 230 | 211 | 337 | 2,477 | 5,878 | 8,681 | 323 | 10,903 | ||||||||
North Sea | ||||||||||||||||
Proved | ||||||||||||||||
Developed Producing | 34 | 23 | 38 | |||||||||||||
Developed Non-Producing | 4 | — | 4 | |||||||||||||
Undeveloped | 81 | 4 | 82 | |||||||||||||
Total Proved | 119 | 27 | 124 | |||||||||||||
Probable | 67 | 11 | 69 | |||||||||||||
Total Proved plus Probable | 186 | 38 | 193 | |||||||||||||
Offshore Africa | ||||||||||||||||
Proved | ||||||||||||||||
Developed Producing | 36 | 12 | 38 | |||||||||||||
Developed Non-Producing | — | — | — | |||||||||||||
Undeveloped | 36 | 9 | 38 | |||||||||||||
Total Proved | 72 | 21 | 76 | |||||||||||||
Probable | 26 | 23 | 30 | |||||||||||||
Total Proved plus Probable | 98 | 44 | 106 | |||||||||||||
Total Company | ||||||||||||||||
Proved | ||||||||||||||||
Developed Producing | 171 | 81 | 189 | 252 | 5,125 | 3,218 | 80 | 6,434 | ||||||||
Developed Non-Producing | 16 | 14 | — | 104 | — | 303 | 8 | 193 | ||||||||
Undeveloped | 173 | 59 | 48 | 911 | (8 | ) | 2,532 | 131 | 1,736 | |||||||
Total Proved | 360 | 154 | 237 | 1,267 | 5,117 | 6,053 | 219 | 8,363 | ||||||||
Probable | 154 | 57 | 100 | 1,210 | 761 | 2,710 | 104 | 2,839 | ||||||||
Total Proved plus Probable | 514 | 211 | 337 | 2,477 | 5,878 | 8,763 | 323 | 11,202 | ||||||||
Canadian Natural Resources Limited | 23 | Year Ended December 31, 2018 |
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:
• | “Proved reserves” are those reserves which can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. |
• | “Probable reserves” are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. |
Each of the reserves categories (proved and probable) may be divided into developed and undeveloped categories:
• | “Developed reserves” are reserves that are expected to be recovered from (i) existing wells and installed facilities or, if the facilities have not been installed, that would involve a low expenditure (compared to the cost of drilling a well) to put the reserves on production, and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. The developed category may be subdivided into producing and non-producing. |
• | “Undeveloped reserves” are reserves that are expected to be recovered from known accumulations with new wells on undrilled acreage, or from existing wells where significant expenditures are required for the completion of these wells or for the installation of processing and gathering facilities prior to the production of these reserves. Reserves on undrilled acreage are limited to those drilling units directly offsetting development spacing areas that are reasonably certain of production when drilled unless reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. |
5. | The reserves 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. | BOE values as presented may not calculate due to rounding. |
A report on reserves data by the IQREs 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.
Canadian Natural Resources Limited | 24 | Year Ended December 31, 2018 |
Summary of Net Present Values of Future Net Revenue Before Income Taxes (1)
As of December 31, 2018
Forecast Prices and Costs
MM$ | Discount @ 0% | Discount @ 5% | Discount @ 10% | Discount @ 15% | Discount @ 20% | Unit Value Discounted at 10%/year ($/BOE) (2) | ||||||
North America | ||||||||||||
Proved | ||||||||||||
Developed Producing | 361,010 | 143,064 | 82,072 | 57,648 | 45,025 | 12.91 | ||||||
Developed Non-Producing | 5,331 | 3,697 | 2,945 | 2,468 | 2,121 | 15.58 | ||||||
Undeveloped | 39,173 | 27,921 | 15,804 | 9,128 | 5,416 | 9.78 | ||||||
Total Proved | 405,514 | 174,682 | 100,821 | 69,244 | 52,562 | 12.35 | ||||||
Probable | 152,532 | 45,299 | 20,981 | 12,563 | 8,664 | 7.66 | ||||||
Total Proved plus Probable | 558,046 | 219,981 | 121,802 | 81,807 | 61,226 | 11.17 | ||||||
North Sea | ||||||||||||
Proved | ||||||||||||
Developed Producing | (258 | ) | 699 | 956 | 1,010 | 1,000 | 25.16 | |||||
Developed Non-Producing | 78 | 63 | 51 | 41 | 34 | 12.75 | ||||||
Undeveloped | 4,339 | 3,320 | 2,624 | 2,129 | 1,764 | 32.00 | ||||||
Total Proved | 4,159 | 4,082 | 3,631 | 3,180 | 2,798 | 29.28 | ||||||
Probable | 5,129 | 3,255 | 2,289 | 1,732 | 1,381 | 33.17 | ||||||
Total Proved plus Probable | 9,288 | 7,337 | 5,920 | 4,912 | 4,179 | 30.67 | ||||||
Offshore Africa | ||||||||||||
Proved | ||||||||||||
Developed Producing | 1,293 | 1,265 | 1,175 | 1,080 | 996 | 30.92 | ||||||
Developed Non-Producing | — | — | — | — | — | |||||||
Undeveloped | 2,137 | 1,399 | 972 | 707 | 533 | 25.58 | ||||||
Total Proved | 3,430 | 2,664 | 2,147 | 1,787 | 1,529 | 28.25 | ||||||
Probable | 2,557 | 1,656 | 1,157 | 860 | 671 | 38.57 | ||||||
Total Proved plus Probable | 5,987 | 4,320 | 3,304 | 2,647 | 2,200 | 31.17 | ||||||
Total Company | ||||||||||||
Proved | ||||||||||||
Developed Producing | 362,045 | 145,028 | 84,203 | 59,738 | 47,021 | 13.09 | ||||||
Developed Non-Producing | 5,409 | 3,760 | 2,996 | 2,509 | 2,155 | 15.52 | ||||||
Undeveloped | 45,649 | 32,640 | 19,400 | 11,964 | 7,713 | 11.18 | ||||||
Total Proved | 413,103 | 181,428 | 106,599 | 74,211 | 56,889 | 12.75 | ||||||
Probable | 160,218 | 50,210 | 24,427 | 15,155 | 10,716 | 8.60 | ||||||
Total Proved plus Probable | 573,321 | 231,638 | 131,026 | 89,366 | 67,605 | 11.70 | ||||||
(1) | Abandonment and reclamation costs included in the calculation of the Future Net Revenue (FNR) 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 Asset Retirement Obligation (ARO) for development existing as at December 31, 2018. The portion of the Company’s estimated ARO included in the reserves FNR is escalated at 2.0% per year after 2019. For additional information, refer to "Additional Information Concerning Future Net Revenue." |
(2) | Unit values are based on company net reserves. |
Canadian Natural Resources Limited | 25 | Year Ended December 31, 2018 |
Summary of Net Present Values of Future Net Revenue After Income Taxes(1) (2)
As of December 31, 2018
Forecast Prices and Costs
MM$ | Discount @ 0% | Discount @ 5% | Discount @ 10% | Discount @ 15% | Discount @ 20% | |||||
North America | ||||||||||
Proved | ||||||||||
Developed Producing | 266,889 | 107,718 | 62,772 | 44,606 | 35,135 | |||||
Developed Non-Producing | 3,981 | 2,691 | 2,123 | 1,768 | 1,511 | |||||
Undeveloped | 28,784 | 19,876 | 10,827 | 5,896 | 3,182 | |||||
Total Proved | 299,654 | 130,285 | 75,722 | 52,270 | 39,828 | |||||
Probable | 111,673 | 32,859 | 15,080 | 8,958 | 6,137 | |||||
Total Proved plus Probable | 411,327 | 163,144 | 90,802 | 61,228 | 45,965 | |||||
North Sea | ||||||||||
Proved | ||||||||||
Developed Producing | (82 | ) | 446 | 593 | 627 | 626 | ||||
Developed Non-Producing | (103 | ) | (3 | ) | 19 | 22 | 20 | |||
Undeveloped | 2,765 | 2,089 | 1,652 | 1,346 | 1,122 | |||||
Total Proved | 2,580 | 2,532 | 2,264 | 1,995 | 1,768 | |||||
Probable | 3,105 | 1,985 | 1,406 | 1,072 | 860 | |||||
Total Proved plus Probable | 5,685 | 4,517 | 3,670 | 3,067 | 2,628 | |||||
Offshore Africa | ||||||||||
Proved | ||||||||||
Developed Producing | 1,008 | 1,032 | 980 | 914 | 851 | |||||
Developed Non-Producing | — | — | — | — | — | |||||
Undeveloped | 1,624 | 1,076 | 754 | 554 | 422 | |||||
Total Proved | 2,632 | 2,108 | 1,734 | 1,468 | 1,273 | |||||
Probable | 1,924 | 1,253 | 882 | 659 | 518 | |||||
Total Proved plus Probable | 4,556 | 3,361 | 2,616 | 2,127 | 1,791 | |||||
Total Company | ||||||||||
Proved | ||||||||||
Developed Producing | 267,815 | 109,196 | 64,345 | 46,147 | 36,612 | |||||
Developed Non-Producing | 3,878 | 2,688 | 2,142 | 1,790 | 1,531 | |||||
Undeveloped | 33,173 | 23,041 | 13,233 | 7,796 | 4,726 | |||||
Total Proved | 304,866 | 134,925 | 79,720 | 55,733 | 42,869 | |||||
Probable | 116,702 | 36,097 | 17,368 | 10,689 | 7,515 | |||||
Total Proved plus Probable | 421,568 | 171,022 | 97,088 | 66,422 | 50,384 | |||||
(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 MD&A for the year ended December 31, 2018. |
(2) | Abandonment and reclamation costs included in the calculation of the Future Net Revenue (FNR) 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 Asset Retirement Obligation (ARO) for development existing as at December 31, 2018. The portion of the Company’s estimated ARO included in the reserves FNR is escalated at 2.0% per year after 2019. For additional information, refer to "Additional Information Concerning Future Net Revenue." |
Canadian Natural Resources Limited | 26 | Year Ended December 31, 2018 |
Additional Information Concerning Future Net Revenue
The following table summarizes the undiscounted future net revenue as at December 31, 2018 using forecast prices and costs. Abandonment and reclamation costs included in the calculation of the future net revenue 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, 2018. The Company’s estimated ARO at December 31, 2018 was $12,312 million, unescalated and undiscounted (escalated and discounted at 10%, ARO at December 31, 2018 was $1,456 million). Approximately $8,717 million of this unescalated and undiscounted amount was also included in the future net revenue and is escalated at 2.0% per year after 2019. Specifically, for North America (excluding SCO assets), future net revenue includes the costs associated with abandonment and reclamation of wells (wells, well sites, well site equipment and pipelines) with assigned reserves. For SCO assets, future net revenue includes the costs associated with the abandonment and reclamation of the mine site and all mining facilities. In addition, the future net revenue for Horizon assets also includes abandonment and reclamation of the upgrading facilities. For North Sea and Offshore Africa, future net revenue includes the costs associated with the abandonment and reclamation of offshore wells and facilities with assigned reserves.
Total Future Net Revenue (Undiscounted) | ||||||||||||||||
North America | North Sea | Offshore Africa | Total | |||||||||||||
MM$ | Proved | Proved plus Probable | Proved | Proved plus Probable | Proved | Proved plus Probable | Proved | Proved plus Probable | ||||||||
Revenue | 958,011 | 1,288,755 | 13,308 | 21,629 | 7,334 | 10,122 | 978,653 | 1,320,506 | ||||||||
Royalties | 158,276 | 222,801 | 28 | 47 | 239 | 352 | 158,543 | 223,200 | ||||||||
Production Costs | 304,520 | 393,252 | 5,927 | 8,659 | 2,507 | 2,466 | 312,954 | 404,377 | ||||||||
Development Costs | 76,525 | 99,931 | 1,502 | 1,943 | 807 | 932 | 78,834 | 102,806 | ||||||||
Abandonment and Reclamation Costs – Future Development | 416 | 752 | — | — | 44 | 78 | 460 | 830 | ||||||||
Abandonment and Reclamation Costs – Existing Development | 12,760 | 13,973 | 1,692 | 1,692 | 307 | 307 | 14,759 | 15,972 | ||||||||
Future Net Revenue Before Income Taxes | 405,514 | 558,046 | 4,159 | 9,288 | 3,430 | 5,987 | 413,103 | 573,321 | ||||||||
Income Taxes | 105,860 | 146,719 | 1,579 | 3,603 | 798 | 1,431 | 108,237 | 151,753 | ||||||||
Future Net Revenue After Income Taxes (1) | 299,654 | 411,327 | 2,580 | 5,685 | 2,632 | 4,556 | 304,866 | 421,568 | ||||||||
(1) | Future net revenue is prior to provision for interest, general and administrative expenses and the impact of any risk management activities. |
Canadian Natural Resources Limited | 27 | Year Ended December 31, 2018 |
The following table summarizes the future net revenue by product type as at December 31, 2018 using forecast prices and costs. The net present values of the future net revenue for each product type includes the forecast estimates of abandonment and reclamation costs attributable to future development activity. The net present value of the future net revenue for the “Abandonment and Reclamation Costs - Existing Development” contains certain costs already included in the Company’s ARO for development existing as at December 31, 2018, which are not applied at the product type level.
Future Net Revenue By Product Type | |||||
Reserves Category | Product Type | Future Net Revenue Before Income Taxes (discounted at 10%/year) (MM$) | Unit Value ($/BOE) (1) | ||
Proved Reserves | Light and Medium Crude Oil (including solution gas and other by-products) | 11,381 | 22.45 | ||
Primary Heavy Crude Oil (including solution gas) | 2,863 | 18.41 | |||
Pelican Lake Heavy Crude Oil (including solution gas) | 4,209 | 17.71 | |||
Bitumen (Thermal Oil) | 15,811 | 12.48 | |||
Synthetic Crude Oil | 66,689 | 13.03 | |||
Natural Gas (including by-products but excluding solution gas and by-products from oil wells) | 6,852 | 6.35 | |||
Abandonment and Reclamation Costs – Existing Development | (1,206 | ) | |||
Total | 106,599 | 12.75 | |||
Proved Plus Probable Reserves | Light and Medium Crude Oil (including solution gas and other by-products) | 16,865 | 23.31 | ||
Primary Heavy Crude Oil (including solution gas) | 4,038 | 18.92 | |||
Pelican Lake Heavy Crude Oil (including solution gas) | 5,659 | 16.75 | |||
Bitumen (Thermal Oil) | 21,785 | 8.79 | |||
Synthetic Crude Oil | 74,353 | 12.65 | |||
Natural Gas (including by-products but excluding solution gas and by-products from oil wells) | 9,588 | 6.10 | |||
Abandonment and Reclamation Costs – Existing Development | (1,262 | ) | |||
Total | 131,026 | 11.70 | |||
(1) | Unit values are based on company net reserves. |
Canadian Natural Resources Limited | 28 | Year Ended December 31, 2018 |
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, 2018. The following is a summary of the Sproule price forecast. All prices increase at a rate of 2% per year after 2023.
2019 | 2020 | 2021 | 2022 | 2023 | ||||||
Crude Oil and NGLs | ||||||||||
WTI (1) (US$/bbl) | 63.00 | 67.00 | 70.00 | 71.40 | 72.83 | |||||
WCS (2) (C$/bbl) | 59.47 | 62.31 | 67.45 | 69.53 | 71.66 | |||||
Canadian Light Sweet (3) (C$/bbl) | 75.27 | 77.89 | 82.25 | 84.79 | 87.39 | |||||
Cromer LSB (4) (C$/bbl) | 75.27 | 76.89 | 81.25 | 83.79 | 86.39 | |||||
Edmonton C5+ (5) (C$/bbl) | 75.32 | 80.00 | 83.75 | 85.50 | 87.29 | |||||
North Sea Brent (6) (US$/bbl) | 70.00 | 72.00 | 73.00 | 74.46 | 75.95 | |||||
Natural Gas | ||||||||||
AECO (7) (C$/MMBtu) | 1.95 | 2.44 | 3.00 | 3.21 | 3.30 | |||||
BC Westcoast Station 2 (8) (C$/MMBtu) | 1.35 | 1.94 | 2.60 | 2.81 | 2.90 | |||||
Henry Hub (9) (US$/MMBtu) | 3.00 | 3.25 | 3.50 | 3.57 | 3.64 | |||||
(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 (40o 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 (35o 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 0.77 US$/C$ for 2019, and 0.80 US$/C$ after 2019 was used in the 2018 evaluation.
Production and capital costs are escalated at Sproule’s cost inflation rate of 0% per year for 2019 and 2% per year after 2019 for all products.
The Company’s 2018 average pricing, net of blending costs and excluding risk management activities, was $74.20/bbl for light and medium crude oil, $38.98/bbl for primary heavy crude oil, $43.30/bbl for Pelican Lake heavy crude oil, $33.66/bbl for bitumen (thermal oil), $68.61/bbl for SCO, $40.64 for NGLs, and $2.61/Mcf for natural gas.
Canadian Natural Resources Limited | 29 | Year Ended December 31, 2018 |
Reconciliation of Company Gross Reserves
As of December 31, 2018
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, 2017 | 171 | 198 | 327 | 1,350 | 5,264 | 6,730 | 229 | 8,661 | ||||||||
Discoveries | — | — | — | — | — | — | — | — | ||||||||
Extensions | 12 | 14 | — | 171 | 808 | 122 | 9 | 1,034 | ||||||||
Infill Drilling | 17 | 6 | — | 4 | — | 470 | 38 | 143 | ||||||||
Improved Recovery | — | — | 1 | 2 | — | 3 | — | 4 | ||||||||
Acquisitions | 3 | 2 | — | — | — | 82 | 4 | 22 | ||||||||
Dispositions | — | (5 | ) | — | — | — | (3 | ) | — | (5 | ) | |||||
Economic Factors | — | 1 | 1 | — | — | (305 | ) | (4 | ) | (53 | ) | |||||
Technical Revisions | 10 | (2 | ) | (1 | ) | 52 | 175 | 42 | 6 | 247 | ||||||
Production | (19 | ) | (32 | ) | (23 | ) | (39 | ) | (156 | ) | (544 | ) | (15 | ) | (374 | ) |
December 31, 2018 | 194 | 182 | 305 | 1,540 | 6,091 | 6,597 | 267 | 9,679 | ||||||||
North Sea | ||||||||||||||||
December 31, 2017 | 120 | 21 | 124 | |||||||||||||
Discoveries | — | — | — | |||||||||||||
Extensions | — | — | — | |||||||||||||
Infill Drilling | 1 | — | 1 | |||||||||||||
Improved Recovery | — | — | — | |||||||||||||
Acquisitions | 8 | — | 8 | |||||||||||||
Dispositions | — | — | — | |||||||||||||
Economic Factors | 5 | — | 5 | |||||||||||||
Technical Revisions | (6 | ) | 18 | (3 | ) | |||||||||||
Production | (9 | ) | (12 | ) | (11 | ) | ||||||||||
December 31, 2018 | 119 | 27 | 124 | |||||||||||||
Offshore Africa | ||||||||||||||||
December 31, 2017 | 83 | 20 | 86 | |||||||||||||
Discoveries | — | — | — | |||||||||||||
Extensions | — | — | — | |||||||||||||
Infill Drilling | — | — | — | |||||||||||||
Improved Recovery | — | — | — | |||||||||||||
Acquisitions | — | — | — | |||||||||||||
Dispositions | — | — | — | |||||||||||||
Economic Factors | — | — | — | |||||||||||||
Technical Revisions | 10 | 17 | 13 | |||||||||||||
Production | (7 | ) | (9 | ) | (9 | ) | ||||||||||
December 31, 2018 | 86 | 28 | 90 | |||||||||||||
Total Company | ||||||||||||||||
December 31, 2017 | 374 | 198 | 327 | 1,350 | 5,264 | 6,771 | 229 | 8,871 | ||||||||
Discoveries | — | — | — | — | — | — | — | — | ||||||||
Extensions | 12 | 14 | — | 171 | 808 | 122 | 9 | 1,034 | ||||||||
Infill Drilling | 18 | 6 | — | 4 | — | 470 | 38 | 144 | ||||||||
Improved Recovery | — | — | 1 | 2 | — | 3 | — | 4 | ||||||||
Acquisitions | 11 | 2 | — | — | — | 82 | 4 | 30 | ||||||||
Dispositions | — | (5 | ) | — | — | — | (3 | ) | — | (5 | ) | |||||
Economic Factors | 5 | 1 | 1 | — | — | (305 | ) | (4 | ) | (48 | ) | |||||
Technical Revisions | 14 | (2 | ) | (1 | ) | 52 | 175 | 77 | 6 | 257 | ||||||
Production | (35 | ) | (32 | ) | (23 | ) | (39 | ) | (156 | ) | (565 | ) | (15 | ) | (394 | ) |
December 31, 2018 | 399 | 182 | 305 | 1,540 | 6,091 | 6,652 | 267 | 9,893 | ||||||||
Canadian Natural Resources Limited | 30 | Year Ended December 31, 2018 |
PROBABLE
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, 2017 | 68 | 74 | 142 | 1,230 | 799 | 2,790 | 106 | 2,884 | ||||||||
Discoveries | — | — | — | — | — | — | — | — | ||||||||
Extensions | 4 | 7 | — | 59 | 71 | 93 | 5 | 162 | ||||||||
Infill Drilling | 6 | 2 | — | 1 | — | 391 | 22 | 97 | ||||||||
Improved Recovery | 1 | — | 2 | 2 | — | 1 | — | 4 | ||||||||
Acquisitions | 1 | 1 | — | 403 | — | 22 | 1 | 410 | ||||||||
Dispositions | — | (1 | ) | — | — | — | (2 | ) | — | (2 | ) | |||||
Economic Factors | (1 | ) | — | — | — | — | (104 | ) | (1 | ) | (19 | ) | ||||
Technical Revisions | (5 | ) | (13 | ) | (4 | ) | (176 | ) | 71 | (155 | ) | (3 | ) | (157 | ) | |