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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, 2007 Commission File Number: 333-146056
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))
2500, 855-2ND STREET S.W., CALGARY, ALBERTA, CANADA, T2P 4J8
TELEPHONE: (403) 517-7345
(Address and telephone number of Registrant's principal executive offices)
CT CORPORATION SYSTEM, 111-8TH AVENUE, NEW YORK, NEW YORK 10011
(212) 894-8940
(Name, address (including zip code) and telephone
number (including area code) of agent for
service in the United States)
SECURITIES REGISTERED OR TO BE REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
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
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.
539,728,829 Common Shares outstanding as of December 31, 2007
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Indicate by check mark whether the Registrant is furnishing the information
contained in this Form 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 filing 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 [__]
This Annual Report on Form 40-F shall be incorporated by reference into, or as
an exhibit to, as applicable, the Registrant's Registration Statement on Form
F-9 (Registration No. 333-146056) under the Securities Act of 1933.
All dollar amounts in this Annual Report on Form 40-F are expressed in Canadian
dollars. As of March 26, 2008, the noon buying rate for Canadian Dollars as
expressed by the Federal Reserve Bank of New York was US$1.0180 equals C$ 1.00.
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
Annual Information Form of Canadian Natural Resources Limited ("Canadian
Natural") for the year ended December 31, 2007.
B. AUDITED ANNUAL FINANCIAL STATEMENTS
Canadian Natural's audited consolidated financial statements for the
years ended December 31, 2007 and 2006, including the auditor's report
with respect thereto. For a reconciliation of important differences
between Canadian and United States generally accepted accounting
principles, see Note 17 of the notes to the consolidated financial
statements.
C. MANAGEMENT'S DISCUSSION AND ANALYSIS
Canadian Natural's Management's Discussion and Analysis for the year
ended December 31, 2007.
SUPPLEMENTARY OIL & GAS INFORMATION
For Canadian Natural's Supplementary Oil & Gas Information for the year ended
December 31, 20007, see Exhibit 1 of this Annual Report on Form 40-F.
C A N A D I A N N A T U R A L R E S O U R C E S L I M I T E D
ANNUAL INFORMATION FORM
MARCH 27, 2008
TABLE OF CONTENTS
DEFINITIONS...................................................................3
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS.............................5
RISK FACTORS..................................................................7
REGULATORY MATTERS...........................................................10
ENVIRONMENTAL MATTERS........................................................11
THE COMPANY..................................................................13
GENERAL DEVELOPMENT OF THE BUSINESS..........................................14
DESCRIPTION OF THE BUSINESS..................................................16
A. PRINCIPAL CRUDE OIL, NATURAL GAS AND OIL SANDS PROPERTIES...............17
DRILLING ACTIVITY...................................................18
PRODUCING CRUDE OIL AND NATURAL GAS WELLS...........................19
NORTHEAST BRITISH COLUMBIA..........................................19
NORTHWEST ALBERTA...................................................20
NORTHERN PLAINS.....................................................21
SOUTHERN PLAINS AND SOUTHEAST SASKATCHEWAN..........................23
HORIZON OIL SANDS PROJECT...........................................24
UNITED KINGDOM NORTH SEA............................................26
OFFSHORE WEST AFRICA................................................27
COTE D'IVOIRE.......................................................27
GABON...............................................................28
B. CONVENTIONAL CRUDE OIL, NGLS AND NATURAL GAS RESERVES...................29
C. RECONCILIATION OF CHANGES IN NET CONVENTIONAL RESERVES..................34
D. OIL SANDS MINING DISCLOSURE.............................................35
E. CRUDE OIL, NGLS AND NATURAL GAS PRODUCTION..............................42
F. HISTORICAL DRILLING ACTIVITY BY PRODUCT.................................47
G. NET CAPITAL EXPENDITURES................................................47
H. UNDEVELOPED ACREAGE.....................................................49
I. DEVELOPED ACREAGE.......................................................49
SELECTED FINANCIAL INFORMATION...............................................50
CAPITAL STRUCTURE............................................................51
MARKET FOR CANADIAN NATURAL RESOURCES LIMITED SECURITIES.....................52
DIVIDEND HISTORY.............................................................53
TRANSFER AGENTS AND REGISTRAR................................................53
CANADIAN NATURAL RESOURCES LIMITED 1
DIRECTORS AND OFFICERS.......................................................54
CONFLICTS OF INTEREST........................................................59
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS...................59
AUDIT COMMITTEE INFORMATION..................................................60
LEGAL PROCEEDINGS............................................................61
MATERIAL CONTRACTS...........................................................61
INTERESTS OF EXPERTS.........................................................61
ADDITIONAL INFORMATION.......................................................61
SCHEDULE "A" REPORT ON RESERVES DATA.........................................62
SCHEDULE "B" REPORT OF MANAGEMENT AND DIRECTORS..............................65
SCHEDULE "C" CHARTER OF THE AUDIT COMMITTEE..................................67
2 CANADIAN NATURAL RESOURCES LIMITED
DEFINITIONS
The following are definitions of selected abbreviations used in this Annual
Information Form:
"ARO" means Asset Retirement Obligation
"BBL" or "BARREL" means 34.972 Imperial gallons or 42 US gallons
"BCF" means one billion cubic feet
"BBL/D" means barrels per day
"BOE" means barrel of oil equivalent
"BOE/D" means barrel of oil equivalent per day
"CO2" means carbon dioxide
"CO2E" means carbon dioxide equivalents
"CANADIAN NATURAL RESOURCES LIMITED", "CANADIAN NATURAL", or "COMPANY" means
Canadian Natural Resources Limited and includes, where applicable, reference to
subsidiaries of and partnership interests held by Canadian Natural Resources
Limited and its subsidiaries
"CBM" means coal bed methane
"CONVENTIONAL CRUDE OIL, NGLS AND NATURAL GAS" includes all of the Company's
light and medium crude oil, heavy crude oil, thermal in-situ, natural gas, coal
bed methane and natural gas liquid activities. It does not include the Company's
oil sands mining assets
"DEVELOPMENT WELL" means a well drilled into a zone that is known to be
productive and expected to produce crude oil or natural gas in the future
"DRY WELL" means a well drilled that is not capable of producing commercial
quantities of crude oil or natural gas to justify completion - a dry well will
be plugged back, abandoned and reclaimed
"EXPLORATORY WELL" means a well drilled into an unproved territory with the
intention to discover commercial quantities of crude oil or natural gas
"FPSO" means a Floating Production, Storage and Offtake vessel
"GHG" means greenhouse gas
"GROSS ACRES" means the total number of acres in which the Company holds a
working interest or the right to earn a working interest
"GROSS WELLS" means the total number of wells in which the Company has a working
interest
"HORIZON PROJECT" means the Horizon Oil Sands Project
"MBBL" means one thousand barrels
"MCF" means one thousand cubic feet
"MCF/D" means one thousand cubic feet per day
"MMBBL" means one million barrels
"MMBTU" means one million British thermal units
"MMCF" means one million cubic feet
"MMCF/D" means one million cubic feet per day
CANADIAN NATURAL RESOURCES LIMITED 3
"NGLS" means natural gas liquids
"NET ACRES" refers to gross acres multiplied by the percentage working interest
therein owned or to be owned by the Company
"NET WELLS" refers to gross wells multiplied by the percentage working interest
therein owned or to be owned by the Company
"PRODUCTIVE WELL" means a well that is not a dry well
"PRT" means Petroleum Revenue Tax
"SAGD" means steam-assisted gravity drainage
"SCO" means synthetic light crude oil
"SEC" means United States Securities and Exchange Commission
"UNDEVELOPED ACREAGE" refers to lands on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of crude oil and natural gas
"US" means United States
"WORKING INTEREST" means the interest held by the Company in a crude oil or
natural gas property, which interest normally bears its proportionate share of
the costs of exploration, development, and operation as well as any royalties or
other production burdens
"WTI" means West Texas Intermediate
4 CANADIAN NATURAL RESOURCES LIMITED
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements in this document or documents incorporated herein by
reference constitute forward-looking statements or information (collectively
referred to herein as "forward-looking statements") within the meaning of
applicable securities legislation. Forward-looking statements can be identified
by the words "believe", "anticipate", "expect", "plan", "estimate", "target",
"continue", "could" "intend", "may", "potential", "predict", "should", "will",
"objective", "project", "forecast", "goal", "guidance", "outlook", "effort"
"seeks", "schedule" or expressions of a similar nature suggesting future outcome
or statements regarding an outlook. 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 crude oil and natural gas reserves and in projecting future
rates of production and the timing of development expenditures. The total amount
or timing of actual future production may vary significantly from reserve and
production estimates. In addition, these statements are not guarantees of future
performance and are subject to certain risks and the reader should not place
undue reliance on these forward-looking statements as there can be no assurance
that the plans, initiatives or expectations upon which they are based will
occur.
The forward-looking statements are based on current expectations, estimates and
projections about Canadian Natural Resources Limited (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, uncertainties and
other factors 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
factors include, among others: general economic and business conditions which
will, among other things, impact demand for and market prices of the Company's
products; volatility of and assumptions regarding crude oil and natural gas
prices; fluctuations in currency and interest rates; assumptions on which the
Company's current guidance is based; economic conditions in the countries and
regions in which the Company conducts business; political uncertainty, including
actions of or against terrorists, insurgent groups or other conflict including
conflict between states; industry capacity; ability of the Company to implement
its business strategy, including exploration and development activities; impact
of competition; the Company's defense of lawsuits; availability and cost of
seismic, drilling and other equipment; ability of the Company and its
subsidiaries to complete its capital programs; the Company's and its
subsidiaries' ability to secure adequate transportation for its products;
unexpected difficulties in mining, extracting or upgrading the Company's bitumen
products; potential delays or changes in plans with respect to exploration or
development projects or capital expenditures; ability of the Company to attract
the necessary labour required to build its thermal and oil sands mining
projects; operating hazards and other difficulties inherent in the exploration
for and production and sale of crude oil and natural gas; availability and cost
of financing; the Company's and its subsidiaries' success of exploration and
development activities and their ability to replace and expand crude oil and
natural gas reserves; timing and success of integrating the business and
operations of acquired companies; production levels; imprecision of reserve
estimates and estimates of recoverable quantities of crude oil, bitumen, natural
gas and liquids not currently classified as proved; actions by governmental
authorities; government regulations and the expenditures required to comply with
them (especially safety and environmental laws and regulations and the impact of
climate change initiatives on capital and operating costs); asset retirement
obligations; the adequacy of the Company's provision for taxes; and other
circumstances affecting revenues and expenses. Certain of these factors are
discussed in more detail under the heading "Risk Factors". The Company's
operations have been, and at times in the future may be affected by political
developments and by federal, provincial and local laws and regulations such as
restrictions on production, changes in taxes, royalties and other amounts
payable to governments or governmental agencies, price or gathering rate
controls and environmental protection regulations. Should one or more of these
risks or uncertainties materialize, or should any of the Company's assumptions
prove incorrect, actual results may vary in material respects from those
projected in the forward-looking statements. The impact of any one factor on a
particular forward-looking statement is not determinable with certainty as such
factors are interdependent upon other factors, and the Company's course of
action would depend upon its assessment of the future considering all
information then available.
Readers are cautioned that the foregoing list of important factors is not
exhaustive. Unpredictable or unknown factors not discussed in this report could
also have material adverse effects on forward-looking statements. Although the
Company believes that the expectations conveyed by the forward-looking
statements are reasonable based on information available to it on the date such
forward-looking statements are made, no assurances can be given as to future
results, levels of activity and achievements. All subsequent forward-looking
statements, whether written or oral, attributable to the Company or persons
acting on its behalf are expressly qualified in their entirety by these
cautionary statements. Except as required by law, the Company assumes no
obligation to update forward-looking statements should circumstances or
Management's estimates or opinions change.
CANADIAN NATURAL RESOURCES LIMITED 5
SPECIAL NOTE REGARDING CURRENCY, PRODUCTION AND RESERVES
In this document, all references to dollars refer to Canadian dollars unless
otherwise stated. Reserves and production data is presented on a before
royalties basis unless otherwise stated. In addition, reference is made to crude
oil and natural gas in common units called barrel of oil equivalent ("boe"). A
boe is derived by converting six thousand cubic feet of natural gas to one
barrel of crude oil (6mcf:1bbl). This conversion may be misleading, particularly
if used in isolation, since the 6mcf:1bbl ratio is based on an energy
equivalency at the burner tip and does not represent the value equivalency at
the well head.
For the year ended December 31, 2007, the Company retained qualified independent
reserve evaluators, Sproule Associates Limited ("Sproule") and Ryder Scott
Company ("Ryder Scott") to evaluate 100% of the Company's conventional proved,
as well as proved and probable crude oil, NGLs and natural gas reserves and
prepare Evaluation Reports on these reserves. Conventional crude oil, NGLs and
natural gas includes all of the Company's light/medium, primary heavy, and
thermal crude oil, natural gas, coal bed methane and NGLs activities. It does
not include the Company's oil sands mining assets. Conventional crude oil, NGLs,
and natural gas reserves, net of royalties, are estimated using royalty
regulations in effect as of December 31, 2007. Similarly, bitumen and synthetic
crude oil reserves, net of royalties, relating to surface mineable oil sand
projects are estimated using royalty regulations in effect as of December 31,
2007. Royalty changes proposed by the Government of Alberta will be incorporated
in the reserves evaluation should they be enacted. Sproule evaluated the
Company's North America conventional assets and Ryder Scott evaluated the
international conventional assets. The Company has been granted an exemption
from National Instrument 51-101 - "Standards of Disclosure for Oil and Gas
Activities" ("NI 51-101"), which prescribes the standards for the preparation
and disclosure of reserves and related information for companies listed in
Canada. This exemption allows the Company to substitute SEC requirements for
certain disclosures required under NI 51-101. There are three principal
differences between the two standards. The first is the requirement under NI
51-101 to disclose both proved and proved and probable reserves, as well as the
related net present value of future net revenues using forecast prices and
costs. The second is in the definition of proved reserves; however, as discussed
in the Canadian Oil and Gas Evaluation Handbook ("COGEH"), the standards that NI
51-101 employs, the difference in estimated proved reserves based on constant
pricing and costs between the two standards is not material. The third is the
requirement to disclose a gross reserve reconciliation (before the consideration
of royalties). The Company discloses its reserve reconciliation net of royalties
in adherence to SEC requirements.
For the year ended December 31, 2007, the Company retained a qualified
independent reserves evaluator, GLJ Petroleum Consultants Ltd. ("GLJ"), to
evaluate 100% of Phases 1 through 3 of the Company's Horizon Project and prepare
an Evaluation Report on the Company's proved, as well as proved and probable oil
sands mining reserves incorporating both the mining and upgrading projects.
These reserves were evaluated adhering to the requirements of SEC Industry Guide
7 using year-end constant pricing and have been disclosed separately from the
Company's conventional proved and proved and probable crude oil, NGLs and
natural gas reserves.
The Company annually discloses proved conventional reserves and the Standardized
Measure of discounted future net cash flows using year-end constant prices and
costs as mandated by the SEC in the supplementary crude oil and natural gas
information section of the Company's Annual Report. The Company has elected to
provide the net present value of these same conventional proved reserves as well
as its conventional proved and probable reserves and the net present value of
these reserves under the same parameters as voluntary additional information.
Net present values of conventional reserves are based upon discounted cash flows
prior to the consideration of income taxes and existing asset abandonment
liabilities. Only future development costs and associated material well
abandonment liabilities have been applied. The Company has also elected to
provide both proved, and proved and probable conventional reserves and the net
present value of these reserves using forecast prices and costs as voluntary
additional information, which is disclosed in this Annual Information Form.
The Reserve Committee of the Company's Board of Directors has met with and
carried out independent due diligence procedures with each of Sproule, Ryder
Scott and GLJ to review the qualifications of and procedures used by each
evaluator in determining the estimate of the Company's quantities and net
present value of remaining conventional crude oil, NGLs and natural gas reserves
as well as the Company's quantity of oil sands mining reserves.
SPECIAL NOTE REGARDING NON-GAAP FINANCIAL MEASURES
Management's Discussion and Analysis ("MD&A") includes references to financial
measures commonly used in the crude oil and natural gas industry, such as cash
flow from operations, adjusted net earnings from operations and net asset value.
These financial measures are not defined by generally accepted accounting
principles ("GAAP") and therefore are referred to as non-GAAP measures. The
non-GAAP measures used by the Company may not be comparable to similar measures
presented by other companies. The Company uses these non-GAAP measures to
evaluate its performance. The non-GAAP measures should not be considered an
alternative to or more meaningful than net earnings, as determined in accordance
with Canadian GAAP, as an indication of the Company's performance.
6 CANADIAN NATURAL RESOURCES LIMITED
RISK FACTORS
VOLATILITY OF CRUDE OIL AND NATURAL GAS PRICES
The Company's financial condition is substantially dependent on, and highly
sensitive to, the prevailing prices of crude oil and natural gas. Fluctuations
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 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
availability of alternate fuel sources and weather conditions. Natural gas
prices realized by the Company are affected primarily in North America by supply
and demand, weather conditions and prices of alternate sources of energy,
including liquefied natural gas. 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 or curtailment
in production at some properties or resulting unutilized long-term
transportation commitments, all of which could have a material adverse effect on
Canadian Natural's revenues, net earnings and cash flows.
Canadian Natural conducts an annual assessment of the carrying value of its
assets in accordance with Canadian GAAP. If crude oil and natural gas prices
decline, the carrying value of the assets could be subject to downward
revisions, and net earnings could be adversely affected.
Approximately 26% of the Company's 2007 production on a boe basis was primary
and thermal heavy crude oil. The market prices for heavy crude oil differ from
the established market indices for light and medium grades of crude oil, due
principally to the higher transportation and refining costs associated with
heavy crude oil. As a result, the price received for heavy crude oil is
generally lower than the price for medium and light crude oil, and the
production costs associated with heavy crude oil may be higher than for lighter
grades. Future differentials are uncertain and any increase in the heavy crude
oil differentials could have a material adverse effect on the Company's
business.
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 and other federal, provincial, state and
municipal laws and regulations, as well as international conventions
(collectively, "environmental legislation").
Environmental legislation imposes, among other things, restrictions, liabilities
and obligations in connection with the generation, handling, storage,
transportation, treatment and disposal of hazardous substances and waste and in
connection with spills, releases and emissions of various substances to the
environment. Environmental legislation also requires that wells, facility sites
and other properties associated with the Company's operations be operated,
maintained, abandoned and reclaimed to the satisfaction of applicable regulatory
authorities. In addition, certain types of operations, including exploration and
development projects and significant changes to certain existing projects, may
require the submission and approval of environmental impact assessments or
permit applications. Compliance with environmental legislation can require
significant expenditures and failure to comply with environmental legislation
may result in the imposition of fines and penalties. The costs of complying with
environmental legislation in the future may have a material adverse effect on
Canadian Natural's financial condition or results of operations.
The crude oil and natural gas industry is experiencing incremental increases in
costs related to environmental regulation, particularly in North America and the
North Sea. Existing and expected legislation and regulations will require the
Company to address and mitigate the effect of its activities on the environment.
Increasingly stringent laws and regulations may have an adverse effect on the
Company's future net earnings and cash flow from operations.
CANADIAN NATURAL RESOURCES LIMITED 7
GREENHOUSE GAS AND OTHER AIR EMISSIONS
The Company is concurrently working with legislators and regulators as they
develop and implement new GHG emission laws and regulations. Internally, the
Company is pursuing an integrated emissions reduction strategy, to ensure that
it is able to comply with existing and future emission reductions requirements.
The Company continues to develop strategies that will enable it to deal with the
risks and opportunities associated with new GHG and air emissions policies. In
addition, the Company is working with relevant parties to ensure that new
policies encourage innovation, energy efficiency, targeted research and
development while not impacting competitiveness.
In Canada, the Federal government has indicated its intent to develop
regulations that would be in effect in 2010 to address industrial GHG emissions.
The Federal Government has also outlined national and sectoral reduction targets
for several categories of air pollutants. In Alberta, GHG regulations came into
effect July 1, 2007, affecting facilities emitting more than 100 kilotonnes of
CO2e annually. Two Canadian Natural facilities, the Primrose/Wolf Lake in-situ
heavy oil and the Hays sour gas plant, are captured under the regulations. In
the UK, greenhouse gas regulations have been in effect since 2005. During Phase
1 (2005-2007) of the UK National Allocation Plan the Company operated below its
CO2 allocation. For Phase 2 (2008-2012) the Company's CO2 allocation has been
decreased below the Company's estimated current operations emissions. The
Company continues to focus on implementing reduction programs based on
efficiency audits of its major facilities to reduce CO2 emissions and on trading
mechanisms to ensure compliance with any requirement now in effect.
There are a number of unresolved issues in relation to Canadian Federal and
Provincial GHG regulatory requirements. Key among them is an appropriate common
facility emission threshold, availability and duration of compliance mechanisms
and resolution of federal/provincial harmonization agreements. The Company
continues to pursue GHG emission reduction initiatives including solution gas
conservation, CO2 capture and sequestration in oil sands tailings, CO2 capture
and storage in association with enhanced oil recovery and participation in an
industry initiative to promote an integrated CO2 capture and storage network.
The additional requirements of enacted or proposed GHG legislation on the
Company's operations will increase capital expenditures and operating expenses,
especially those related to the Horizon Project and the Company's other existing
and planned large oil sands projects. This may have an adverse effect on the
Company's net earnings and cash flow from operations.
Air pollutant standards and guidelines are being developed federally and
provincially and the Company is participating in these discussions. Ambient air
quality and sector based reductions in air emissions are being reviewed. Through
participation of the Company and the industry with stakeholders, guidelines have
been developed that adopt a structured process to emission reductions that is
commensurate with technological development and operational requirements.
NEED TO REPLACE RESERVES
Canadian Natural's future crude oil and natural gas reserves and production, and
therefore its cash flows and results of operations, are highly dependent upon
success in exploiting its current reserve base and acquiring or discovering
additional reserves. Without additions to reserves through exploration,
acquisition or development activities, the Company's production will decline
over time as reserves are depleted. The business of exploring for, developing or
acquiring reserves is capital intensive. To the extent the Company's cash flows
from operations are insufficient to fund capital expenditures and external
sources of capital become limited or unavailable, the Company's ability to make
the necessary capital investments to maintain and expand its crude oil and
natural gas reserves will be impaired. In addition, Canadian Natural may be
unable to find and develop or acquire additional reserves to replace its crude
oil and natural gas production at acceptable costs.
COMPETITION IN ENERGY INDUSTRY
The energy industry is highly competitive in all aspects, including the
exploration for, and the development of, new sources of supply, the construction
and operation of crude oil and natural gas pipelines and facilities, the
acquisition of crude oil and natural gas interests and the transportation and
marketing of crude oil, natural gas, NGLs and electricity. Canadian Natural will
compete not only among participants in the energy industry, but also between
petroleum products and other energy sources. The Company's competitors will
include integrated oil and natural gas companies and numerous other senior oil
and natural gas companies, some of which may have greater financial and other
resources than the Company.
8 CANADIAN NATURAL RESOURCES LIMITED
OTHER BUSINESS RISKS
Other business risks relate to operational risks, the cost of capital available
to fund exploration and development programs, fluctuation in foreign exchange
rates, the availability of skilled labour and manpower, regulatory issues and
taxation and the requirements of new environmental laws and regulations.
Exploring for, producing and transporting petroleum substances 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 and interruption of operations. The Company has developed a comprehensive
health and safety management framework to mitigate physical risks. The Company
also mitigates insurable risks to protect against significant losses by
maintaining a comprehensive insurance program, while maintaining levels and
amounts of risk within the Company which management believes to be acceptable.
However, Canadian Natural's liability, property and business interruption
insurance may not and possibly will not provide adequate coverage in all
circumstances.
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, risks 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 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 private ownership of crude oil and natural gas properties in
Canada differs distinctly from its ownership interests in foreign crude oil and
natural gas properties. In some foreign countries in which the Company does and
may do business in the future, the state generally retains ownership of the
minerals and consequently retains control of, and in many cases participates in,
the exploration and production of reserves. Accordingly, operations outside of
Canada may be materially affected by host governments through royalty payments,
export taxes and regulations, surcharges, value added taxes, production bonuses
and other charges. In addition, changes in prices and costs of operations,
timing of production and other factors may affect estimates of crude oil and
natural gas reserve quantities and future net cash flows attributable to foreign
properties in a manner materially different than such changes would affect
estimates for Canadian properties. Agreements covering foreign crude oil and
natural gas operations also frequently contain provisions obligating the Company
to spend specified amounts on exploration and development, or to perform certain
operations or forfeit all or a portion of the acreage subject to the contract.
UNCERTAINTY OF RESERVE ESTIMATES
There are numerous uncertainties inherent in estimating quantities of reserves,
including many factors beyond the Company's control. In general, estimates of
economically recoverable crude oil, NGLs and natural gas reserves and the future
net cash flow therefrom are based upon a number of factors and assumptions made
as of the date on which the reserve estimates were determined, such as
geological and engineering estimates which have inherent uncertainties, the
assumed effects of regulation by governmental agencies and estimates of future
commodity prices and operating costs, all of which may vary considerably from
actual results. All such estimates are, to some degree, uncertain and
classifications of reserves are only attempts to define the degree of
uncertainty involved. For these reasons, estimates of the economically
recoverable crude oil, NGLs and natural gas 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, 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 with respect to reserves that may be developed and produced in the
future are often based upon volumetric calculations and upon analogy to similar
types of reserves, rather than upon actual production history. Estimates based
on these methods generally are less reliable than those based on actual
production history. Subsequent evaluation of the same reserves based upon
production history will result in variations, which may be material, in the
estimated reserves.
CANADIAN NATURAL RESOURCES LIMITED 9
PRIORITY OF SUBSIDIARY INDEBTEDNESS; CONSEQUENCES OF HOLDING CORPORATION
STRUCTURE
The Company carries on business through corporate and partnership subsidiaries.
The majority of the Company's assets are held in one or more corporate or
partnership subsidiaries. The results of operations and ability to service
indebtedness, including debt securities, are dependent upon the results of
operations of these subsidiaries and the payment of funds by these subsidiaries
to the Company in the form of loans, dividends or other means employed for the
payment of funds to the Company. In the event of the liquidation of any
corporate or partnership subsidiary, the assets of the subsidiary would be used
first to repay the indebtedness of the subsidiary, including trade payables or
obligations under any guarantees, prior to being used by the Company to pay its
indebtedness.
REGULATORY MATTERS
The Company's business is subject to regulations generally established by
government legislation and governmental agencies. The regulations are summarized
in the following paragraphs.
CANADA
The petroleum and natural gas industry in Canada operates under government
legislation and regulations, which govern exploration, development, production,
refining, marketing, transportation, prevention of waste and other activities.
The Company's Canadian properties are primarily located in Alberta, British
Columbia, Saskatchewan, Manitoba and the Northwest and Yukon Territories. Most
of these properties are held under leases/licences obtained from the respective
provincial or federal governments, which give the holder the right to explore
for and produce crude oil and natural gas. The remainder of the properties is
held under freehold (private ownership) lands.
Conventional petroleum and natural gas leases issued by the provinces of
Alberta, Saskatchewan and Manitoba have a primary term from two to five years,
and British Columbia leases/licences presently have a term of up to ten years.
Those portions of the leases that are producing or are capable of producing at
the end of the primary term will "continue" for the productive life of the
lease.
The exploration licences in the Northwest and Yukon Territories are administered
by the Federal Government and only grant the right to explore. They have initial
terms of four to five years. A Commercial Discovery Licence must be obtained in
order to produce crude oil and natural gas, which requires approval of a
development plan.
An 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 out of the permit. 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 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 each province. Government
royalties are payable on crude oil, NGLs and natural gas 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.
On October 25, 2007 the Province of Alberta issued the framework of its proposed
changes to the Alberta crude oil and natural gas royalty regime, effective
January 1, 2009. The Company is currently awaiting finalization of the royalty
implementation regulations, however it expects that its 2009 and future Alberta
royalty payments will increase as a result of the proposed royalty changes and
that its level of activity in Alberta in aggregate will be reduced from what it
otherwise would have been in the absence of such royalty changes.
In addition to government royalties, the Company is currently subject to federal
and provincial income taxes in Canada at a combined rate of approximately 32.53%
after allowable deductions.
During 2007, the Canadian Federal Government enacted income tax rate changes
which reduce the Federal corporate income tax rate over the next five years from
21% in 2007 to 15% in 2012.
10 CANADIAN NATURAL RESOURCES LIMITED
UNITED KINGDOM
Under existing law, the UK Government has broad authority to regulate the
petroleum industry, including exploration, development, conservation and rates
of production.
Crude oil and natural gas fields granted development approval before March 16,
1993 are subject to UK Petroleum Revenue Tax ("PRT") of 50% charged on crude oil
and natural gas profits. Approvals granted on or after March 16, 1993 are
exempted from PRT and government royalties. Profits for PRT purposes are
calculated on a field-by-field basis by deducting field operating costs and
field development costs from production and third-party tariff revenue. In
addition, certain statutory allowances are available, which may reduce the PRT
payable.
The Company is subject to UK Corporation Tax ("CT") on its UK profits as
adjusted for CT purposes. PRT paid is deductible for CT purposes. The CT rate,
which became effective April 1, 1999, was set at 30%. In its 2002 budget speech
by the UK Chancellor of the Exchequer, the UK Government announced changes to
taxation policies on UK North Sea crude oil and natural gas production. A
Supplementary Charge Tax ("SCT") of 10%, charged on the same profits as
calculated for "normal" CT but excluding any deduction for financing costs, was
added to the current 30% CT charge. Also the deduction for expenditures on
capital items was changed from 25% per annum to 100% in the year incurred.
During 2005, the UK Chancellor of the Exchequer announced a further increase to
the SCT of 10% to 20% on profits from UK North Sea crude oil and natural gas
production, effective January 1, 2006. In December 2006, the UK Government
announced the abolition of PRT on profits of decommissioned fields subsequently
redeveloped, subject to certain conditions being met.
OFFSHORE WEST AFRICA
Terms of licences, including royalties and taxes payable on production or profit
sharing arrangements, vary by country and, in some cases, by concession within
each country. Development of the Espoir Field on CI-26 and the Baobab Field on
CI-40, in Cote d'Ivoire, are subject to production sharing arrangements that
provide that tax or royalty payments to the Government are deemed to be met from
the Government's share of profit oil. In August 2006, the Government of Cote
d'lvoire announced a reduction in the rate of Corporate Income Tax from 35% to
27%, effective January 1, 2006. Effective January 1, 2008, the Government of
Cote d'lvoire announced a further corporate income tax rate reduction to 25%.
In October 2005, Canadian Natural completed the acquisition of the permit to
develop the Olowi Field, offshore Gabon and received approval of its development
plan for this acquisition from the Gabonese Government in early 2006 and from
Canadian Natural's Board of Directors in November 2006. Development of this
field is under the terms of a production sharing arrangement that provides that
tax or royalty payments to the Government are deemed to be met from the
Government's share of profit oil.
ENVIRONMENTAL MATTERS
The Company carries out its activities in compliance with all relevant regional,
national and international regulations and industry standards. Environmental
specialists in the UK and Canada 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 and Environmental Committee of the Board of Directors.
The Company regularly meets with, and submits to inspections by, the various
governments in the regions where the Company operates. At present, the Company
believes that it meets all existing environmental standards and regulations and
has included appropriate amounts in its capital expenditure budget to continue
to meet current environmental protection requirements. Since these requirements
apply to all operators in the crude oil and natural gas industry, it is not
anticipated that the Company's competitive position within the industry will be
adversely affected by changes in applicable legislation. The Company has
internal procedures designed to ensure that the environmental aspects of new
acquisitions and developments are taken into account prior to proceeding. The
Company's environmental management plan and operating guidelines focus on
minimizing the environmental impact of field operations while meeting regulatory
requirements and corporate standards. The Company's proactive program includes:
an internal environmental compliance audit and inspection program of its
operating facilities; a suspended well inspection program to support future
development or eventual abandonment; appropriate reclamation and decommissioning
standards for wells and facilities ready for abandonment; an effective surface
reclamation program; a due diligence program related to groundwater monitoring;
an active program related to preventing and reclaiming spill sites; a solution
gas reduction and conservation program; a program to replace the majority of
fresh water for steaming with brackish water; environmental planning for all
projects to assess impacts and to implement avoidance, and mitigation programs;
reporting for environmental liabilities; a program to optimize efficiencies at
the Company's operating facilities; and continued evaluation of new technologies
to reduce environmental impacts. The Company has also established stringent
operating standards in four areas: using water-based, environmentally friendly
drilling muds whenever possible; implementing cost effective ways of reducing
CANADIAN NATURAL RESOURCES LIMITED 11
GHG per unit of production; exercising care with respect to all waste produced
through effective waste management plans; and minimizing produced water volumes
onshore and offshore through cost-effective measures. Canadian Natural
participates in both the Canadian federal and provincial regulated GHG
emissions. The Company continues to quantify annual GHG emissions for internal
reporting purposes. The Company has participated in the Canadian Association of
Petroleum Producers ("CAPP") Stewardship Program since 2000 and is currently a
Gold Level Reporter. Canadian Natural continues to invest in proven and new
technologies and in improved operating strategies to help us achieve the
Companies overall goal of a net reduction of GHG emissions per unit of
production.
Canadian Natural is committed to managing air emissions through an integrated
corporate approach which considers opportunities to reduce both air pollutants
and GHG emissions. Air quality programs continue to be an essential part of the
Company's environmental work plan and are operated within all regulatory
standards and guidelines. The Company strategy for managing GHG emissions is
based on four core principles: energy conservation and efficiency; reduced
intensity; innovative technology and associated research and development; and,
trading capacity, both domestically and globally.
The Company continues to implement flaring, venting and fuel and solution gas
conservation programs. In 2007 the Company completed approximately 115 gas
conservation projects, resulting in a reduction of 1.28 million tonnes/year of
CO2e. Over the past five years the Company has spent over $116 million to
conserve the equivalent of over 6.4 million tonnes of CO2e. In heavy crude oil
production Canadian Natural is evaluating tank heater efficiencies in an effort
to conserve fuel gas at facilities with field tanks. The Company also monitors
the performance of its compressor fleet and it is continually modified and
optimized for maximum efficiency. These programs also influence and direct the
Company's plans for new projects and facilities. It is planned that the Horizon
Project will incorporate advancements in technology to reduce further GHG
emissions through maximizing heat integration, the use of cogeneration to meet
steam and electricity demands and the design of the hydrogen production facility
to enable CO2 capture and the sequestration of CO2 in oils sands tailings.
In its North Sea operations the Company continues to focus on implementing
reduction programs based on efficiency audits of its major facilities. The
Produced Water Re-injection trial on Ninian Central continued throughout 2007
during which time approximately 1.5 million cubic meters of produced water were
re-injected to the reservoir. This resulted in approximately 16 tonnes of oil
not being discharged to sea, a reduction of approximately 10%. The trial has
been very successful and will continue through 2008 as a permanent installation.
The costs incurred by the Company for compliance with environmental matters and
site restoration is approximately 3% of the total exploration and development
expenditures incurred by the Company in each of the years ended December 31,
2007, 2006 and 2005.
For 2007, the Company's capital expenditures included $71 million for
abandonment expenditures (2006 - $75 million; 2005 - $46 million).
The Company's estimated undiscounted ARO at December 31, 2007 was as follows:
Estimated ARO, undiscounted ($millions) 2007 2006
--------------------------------------------------------------------------------
North America $ 3,038 $ 2,826
North Sea 1,286 1,543
Offshore West Africa 102 128
4,426 4,497
--------------------------------------------------------------------------------
North Sea PRT recovery (555) (625)
--------------------------------------------------------------------------------
$ 3,871 $ 3,872
================================================================================
The estimate of ARO is based on estimates of future costs to abandon and restore
the wells, production facilities and offshore production platforms. Factors that
affect costs include number of wells drilled, well depth and the specific
environmental legislation. The estimated costs are based on engineering
estimates using current costs in accordance with present legislation and
industry operating practice. The Company's strategy in the North Sea consists of
developing commercial hubs around its core operated properties with the goal of
increasing production, lowering costs and extending the economic lives of its
production facilities, thereby delaying the eventual abandonment dates. The
future abandonment costs incurred in the North Sea are expected to result in an
estimated PRT recovery of $555 million (2006 - $625 million; 2005 - $370
million), as abandonment costs are an allowable deduction in determining PRT and
may be carried back to reclaim PRT previously paid. The expected PRT recovery
reduces the Company's net undiscounted abandonment liability to $3,871 million
(2006 - $3,872 million).
12 CANADIAN NATURAL RESOURCES LIMITED
THE COMPANY
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 2500, 855 -- 2nd Street S.W.,
T2P 4J8.
Canadian Natural formed a wholly owned subsidiary, CanNat Resources Inc.
("CanNat") in January 1995.
Pursuant to a Plan of Arrangement, the Company acquired all of the outstanding
shares of Sceptre Resources Limited ("Sceptre") in September 1996 and in January
1997, Sceptre and CanNat amalgamated pursuant to the BUSINESS CORPORATIONS ACT
(Alberta) under the name CanNat Resources Inc.
Pursuant to an Offer to Purchase all of the outstanding shares, the Company
completed the acquisition of Ranger Oil Limited ("Ranger"), including its
subsidiaries, in July 2000. On October 1, 2000 Ranger and the Company
amalgamated pursuant to the BUSINESS CORPORATIONS ACT (Alberta) under the name
Canadian Natural Resources Limited.
Pursuant to a Plan of Arrangement, the Company acquired all of the outstanding
shares of Rio Alto Exploration Ltd. ("RAX") in July 2002. On January 1, 2003 RAX
and the Company amalgamated pursuant to the BUSINESS CORPORATIONS ACT (Alberta)
under the name Canadian Natural Resources Limited.
On January 1, 2004 CanNat and the Company amalgamated pursuant to the BUSINESS
CORPORATIONS ACT (Alberta) under the name Canadian Natural Resources Limited.
On September 14, 2006, the Company announced entering into an agreement to
acquire Anadarko Canada Corporation, a subsidiary of Anadarko Petroleum
Corporation for net cash consideration of $4,641 million including working
capital and other adjustments. Pursuant to a Purchase and Sale Agreement, the
Company acquired all of the outstanding shares of Anadarko Canada Corporation
effective November 2, 2006. On November 3, 2006 Anadarko Canada Corporation and
a wholly owned subsidiary of the Company, 1266701 Alberta Ltd. amalgamated to
form ACC-CNR Resources Corporation. Subsequently, on January 1, 2007, ACC-CNR
Resources Corporation and Canadian Natural Resources Limited amalgamated and the
amalgamated company continued under the name Canadian Natural Resources Limited.
On January 1, 2008 Ranger Oil (International) Ltd., 764968 Alberta Inc., CNR
International (Norway) Limited, Renata Resources Inc. and the Company
amalgamated pursuant to the BUSINESS CORPORATIONS ACT (Alberta) under the name
Canadian Natural Resources Limited.
The main operating subsidiaries of the Company, each of which is directly or
indirectly wholly-owned, and their jurisdictions of incorporation are as
follows:
NAME OF COMPANY JURISDICTION OF INCORPORATION
--------------- -----------------------------
CanNat Energy Inc. Delaware
CNR (ECHO) Resources Inc. Alberta
CNR International (U. K.)
Investments Limited England
CNR International (U. K.) Limited England
CNR International Cote d'Ivoire SARL Cote d'Ivoire
CNR International (Olowi) Limited Bahamas
CNR Petro Resources Limited Alberta
Horizon Construction Management Ltd. Alberta
Canadian Natural, as the managing partner and CNR (ECHO) Resources Inc. are the
partners of Canadian Natural Resources, a general partnership. Canadian Natural,
as the managing partner, CNR (ECHO) Resources Inc., and Canadian Natural
Resources are partners of Canadian Natural Resources Northern Alberta
Partnership, a general partnership. The two partnerships hold the majority of
the producing Canadian crude oil and natural gas properties of Canadian Natural.
Canadian Natural, as the managing partner, and CNR Petro Resources Limited are
the partners of CNR 2006 Partnership, which holds certain crude oil and natural
gas properties situated in the provinces of Alberta, Saskatchewan and British
Columbia and in the Yukon Territories. The Company also has a 15% interest in
Cold Lake Pipeline Ltd., which is the general partner of Cold Lake Pipeline
Limited Partnership in which Canadian Natural holds a separate 14.7% partnership
interest. Canadian Natural, as the managing partner, and CNR (ECHO) Resources
Inc. are the partners of Canadian Natural Resources 2005 Partnership, a general
partnership which holds certain natural gas facilities situated in Alberta.
The consolidated financial statements of Canadian Natural include the accounts
of the Company and all of its subsidiaries and partnerships.
CANADIAN NATURAL RESOURCES LIMITED 13
GENERAL DEVELOPMENT OF THE BUSINESS
Canadian Natural's business is the acquisition of interests in crude oil and
natural gas rights and the exploration, development, production, marketing and
sale of crude oil and NGLs, natural gas and bitumen production.
The Company initiates, operates and maintains a large working interest in a
majority of the prospects in which it participates. Canadian Natural's objective
is to increase cash flow and net earnings through the development of its
existing crude oil and natural gas properties and through the discovery and
acquisition of new reserves. The Company's principal regions of crude oil and
natural gas operations are in the Western Canadian Sedimentary Basin, the United
Kingdom (the "UK") sector of the North Sea and Offshore West Africa. The Company
has a full complement of management, technical and support staff to pursue these
objectives. As at December 31, 2007 the Company had 3,461 permanent employees in
North America and 334 permanent employees in its international operations.
In February 2005, the Board of Directors of the Company approved Phase 1 of the
Horizon Project. The Horizon Project is designed as a phased development and
includes the mining of bitumen combined with an onsite upgrader. The phased
approach provides the Company with improved cost and project controls including
labour and materials management, and directionally mitigates the effects of
growth on local infrastructure. Phase 1 production is targeted to begin in the
third quarter 2008 ramping up to 110,000 bbl/d of SCO. The Company is also
developing various cost effective options for execution of additional
construction on Phases 2/3. These phases have been further subdivided into four
distinct tranches that will target production expansion to 232,000 bbl/d of SCO
by 2013.
Based upon stratigraphic drilling and the Company's own internal estimates it is
believed that the Company's oil sands leases located near Fort McMurray, Alberta
contain an estimated 6 billion barrels of potentially recoverable bitumen using
existing mining and upgrading technologies. Additional in-situ potential also
exists on the western portions of the leases. The first three phases of the
Horizon Project, which encompasses only a portion of these oil sands leases,
will deliver approximately 39 years of production without the declines normally
associated with petroleum operations. GLJ Petroleum Consultants Ltd. ("GLJ"), a
qualified independent third party petroleum consultant firm, was retained by the
Reserves Committee of Canadian Natural's Board of Directors to evaluate the
mining reserves associated with the Horizon Project. Their report estimated that
3.0 billion barrels of gross lease proved and probable synthetic crude oil
reserves are located on the leases associated with the first three phases of the
Horizon Project.
In August 2005, the Company entered into an agreement to obtain pipeline
transportation service for the Horizon Project. This agreement allows Canadian
Natural to gain access to major sales pipelines out of Edmonton for the
Company's synthetic crude oil which will be produced at the Horizon Project,
while at the same time provides significant quality benefits associated with
being the only shipper on the Horizon Pipeline. The expected twinning of the
existing Alberta Oil Sands Pipeline ("AOSPL"), resulting in two parallel
pipelines, one of which will be dedicated to Canadian Natural, combined with a
new pipeline constructed from the Horizon Project site down to the AOSPL
Terminal (collectively, the "Horizon Pipeline"), will provide crude oil
transportation service for the Horizon Project. The initial term of the
agreement is 25 years, which will commence on the in-service date. In addition
to having the option to renew the agreement for successive 10-year terms,
Canadian Natural has the right to request incremental expansions of the Horizon
Pipeline based upon applicable National Energy Board approved multi-pipeline
economics. The construction of the Horizon Pipeline began in 2006 and is
scheduled to be fully operational by third quarter 2008 to coincide with first
production at the Horizon Project.
In April 2005, the Company monetized, through a sale, a large portion of its
overriding royalty interests on various producing properties throughout Western
Canada and Ontario for proceeds of approximately $345 million. In 2004 these
interests produced approximately 3,700 boe/d and over the 2003 and 2004 fiscal
years cash flow from these interests averaged approximately $50 million per
year. As part of the transaction, the Company purchased 3,858,520 trust units of
Freehold Royalty trust for $60 million and, after the mandatory hold period and
pursuant to an agreement, the trust units were sold to an underwriting group for
a net gain of approximately $11 million.
On June 1, 2005, the Company issued $400 million of 10 year 4.95% unsecured
notes maturing June 1, 2015 pursuant to a short form shelf prospectus dated
August 1, 2003 for the issuance of medium term notes in Canada.
During 2005, the Company completed 96 transactions in the normal course to
acquire additional interests in crude oil and natural gas properties at an
aggregate net expenditure of $134 million. These properties are located in the
Company's principal operating regions and are comprised of producing and
non-producing leases together with related facilities. In addition, the Company
disposed of a large portion of its overriding royalty interests and operated and
non-operated properties not located in the Company's core regions for proceeds
of $454 million.
In January 2006 the Company issued $400 million of 4.50% unsecured notes
maturing January 23, 2013 pursuant to a short form Canadian base shelf
prospectus dated August 29, 2005.
CANADIAN NATURAL RESOURCES LIMITED 14
On August 17, 2006, the Company issued US$250 million of 10 year 6.0% unsecured
notes maturing August 15, 2016 and US$450 million of 30 year 6.50% unsecured
notes maturing February 15, 2037 pursuant to a US short form base shelf
prospectus dated June 3, 2005.
In November 2006, the Company completed the acquisition of Anadarko Canada
Corporation ("ACC") for net cash consideration of $4,641 million, including
working capital and other adjustments. The Company immediately integrated ACC
into its ongoing operations. The land and production base acquired are located
substantially in Western Canada and are natural gas weighted assets with a long
reserve life. At the time, the assets produced in excess of 350 mmcf/d of
natural gas and approximately 9,000 bbl/d of light crude oil and NGLs
production. The assets acquired also included approximately 1.5 million net
undeveloped acres and key strategic facilities in Northeast British Columbia and
Northwest Alberta. In conjunction with the closing of the acquisition of ACC,
the Company executed a $3,850 million, three-year non-revolving syndicated
credit facility maturing in October 2009. In March 2007 $1,500 million of the
credit facility was repaid, reducing the facility to $2,350 million.
During 2006, the Company completed 83 transactions in the normal course to
acquire additional interests in crude oil and natural gas properties. The
aggregate net expenditure of the transactions was $4,801 million, including the
ACC acquisition of $4,755 million. The properties acquired are located in the
Company's principal operating regions and are comprised of producing and
non-producing leases together with related facilities. As well the Company
participated in 48 transactions to dispose of non-core operated and non-operated
properties for proceeds of $68 million. Included in this amount is a royalty
disposition for $66 million.
On March 19, 2007, the Company issued US$1,100 million of 10 year 5.70%
unsecured notes maturing May 15, 2017 and US$1,100 million of 30 year 6.25%
unsecured notes maturing March 15, 2038 pursuant to a US short form base shelf
prospectus dated November 27, 2006.
During 2007, the Company completed 67 transactions in the normal course to
acquire additional interests in crude oil and natural gas properties. The
aggregate net expenditure of the transactions was $70.9 million. The properties
acquired are located in the Company's principal operating regions and are
comprised of producing and non-producing leases together with related
facilities. As well the Company participated in 33 transactions to dispose of
non-core operated and non-operated properties for proceeds of $109.9 million.
On December 18, 2007 the Company issued $400 million of 3 year 5.50% unsecured
notes maturing December 17, 2010 pursuant to a Canadian short form base shelf
prospectus dated September 25, 2007.
On January 17, 2008, the Company issued US$400 million of 5 year 5.15% unsecured
notes maturing February 1, 2013, US$400 million of 10 year 5.90% unsecured notes
maturing February 1, 2018 and US$400 million of 31 year 6.75% unsecured notes
maturing February 1, 2039 pursuant to a US short form base shelf prospectus
dated September 25, 2007.
CANADIAN NATURAL RESOURCES LIMITED 15
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, NGLs, natural gas and bitumen production. The Company's principal
core regions of operations are western Canada, the United Kingdom sector of the
North Sea and Offshore West Africa.
The Company focuses on exploiting its core properties and actively maintaining
cost controls. Whenever possible Canadian Natural takes on significant ownership
levels, operates the properties and attempts to dominate the local land position
and operating infrastructure. 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 presence in existing core
regions.
The Company's business approach is to maintain large project inventories and
production diversification among each of the commodities it produces namely:
natural gas, NGLs, light/medium crude oil, Pelican Lake crude oil, primary heavy
crude oil and thermal heavy crude oil. The Company's operations are centred on
balanced product offerings, which together provide complementary infrastructure
and balance throughout the business cycle. Natural gas is the largest single
commodity sold, accounting for 45% of 2007 production. Virtually all of the
Company's natural gas and NGLs production is located in the Canadian provinces
of Alberta and British Columbia and is marketed in Canada and the United States.
Light/medium crude oil and NGLs, representing 23% of 2007 production, is located
principally in the Company's North Sea and Offshore West Africa properties, with
additional production in the Provinces of Saskatchewan, British Columbia and
Alberta. Primary and thermal heavy crude oil operations in the Provinces of
Alberta and Saskatchewan account for 26% of 2007 production. Other heavy crude
oil, which accounts for 6% of 2007 production, is produced from the Pelican Lake
area in north Alberta. This production, which has medium crude oil netback
characteristics, is developed through a staged horizontal drilling program
complimented by water and polymer flooding. Midstream assets, comprised of three
crude oil pipelines and an electricity co-generation facility, provide cost
effective infrastructure supporting the heavy and Pelican Lake crude oil
operations. Canadian Natural expects its ownership of oil sands leases near Fort
McMurray, Alberta to provide a basis for long-term synthetic crude oil
production growth. The first three phases of the Horizon Project, which
encompasses only a portion of these oil sands leases, are targeted to deliver
approximately 37 years of synthetic crude oil production.
With approximately 12.7 million net acres of core undeveloped land base, the
Company believes it has sufficient project portfolios in each of the product
offerings to provide growth for the next several years.
16 CANADIAN NATURAL RESOURCES LIMITED
A. PRINCIPAL CRUDE OIL, NATURAL GAS AND OIL SANDS PROPERTIES
Set forth below is a summary of the principal crude oil, natural gas and oil
sands properties as at December 31, 2007. The information reflects the working
interests owned by the Company. FPSO's, included under major infrastructure, are
leased by the Company under varying terms.
2007 Average Daily Year Ended Major Infrastructure
Production Rates Dec 31, 2007 As at Dec 31, 2007
---------------------------------------------------------------------------------------------------------------
Region Batteries/
Undeveloped Compressors & Plants/
Crude oil & NGLs Natural gas acreage Platforms/
(mbbl) (mmcf) (thousands) FPSO
---------------------------------------------------------------------------------------------------------------
NORTH AMERICA
Northeast British Columbia 7.0 430 2,401 1/11/-/-
Northwest Alberta 17.0 596 1,489 -/14/-/-
Northern Plains 201.4 418 7,109 12/6/-/-
Southern Plains 12.7 196 925 -/3/-/-
Southeast Saskatchewan 8.4 2 121 -/-/-/-
Non-core regions 0.3 1 109 -/-/-/-
Horizon Oil Sands - - 115 -/-/-/-
---------------------------------------------------------------------------------------------------------------
INTERNATIONAL
North Sea UK Sector 55.9 13 287 -/-/5/1
Offshore West Africa
Cote d'Ivoire 28.5 12 55 -/-/-/2
Gabon - - 151 -/-/-/-
Non-core regions
South Africa - - 4,002 -/-/-/-
---------------------------------------------------------------------------------------------------------------
TOTAL 331.2 1,668 16,764 13/34/5/3
---------------------------------------------------------------------------------------------------------------
CANADIAN NATURAL RESOURCES LIMITED 17
DRILLING ACTIVITY
Set forth below is a summary of the drilling activity, excluding stratigraphic
test and service wells, of the Company for each of the last three fiscal years
ending December 31, 2007 by geographic region:
2007
------------------------------------------------------------------------------------------------------------------------------
Net exploratory Net development
Productive Dry holes Total Productive Dry holes Total
------------------------------------------------------------------------------------------------------------------------------
CANADA
Northeast British Columbia 7.0 6.0 13.0 38.0 10.1 48.1
Northwest Alberta 17.4 3.8 21.2 94.2 8.9 103.1
Northern Plains 48.5 19.4 67.9 571.5 42.4 613.9
Southern Plains 14.4 1.0 15.4 152.2 0.6 152.8
Southeast Saskatchewan 1.0 - 1.0 23.0 0.4 23.4
Non-core regions - - - - - -
NORTH SEA UK SECTOR - - - 3.7 - 3.7
OFFSHORE WEST AFRICA
Cote d'Ivoire - - - 4.1 - 4.1
------------------------------------------------------------------------------------------------------------------------------
TOTAL 88.3 30.2 118.5 886.7 62.4 949.1
==============================================================================================================================
2006
------------------------------------------------------------------------------------------------------------------------------
Net exploratory Net development
Productive Dry holes Total Productive Dry holes Total
------------------------------------------------------------------------------------------------------------------------------
CANADA
Northeast British Columbia 17.2 5.6 22.8 158.9 14.1 173.0
Northwest Alberta 17.7 9.5 27.2 149.6 14.6 164.2
Northern Plains 104.1 28.2 132.3 598.5 36.1 634.6
Southern Plains 31.8 8.4 40.2 78.6 1.0 79.6
Southeast Saskatchewan - - - 72.7 2.0 74.7
Non-core regions 0.6 - 0.6 2.7 - 2.7
NORTH SEA UK SECTOR - - - 7.4 - 7.4
OFFSHORE WEST AFRICA
Cote d'Ivoire - - - 4.1 - 4.1
------------------------------------------------------------------------------------------------------------------------------
TOTAL 171.4 51.7 223.1 1,072.5 67.8 1,140.3
==============================================================================================================================
2005
------------------------------------------------------------------------------------------------------------------------------
Net exploratory Net development
Productive Dry holes Total Productive Dry holes Total
------------------------------------------------------------------------------------------------------------------------------
CANADA
Northeast British Columbia 32.1 7.2 39.3 179.9 21.1 201.0
Northwest Alberta 29.9 9.0 38.9 135.2 7.3 142.5
Northern Plains 63.5 11.5 75.0 671.4 51.9 723.3
Southern Plains 50.6 5.0 55.6 294.9 2.0 296.9
Southeast Saskatchewan 1.0 - 1.0 43.0 - 43.0
Non-core regions - - - 0.3 - 0.3
NORTH SEA UK SECTOR - 0.8 0.8 11.5 0.9 12.4
OFFSHORE WEST AFRICA
Cote d'Ivoire - 0.6 0.6 3.5 - 3.5
------------------------------------------------------------------------------------------------------------------------------
TOTAL 177.1 34.1 211.2 1,339.7 83.2 1,422.9
==============================================================================================================================
18 CANADIAN NATURAL RESOURCES LIMITED
PRODUCING CRUDE OIL & NATURAL GAS WELLS
Set forth below is a summary of the number of gross and net wells within the
Company that were producing or capable of producing as of December 31, 2007:
Natural gas wells Crude oil wells Total wells
Gross Net Gross Net Gross Net
-----------------------------------------------------------------------------------------------------------------------------------
CANADA
Northeast British Columbia 1,541.0 1,294.1 232.0 194.5 1,773.0 1,488.6
Northwest Alberta 2,125.0 1,636.7 561.0 315.5 2,686.0 1,952.2
Northern Plains 3,908.0 3,081.6 6,277.0 5,379.8 10,185.0 8,461.4
Southern Plains 7,320.0 6,136.6 1,154.0 1,025.7 8,474.0 7,162.3
Southeast Saskatchewan 5.0 2.8 1,518.0 952.9 1,523.0 955.6
Non-core regions 122.0 34.9 70.0 21.7 192.0 56.6
UNITED STATES 5.0 0.6 3.0 0.5 8.0 1.1
NORTH SEA UK SECTOR 2.0 0.1 108.0 91.3 110.0 91.4
OFFSHORE WEST AFRICA
Cote d'Ivoire - - 21.0 12.3 21.0 12.3
-----------------------------------------------------------------------------------------------------------------------------------
Total 15,028.0 12,187.4 9,944.0 7,994.2 24,972.0 20,181.5
===================================================================================================================================
Any reserves data in the following property report is based on the applicable
independent engineering report. See below "Conventional Crude Oil, NGLs and
Natural Gas Reserves" and "Oil Sands Mining Disclosure".
NORTHEAST BRITISH COLUMBIA
[GRAPHIC OMITTED]
Significant geological variation extends throughout the productive reservoirs in
this region, producing light crude oil, NGLs and natural gas. The Company holds
working interests ranging up to 100% and averaging 73% in 4,711,958 gross
(3,430,948 net) acres of producing and undeveloped land in the region.
Crude oil reserves are found primarily in the Halfway formation, while natural
gas and associated NGLs are found in numerous carbonate and sandstone formations
at depths up to 4,500 vertical meters. The exploration strategy focuses on
comprehensive evaluation through two-dimensional seismic, three-dimensional
seismic and targeting economic prospects close to existing infrastructure. The
region has a mix of low risk multi-zone targets, deep higher risk exploration
plays and emerging unconventional shale gas plays. The 2006 acquisition of ACC
significantly increased the Company's asset base in Northeast British Columbia
with the addition of the ACC properties in Adsett, Caribou and Fort St. John
West. The southern portion of this region encompasses the Company's BC Foothills
assets; here natural gas is produced from the deep Mississippian and Triassic
aged reservoirs in this highly deformed structural area. In 2006 the Company's
assets in Monkman and Ojay were augmented by the assets previously owned by ACC
in the area.
CANADIAN NATURAL RESOURCES LIMITED 19
Natural gas production from the region averaged 430 mmcf/d in 2007 compared to
the average of 408 mmcf/d in 2006. Crude oil and NGLs production was steady at
7,000 bbl/d in 2007, from an average of 6,700 bbl/d in 2006.
During 2005, the Company initiated a new exploration and development play that
targets natural gas found in the shallow Notikewin formation in the Fort St.
John area. Wells drilled into this formation generally produce at rates of up to
500 to 700 mmcf/d. In combination with the Company's extensive land base and
reduced royalty rates in British Columbia, this shallow gas drilling program
will add to the Company's opportunities in this region. Development of this play
continued in 2006 with the drilling of 45 wells at Ladyfern. Another shallow gas
play was pursued in 2006 with the drilling of 50 Banff wells at Shekelie.
During 2007, the Company drilled 2.9 (2006 - 12.9) net crude oil wells, 42.1
(2006 - 163.2) net natural gas wells, 0.0 (2006 - 0.0) net stratigraphic/service
wells and 16.1 (2006 - 19.7) net dry wells on its lands in this region for a
total of 61.1 (2006 - 195.8) net wells. The Company held an average 81% working
interest in these wells.
NORTHWEST ALBERTA
[GRAPHIC OMITTED]
The Company holds working interests ranging up to 100% and averaging 73% in
3,193,607 gross (2,338,858 net) acres of producing and undeveloped land in the
region located along the border of British Columbia and Alberta west of
Edmonton.
The majority of the Company's initial holdings in the region were obtained
through the 2002 acquisition of RAX; subsequent to 2002 the Company augmented
these holdings with additional land purchases, acquisitions and in 2006 the
purchase of the ACC assets. The ACC acquisition added two very prospective
properties to this region, Wild River and Peace River Arch. The Wild River
assets will provide a premium developed and undeveloped land base in the deep
basin, multi-zone gas fairway and the Peace River Arch assets provide premium
lands in a multi-zone region along with key infrastructure. Northwest Alberta
provides exploration and exploitation opportunities in combination with an
extensive owned and operated infrastructure. In this region, Canadian Natural
produces liquids rich natural gas from multiple, often technically complex
horizons, with formation depths ranging from 700 to 4,500 meters. The northern
portion of this core region provides extensive multi-zone Cretaceous
opportunities similar to the geology of the Company's Northern Plains core
region. The Company is also pursuing development of a Doig shale gas play in
this region. The southern portion provides exploration and development
opportunities in the regionally extensive Cretaceous Cardium formation and in
the deeper, tight gas formations throughout the region. The Cardium is a
complex, tight natural gas reservoir where high productivity may be achieved due
to greater matrix porosity or natural fracturing. Recent regulatory changes have
improved the economics of multi-zone production by providing the opportunity to
commingle multiple zones within a single wellbore. The south western portion of
this region also contains significant Foothills assets with natural gas produced
from the deep Mississippian and Triassic aged reservoirs.
Natural gas production from the region averaged 596 mmcf/d in 2007 compared to
an average of 454 mmcf/d in 2006. Crude oil and NGLs production increased to
17,000 bbl/d in 2007 from 15,000 bbl/d in 2006.
During 2007, the Company drilled 13.0 (2006 - 14.5) net crude oil wells, 98.5
(2006 - 152.8) net natural gas wells, 1.5 (2006 - 0.0) net stratigraphic/service
wells, and 12.8 (2006 - 24.1) net dry wells on its lands in this region for a
total of 125.8 (2006 - 191.4) net wells. The Company held an average 74% working
interest in these wells.
20 CANADIAN NATURAL RESOURCES LIMITED
NORTHERN PLAINS
[GRAPHIC OMITTED]
The Company holds working interests ranging up to 100% and averaging 85% in
12,098,317 gross (10,318,670 net) acres of producing and undeveloped land in the
region located just south of Edmonton north to Fort McMurray and from the
Northwest Alberta area east to the border with Saskatchewan and extending into
western Saskatchewan.
Over most of the region both sweet and sour natural gas reserves are produced
from numerous productive horizons at depths up to approximately 1,500 meters. In
the southwest portion of the region, NGLs and light crude oil are also
encountered at slightly greater depths. The region continues to be one of the
Company's largest natural gas producing regions, with natural gas production
from the region amounting to 418 mmcf/d in 2007 compared to 437 mmcf/d in 2006.
Crude oil and NGLs production from this region increased to 201,400 bbl/d in
2007 up from 194,500 bbl/d in 2006. Production of natural gas was negatively
impacted by the shut-in effective July 1, 2004 of approximately 11 mmcf/d in the
Athabasca Wabiskaw-McMurray oil sands area pursuant to the decision of the
Alberta Energy and Utilities Board. In 2007 the Company made a strategic
decision to reduce natural gas drilling in Western Canada as a result of low
natural pas prices and increase drilling in crude oil areas such as the Northern
Plains area.
Natural gas in this region is produced from shallow, low-risk, multi-zone
prospects and more recently from the Horseshoe Canyon CBM. The Company targets
low-risk exploration and development opportunities and plans to expand its
commercial Horseshoe Canyon CBM project. During 2006, natural gas development
drilling included 120.5 net wells and 48.0 net Horseshoe Canyon CBM locations.
Evaluation of the potential for production of CBM from the Mannville coals
commenced in 2006 with the drilling of three horizontal wells; these wells will
be tested in 2008 to determine the economic viability of this play.
In the area near Lloydminster, Alberta, reserves of heavy crude oil (averaging
12(0)-14(0) API) and natural gas are produced through conventional vertical,
slant and horizontal well bores from a number of productive horizons up to 1,000
meters deep. The energy required to flow the heavy crude oil to the wellbore in
this type of heavy crude oil reservoir comes from solution gas. The crude oil
viscosity and the reservoir quality will determine the amount of crude oil
produced from the reservoir, which will vary from 3% to 20% of the original
crude oil in place. A key component to maintaining profitability in the
production of heavy crude oil is to be a low-cost producer. The Company
continues to achieve low costs producing heavy crude oil by holding a dominant
position that includes a significant land base and an extensive infrastructure
of batteries and disposal facilities.
CANADIAN NATURAL RESOURCES LIMITED 21
The Company's holdings in this region of primary heavy oil production are both
the result of Crown land purchases and several acquisitions including major
acquisitions from Sceptre Resources, Koch Exploration, Ranger Oil and Petrovera.
As part of the acquisition of Ranger, the Company also acquired a 50% interest
in the ECHO Pipeline system, a crude oil transportation pipeline; and, in 2001
the Company acquired the remaining 50%. The pipeline was extended north to the
Company operated Beartrap Field during 2001 and to the Morgan Field in 2006
enhancing development and reducing operating costs for the Company's extensive
holdings in the area. This pipeline was capable of transporting 57,000 bbl/d of
hot, unblended crude oil to sales facilities at Hardisty, Alberta and in 2003
its capacity was expanded to handle up to 72,000 bbl/d. The ECHO Pipeline system
is a high temperature, insulated pipeline that eliminates the requirement for
field condensate blending. The pipeline enables the Company to transport its own
production volumes at a reduced operating cost as well as earn third-party
transportation revenue. This transportation control enhances the Company's
ability to control the full spectrum of costs associated with the development
and marketing of its heavy crude oil.
Production from the 100% owned Primrose and Wolf Lake Fields located near
Bonnyville, Alberta involves processes that utilize steam to increase the
recovery of the heavy (10(0)-11(0) API) crude oil. The two processes employed by
the Company are cyclic steam stimulation and Steam Assisted Gravity Drainage
("SAGD"). Both recovery processes inject steam to heat the heavy crude oil
deposits, reducing the oil viscosity and thereby improving its flow
characteristics. There is also an infrastructure of gathering systems, a
processing plant with a capacity of 80,000 bbl/d of crude oil which expanded to
119,500 bbl/d in 2007. The Company also holds a 50% interest in a co-generation
facility capable of producing 84 megawatts of electricity for the Company's use
and sale into the Alberta power grid at pool prices. Since acquiring the assets
from BP Amoco in 1999, the Company has successfully converted the field from
low-pressure steaming to high-pressure steaming. This conversion resulted in a
significant improvement in well productivity and in ultimate oil recovery.
Canadian Natural drilled 58 high-pressure wells in 2004. In 2004, the Company
started to proceed with its Primrose North expansion project, which was
effectively completed in late 2005 with total capital expenditures of
approximately $300 million incurred. The Primrose North expansion entails a
remote steam generation facility and additional high pressure cyclic steam
wells. First crude oil production from the expansion project began in January
2006. Also in 2004 the Company filed a public disclosure document for regulatory
approval of its Primrose East project, a new facility located about 15
kilometers from its existing Primrose South steam plant and 25 kilometers from
its Wolf Lake central processing facility. The development application for
Primrose East was submitted to the Alberta Energy and Utilities Board in January
2006, with potential impacts associated with the use of bitumen as fuel being
evaluated in the Environmental Impact Assessment. The Company received
regulatory approval for the project in February, 2007 and construction began in
2007, with the first oil production targeted to commence in 2009. A mature SAGD
heavy oil project in which the Company holds a 50% interest is also in operation
in the Saskatchewan portion of this region. In December 2006 Canadian Natural
issued a Public Disclosure Document outlining the proposed development plan for
the Kirby In-Situ Oil Sands Project located approximately 85 km northeast of Lac
La Biche. The Regulatory application for Kirby was submitted in September 2007
outlining the Company's plan to build a 45,000 bbl/d in-situ oil sands project.
In 2006 the Company undertook a Scoping Study to evaluate the construction of an
upgrader to process the Company's Athabasca and Cold Lake thermal production.
The study included evaluating the product alternatives, location, technology,
gasification and integration with existing assets. The next steps in this
process would include a Design Base Memorandum ("DBM") and Engineering Design
Specifications ("EDS") which would be required to be completed prior to
construction and sanctioning of the project by the Board of Directors of the
Company. Based upon the results of the Scoping Study, which identified growing
concerns relating to increased environmental costs for upgraders located in
Canada, inflationary capital cost pressures and narrowing heavy oil
differentials in North America, the Company has, at this point in time, deferred
the DBM and EDS pending clarification on the cost of future environmental
legislation and a more stable cost environment.
Included in the northern part of this region, approximately 200 miles north of
Edmonton, are the Company's holdings at Pelican Lake. These assets produce crude
oil from the Wabasca formation with gravities of 14(0)-17(0) API. Production
costs are low due to the absence of sand production, its associated disposal
requirements and the gathering and pipeline facilities in place. The Company has
the major ownership position in the necessary infrastructure, including roads,
drilling pads, gathering and sales pipelines, batteries, gas plants and
compressors, to ensure economic development of the large crude oil pool located
on the lands. The Company holds and controls approximately 75% of the known
crude oil pool in this area.
It is estimated this field contains approximately four billion barrels of
original crude oil in place but is only expected to achieve less than a 5%
average recovery factor using existing primary production on the Company's
developed leases. Hence, in 2002 the Company embarked upon an Enhanced Oil
Recovery ("EOR") scheme using an emulsion flood to increase the ultimate
recoveries from the field. The experimental Pelican Lake emulsion flood showed
that the recovery mechanism was very efficient; however, response time was slow.
Due to the slow response time, the Company reverted to a waterflood scheme for
this field. The waterflood provided initial production increases as expected and
has shown positive waterflood response. To date approximately 11% of the field
has been converted to waterflood. To further enhance the expected crude oil
recovery from the waterflood, in the second quarter of 2005, the Company
initiated a five well polymer flood pilot test.
22 CANADIAN NATURAL RESOURCES LIMITED
Performance of the polymer flood pilot test has been positive, with crude oil
production rates from the three production wells increasing from approximately
60 bbl/d in 2005 to over 500 bbl/d by December 2006. The commercial expansion of
this EOR technology continues with 70 polymer injection wells at year end 2007.
Pelican Lake production averaged approximately 34,000 bbl/d in 2007.
During 2007, the Company drilled 524.4 (2006 - 484.0) net crude oil wells, 95.6
(2006 - 218.6) net natural gas wells, 145.8 (2006 - 206.9) net
stratigraphic/service wells, and 61.8 (2006 - 64.3) net dry wells for a total of
827.6 (2006 - 973.8) net wells. The Company's average working interest in these
wells was 92%.
SOUTHERN PLAINS AND SOUTHEAST SASKATCHEWAN
[GRAPHIC OMITTED]
In the Southern Plains area, the Company holds interests ranging up to 100% and
averaging 82% in 2,917,066 gross (2,379,552 net) acres of producing and
undeveloped land in the region, principally located south of the Northern Plains
area to the United States border and extending into western Saskatchewan.
Reserves of natural gas, condensate and light gravity crude oil are contained in
numerous productive horizons at depths up to 2,300 meters. Unlike the Company's
other three natural gas producing regions, which have areas with limited or
winter access only, drilling can take place in this region throughout the year.
It is economic to drill shallow wells with reduced well spacings in this region
despite having smaller overall reserves and lower productivity per well since
they achieve a favourable rate of return on capital employed with low drilling
costs and long life reserves. The Company's extensive shallow gas assets in this
region have been augmented in 2006 as a result of the Company's development of
the Senate shallow gas play in SW Saskatchewan and the purchase of the ACC
Hatton assets in SW Saskatchewan. Other assets acquired from ACC in this region
include the crude oil producing assets at Taber.
The Company maintains a large inventory of drillable locations on its land base
in this region. This region is one of the more mature regions of the Western
Canadian Sedimentary Basin and requires continual operational cost control
through efficient utilization of existing facilities, flexible infrastructure
design and consolidation of interests where appropriate.
The Company's share of production in the Southern Plains area averaged 12,700
bbl/d of crude oil and NGLs in 2007 compared to 10,500 bbl/d in 2006. Natural
gas production amounted to 196 mmcf/d in 2007 compared to the 165 mmcf/d
averaged in 2006.
During 2007, the Company drilled a total of 19.1 (2006 - 6.2) net crude oil
wells, 147.5 (2006 - 104.2) net natural gas wells, 1.0 (2006 - 0.0) net
stratigraphic/service wells and 1.6 (2006 - 9.4) net dry wells in this region
for a total of 169.2 (2006 - 119.8) net wells. The Company's average working
interest in these wells was 79%.
The Williston Basin is located in Southeast Saskatchewan with lands extending
into Manitoba. This region became a core region of the Company in mid 1996 with
the acquisition of Sceptre. The Company holds interests ranging up to 100% and
averaging 82% in 220,266 gross (181,691 net) acres of producing and undeveloped
lands in the region.
CANADIAN NATURAL RESOURCES LIMITED 23
The region produces primarily light sour crude oil from as many as seven
productive horizons found at depths up to 2,700 meters. The Company's share of
production in the Southeast Saskatchewan area averaged 8,400 bbl/d of crude oil
and NGLs in 2007 compared to 8,400 bbl/d in 2006. Natural gas production
averaged 2 mmcf/d in 2007 (2006 - 3 mmcf/d).
The Company drilled 24.0 (2006 - 72.7) net crude oil wells, 0.0 (2006 - 0.0) net
natural gas well, 4.0 (2006 - 0.0) net stratigraphic/service wells and 0.4 (2006
- 2.0) net dry wells in this region in 2007, for a total of 28.4 (2006 - 74.7)
net wells. The Company's average working interest in these wells is 84%.
HORIZON OIL SANDS PROJECT
[GRAPHIC OMITTED]
Canadian Natural owns a 100% working interest in its Athabasca Oil Sands leases
in Northern Alberta, of which a portion (being lease 18) is subject to a 5% net
carried interest in the bitumen development. The Horizon Project is located on
these leases, about 70 kilometers north of Fort McMurray. The project includes
surface oil sands mining, bitumen extraction, bitumen upgrading to produce a 34
o API SCO, and associated infrastructure.
Canadian Natural filed an application for regulatory approval of the Horizon
Project in June 2002. The application included a comprehensive environmental
impact assessment and a social and economic assessment and was accompanied by
public consultation. A federal-provincial regulatory Joint Review Panel (the
"Panel") examined the project in a public hearing in September 2003. The Panel
issued its decision report in January 2004, finding that the Horizon Project is
in the public interest. An Alberta Order-in-Council approval was received in
February 2004. Subsequently, key approvals were received from Alberta
Environment under the ENVIRONMENTAL PROTECTION ACT and WATER ACT, and from
Fisheries and Oceans Canada under the FISHERIES ACT.
The Project, which has two aspects, bitumen production and bitumen upgrading to
SCO, is designed as a phased development. Site clearing and pre-construction
preparation activities commenced in 2004 and construction is planned to continue
through 2013. Phase 1 production is targeted to begin in the third quarter of
2008 ramping up to 110,000 bbl/d of SCO. Subsequent expansion through Phases
2/3, which is further broken down into a series of four Tranches, is expected to
increase production to 232,000 bbl/d of SCO out to 2013. These targeted rates of
production represent nominal design capacity. Construction of some components
and portions of facilities for the future expansions have already been completed
and certain major long lead equipment for Phases 2/3 was ordered in 2006 with
deliveries to site expected in 2008. Canadian Natural will seek to maximize
resource recovery and overall production through ongoing optimization of
operations.
24 CANADIAN NATURAL RESOURCES LIMITED
Canadian Natural used a structured system called Front End Loading to ensure
that project definition is adequate and complete before proceeding with
implementation. This system is used successfully worldwide to mitigate risk on
large capital projects in a variety of industries. The process is well
documented at every step and is audited by an independent organization. In June
2002, the Company commenced the Design Basis Memorandum ("DBM"), which is the
second of three front-end engineering phases. The DBM was completed for all
project components in February 2004. In August 2003, the Company commenced work
on the third and final front-end engineering phase for Phase 1, completing the
work in December 2004. The products of this phase include a detailed project
execution plan, Engineering Design Specifications ("EDS") and a detailed cost
estimate (plus or minus 10%). The EDS provided sufficient definition for a lump
sum inquiry for the Detailed Engineering, Procurement and Construction of the
various project components. With this information a "cost certainty" estimate
was developed as a basis for project sanction by the Board of Directors, which
was given in February 2005, authorizing management to proceed with Phase 1 of
the Horizon Project. The Company is now developing various cost effective
options for execution of additional construction on Phases 2/3.
The Horizon Project is designed to use proven technology and will seek to take
advantage of technology improvements that advance environmental performance,
enhance the work environment for workers, increase reliability and production
and reduce capital and production costs. By the end of 2004 the Company had
acquired all key technologies for the project. At year end 2007, Canadian
Natural's Horizon Project team, consisted of 925 permanent employees which
consisted of 661 project staff personnel and 264 operations personnel to fill
63% of the projected project and operations team position requirements.
Horizon Project Phase 1 construction costs were approximately $2.74 billion in
2007 and cumulative expenditures were approximately $6.76 billion through the
end of 2007. Phase 1 construction capital is budgeted to be approximately $1.7
billion to $1.9 billion in 2008, representing a cost to completion forecast
range of 25% to 28% over the original $6.8 billion estimate. In addition,
capital expenditures of $439 million are budgeted for Tranche 2 development and
construction in 2008. These expenditures are direct project costs only and do
not include capitalized interest, stock based compensation or lease evaluation.
During 2007, the Company drilled 98.0 (2006 - 163.0) stratigraphic test wells to
further delineate the ore body and confirm resource quality and quantity.
CANADIAN NATURAL RESOURCES LIMITED 25
UNITED KINGDOM NORTH SEA
[GRAPHIC OMITTED]
The Company's wholly owned subsidiary CNR International (U.K.) Limited, formerly
Ranger Oil (U.K.) Limited, has operated in the North Sea for 30 years and has
developed a significant database, extensive operating experience and an
experienced staff. The Company owns interests ranging from 7% up to 100% in
478,061 gross (374,720 net) acres of producing and non-producing properties in
the UK sector of the North Sea. In 2007, the Company produced from 16 crude oil
fields.
The northerly fields are centered around the Ninian Field where the Company has
an 87.1% working interest. The central processing facility is connected to other
fields including the Columba Terraces and Lyell Fields where the Company
operates with working interests of 91.6% to 100%. In 2002, the Company completed
property acquisitions in the northern North Sea that increased its ownership
levels in the Ninian, Murchison, Lyell and Columba Terraces Fields. As part of
the transaction the Company also acquired an interest in the Strathspey Field
and 12 licences covering 20 exploration blocks and part blocks surrounding the
Ninian and Murchison platforms. Increased ownership in the Brent and Ninian
pipelines and the Sullom Voe Terminal was also acquired. In 2003, the Company
further consolidated its ownership with the acquisition of additional working
interests in the Ninian and Columba Fields, associated facilities and adjacent
exploration acreage. In 2007 the Company acquired a 58.7% working interest in
the abandoned Hutton Field, increasing its working interest in this currently
non-producing Field to 66.5%.
In the central portion of the North Sea, in 2003, the Company increased its
equity in the Banff Field to 87.6% and took over as operator. The Company also
owns a 45.7% operated working interest in the Kyle Field. Beginning in the third
quarter of 2005, all production for the Kyle Field was processed through the
Banff FPSO facilities. The consolidation of these production facilities resulted
in lower combined production costs from these fields.
In 2004, the Company acquired 100% working interest in T-block (comprising the
Tiffany, Toni and Thelma Fields) and 68.7% to 75.3% interests in the Fields
known as B-block (comprising Balmoral, Stirling and Glamis). The Company took
over as operator of these fields. In 2007 the Company disposed of its interests
in the B Block Fields.
The Company receives tariff revenue from other field owners for the processing
of crude oil and natural gas through some of the processing facilities.
Opportunities for further long-reach well development on adjacent fields are
provided by the existing processing facilities.
During 2007, production to the Company from this region averaged approximately
55,900 bbl/d of crude oil (2006 - 60,100 bbl/d). Natural gas production averaged
13.0 mmcf/d in 2007 (2006 - 15.0 mmcf/d).
During 2007 the Company drilled 3.7 (2006 - 7.4) net crude oil wells, 3.5 (2006
- 1.8) net stratigraphic/service wells and 0.0 (2006 - 0.0) net dry wells in
this region for a total of 7.2 (2006 - 9.2) net wells. The Company's average
working interest in these wells is 90%.
26 CANADIAN NATURAL RESOURCES LIMITED
OFFSHORE WEST AFRICA
[GRAPHIC OMITTED]
With the purchase of Ranger in 2000, the Company acquired interests in areas of
crude oil and natural gas exploration and development offshore Cote d'Ivoire and
Angola, West Africa. During 2005, the Company either relinquished or sold all of
its interests in offshore Angola. In 2006, certain exploration acreage in Cote
d'Ivoire was also relinquished.
In 2005, the Company acquired the permit to develop the Olowi Field, offshore
Gabon, West Africa, consisting of 151,818 acres. The Company has a 90% interest
in a production sharing agreement for the block.
The Company also has a 100% interest in 4,001,574 acres offshore South Africa
where it is shooting and evaluating seismic data and undertaking environmental
studies.
COTE D'IVOIRE
The Company owns interests in two exploration licences offshore Cote d'Ivoire
comprising 55,408 net acres. During 2001, the Company increased its interest in
Block CI-26, which contains the Espoir Field, to a 58.7% operating interest. The
Espoir Field is located in water depths ranging from 100 to 700 meters. During
the 1980s, the Espoir Field produced approximately 31 million barrels of crude
oil by natural depletion prior to relinquishment by the previous licencees in
1988. The government of Cote d'Ivoire approved a development plan to recover the
remaining reserves and the Company will continue its exploitation and
development of the field. The first phase of development of East Espoir, which
included the drilling of both producing and water injection wells from a single
wellhead tower, was completed in 2003. The construction and installation of a
new wellhead tower for the West Espoir part of the field were completed in 2005.
Due to a successful infill drilling program completed at East Espoir in early
2006 the Company achieved approximately 24,000 bbl/d of net production from the
Field. Following the infill drilling at East Espoir, development drilling
commenced at West Espoir with first oil from the Field delivered July, 2006.
Development drilling at West Espoir continued throughout 2007 and was completed
in early 2008.
Crude oil from the East and West Espoir Fields is produced to an FPSO with the
associated natural gas delivered onshore through a subsea pipeline for local
power generation. In 2003, the Company drilled a satellite pool, Acajou, which
encountered a reservoir with good quality hydrocarbons. The extent of this
accumulation was further appraised by a well drilled in 2004 which did not
encounter commercial hydrocarbons.
The unsuccessful Zaizou exploration well was drilled in block CI-40 in 2005.
CANADIAN NATURAL RESOURCES LIMITED 27
In the first quarter of 2001, the Company drilled and tested the Baobab
exploration prospect, identified on Block CI-40, eight kilometers south of the
Espoir facilities, in which the Company has a 58% interest. The well encountered
hydrocarbons at a rate of 6,700 bbl/d of crude oil. A second test well in 2002
also produced hydrocarbons at a rate in excess of 10,000 bbl/d of crude oil. The
Company established a field development plan, which was approved by the
Government of Cote d'Ivoire in December 2002. In 2003, the Company awarded four
major contracts for the development of the Baobab Field. These contracts
included the deep water drilling rig to drill 8 producing and 3 water injection
wells, the FPSO, supplies for the subsea equipment and the supply of pipeline
and risers, and installation of the subsea infrastructure. Development commenced
in late 2003 and first oil was achieved in August 2005 producing at
approximately 30,000 bbl/d net to Canadian Natural from 4 wells. Upon completion
of drilling additional wells in 2006, production levels increased as expected.
Subsequent problems with the control of sand and solids production led to five
of the ten production wells being shut in by the end of the year, resulting in
approximately 15,500 bbl/d of net production capacity being shut in. The Company
has secured a deepwater rig, expected in mid-year 2008, that is expected to
enable the Company to execute its plan to return certain of the shut-in wells to
production over the course of 2008 and 2009.
To date political unrest which has occurred from time to time in Cote d'Ivoire
has had no impact on the Company's operations. The Company has developed
contingency plans to continue Cote d'Ivoire operations from a nearby country if
the situation warrants such a move.
During 2007, Company production averaged approximately 28,500 bbl/d of crude oil
(2006- 36,700 bbl/d). Company natural gas production amounted to 12.1 mmcf/d in
2007 (2006 - 9.5 mmcf/d).
In 2007, the Company drilled 4.1 (2006 - 4.1) net crude oil wells, 0.6 (2006 -
1.7) net stratigraphic/service wells and 0.0 (2006 - 0.0) net dry wells for a
total of 4.7 (2006 - 5.8) net wells. The Company's average working interest in
these wells is 59%.
GABON
[GRAPHIC OMITTED]
In late 2005, the Company acquired permit No. G4-187 comprising a 90% operating
interest in the production sharing agreement for the block containing the Olowi
Field. The field is located about 20 kilometers from the Gabonese coast and in
30 meters water depth. Olowi has been delineated by the drilling of 15 wells on
the block. A development plan, comprising an FPSO and four drilling towers, was
filed with the Gabonese Government in late 2005 and approved in February 2006.
The development will target the western flank of the structure where the oil is
located as a rim below a large gas cap. Major contracts covering the FPSO,
platforms, flowlines and the drilling rig were awarded in late 2006.
Construction is underway and first oil is targeted for late 2008. It is planned
that in total 28 horizontal production wells plus one gas injector well will be
drilled. Crude oil production will rely on gas cap expansion supplemented by
re-injection of the produced solution gas. Production is expected to ramp up
during 2009 to a plateau rate of approximately 20,000 bbl/d net to the Company.
28 CANADIAN NATURAL RESOURCES LIMITED
B. CONVENTIONAL CRUDE OIL, NGLS, AND NATURAL GAS RESERVES
For the year ended December 31, 2007, the Company retained qualified independent
reserve evaluators, Sproule Associates Limited ("Sproule") and Ryder Scott
Company ("Ryder Scott") to evaluate 100% of the Company's conventional proved,
as well as proved and probable crude oil, NGLs and natural gas reserves and
prepare Evaluation Reports on these reserves. Conventional crude oil, NGLs and
natural gas includes all of the Company's light/medium, primary heavy, and
thermal crude oil, natural gas, coal bed methane and NGLs activities. It does
not include the Company's oil sands mining assets. Conventional crude oil, NGLs,
and natural gas reserves, net of royalties, are estimated using royalty
regulations in effect as of December 31, 2007. Similarly, bitumen and synthetic
crude oil reserves, net of royalties, relating to surface mineable oil sand
projects are estimated using royalty regulations in effect as of December 31,
2007. Royalty changes proposed by the Government of Alberta will be incorporated
in the reserves evaluation should they be enacted. Sproule evaluated the
Company's North America conventional assets and Ryder Scott evaluated the
international conventional assets. The Company has been granted an exemption
from National Instrument 51-101 - "Standards of Disclosure for Oil and Gas
Activities" ("NI 51-101"), which prescribes the standards for the preparation
and disclosure of reserves and related information for companies listed in
Canada. This exemption allows the Company to substitute SEC requirements for
certain disclosures required under NI 51-101. There are three principal
differences between the two standards. The first is the requirement under NI
51-101 to disclose both proved and proved and probable reserves, as well as the
related net present value of future net revenues using forecast prices and
costs. The second is in the definition of proved reserves; however, as discussed
in the Canadian Oil and Gas Evaluation Handbook ("COGEH"), the standards that NI
51-101 employs, the difference in estimated proved reserves based on constant
pricing and costs between the two standards is not material. The third is the
requirement to disclose a gross reserve reconciliation (before the consideration
of royalties). The Company discloses its reserve reconciliation net of royalties
in adherence to SEC requirements.
The Company annually discloses proved conventional reserves and the Standardized
Measure of discounted future net cash flows using year-end constant prices and
costs as mandated by the SEC in the supplementary crude oil and natural gas
information section of the Company's Annual Report. The Company has elected to
provide the net present value of these same conventional proved reserves as well
as its conventional proved and probable reserves and the net present value of
these reserves under the same parameters as voluntary additional information.
Net present values of conventional reserves are based upon discounted cash flows
prior to the consideration of income taxes and existing asset abandonment
liabilities. Only future development costs and associated material well
abandonment liabilities have been applied. The Company has also elected to
provide both proved, and proved and probable conventional reserves and the net
present value of these reserves using forecast prices and costs as voluntary
additional information, which is disclosed in this Annual Information Form.
The Reserves Committee of the Company's Board of Directors has met with and
carried out independent due diligence procedures with each of Sproule and Ryder
Scott to review the qualifications of and procedures used by each evaluator in
determining the estimate of the Company's quantities and net present value of
remaining conventional crude oil, NGLs and natural gas reserves.
The following tables summarize the evaluations of conventional reserves and
estimated net present values of these reserves at December 31, 2007.
THE ESTIMATED NET PRESENT VALUES OF RESERVES CONTAINED IN THE FOLLOWING TABLES
ARE NOT TO BE CONSTRUED AS A REPRESENTATION OF THE FAIR MARKET VALUE OF THE
PROPERTIES TO WHICH THEY RELATE. THE ESTIMATED FUTURE NET REVENUES DERIVED FROM
THE ASSETS ARE PREPARED PRIOR TO CONSIDERATION OF INCOME TAXES AND EXISTING
ASSET ABANDONMENT LIABILITIES. ONLY FUTURE DEVELOPMENT COSTS AND ASSOCIATED
FUTURE MATERIAL WELL ABANDONMENT LIABILITIES HAVE BEEN APPLIED. NO INDIRECT
COSTS SUCH AS OVERHEAD, INTEREST AND ADMINISTRATIVE EXPENSES HAVE BEEN DEDUCTED
FROM THE ESTIMATED FUTURE NET REVENUES. OTHER ASSUMPTIONS AND QUALIFICATIONS
RELATING TO COSTS, PRICES FOR FUTURE PRODUCTION AND OTHER MATTERS ARE SUMMARIZED
IN THE NOTES TO THE FOLLOWING TABLES. THERE IS NO ASSURANCE THAT THE PRICE AND
COST ASSUMPTIONS CONTAINED IN EITHER THE CONSTANT OR FORECAST CASES WILL BE
ATTAINED AND VARIANCES COULD BE SUBSTANTIAL.
29 CANADIAN NATURAL RESOURCES LIMITED
NET CONVENTIONAL CRUDE OIL, NGLS AND NATURAL GAS RESERVES (NET OF ROYALTIES)
Constant Prices and Costs
--------------------------------------------------------------------------------------------------------------------------------
Crude oil & NGLs (mmbbl) Natural gas (bcf)
Total proved Total proved & Total proved Total proved &
reserves probable reserves reserves probable reserves
--------------------------------------------------------------------------------------------------------------------------------
NORTH AMERICA
Canada 920 1,545 3,519 4,600
United States -- -- 2 2
INTERNATIONAL
United Kingdom 310 405 81 113
Cote d'Ivoire 110 166 64 88
Gabon 18 20 -- --
--------------------------------------------------------------------------------------------------------------------------------
TOTAL 1,358 2,136 3,666 4,803
================================================================================================================================
CONVENTIONAL CRUDE OIL, NGLS AND NATURAL GAS RESERVES
Constant Prices and Costs
--------------------------------------------------------------------------------------------------------------------------------
Crude oil & NGLs (mmbbl) Natural gas (bcf)
Company gross Net Company gross Net
--------------------------------------------------------------------------------------------------------------------------------
Proved developed reserves 828 736 3,454 2,842
Proved undeveloped reserves 715 622 981 824
--------------------------------------------------------------------------------------------------------------------------------
TOTAL PROVED RESERVES 1,543 1,358 4,435 3,666
TOTAL PROVED & PROBABLE RESERVES 2,430 2,136 5,804 4,803
================================================================================================================================
ESTIMATED NET PRESENT VALUE
Constant Prices and Costs
--------------------------------------------------------------------------------------------------------------------------------
Undiscounted Discounted at:
($ millions) 10% 15% 20%
--------------------------------------------------------------------------------------------------------------------------------
Proved developed reserves $ 42,653 $ 25,767 $ 21,924 $ 19,229
Proved undeveloped reserves $ 22,986 $ 8,810 $ 6,082 $ 4,340
--------------------------------------------------------------------------------------------------------------------------------
TOTAL PROVED RESERVES $ 65,639 $ 34,577 $ 28,006 $ 23,569
TOTAL PROVED & PROBABLE RESERVES $ 94,316 $ 44,286 $ 34,604 $ 28,331
================================================================================================================================
30 CANADIAN NATURAL RESOURCES LIMITED
CONVENTIONAL CRUDE OIL, NGLS AND NATURAL GAS RESERVES
Forecast Prices and Costs
--------------------------------------------------------------------------------------------------------------------------------
Crude oil & NGLs (mmbbl) Natural gas (bcf)
Company gross Net Company gross Net
--------------------------------------------------------------------------------------------------------------------------------
Proved developed reserves 814 730 3,464 2,850
Proved undeveloped reserves 721 626 982 822
--------------------------------------------------------------------------------------------------------------------------------
TOTAL PROVED RESERVES 1,535 1,356 4,446 3,672
TOTAL PROVED & PROBABLE RESERVES 2,426 2,129 5,817 4,810
================================================================================================================================
ESTIMATED NET PRESENT VALUES
Forecast Prices and Costs
--------------------------------------------------------------------------------------------------------------------------------
Undiscounted Discounted at:
($ millions) 10% 15% 20%
--------------------------------------------------------------------------------------------------------------------------------
Proved developed reserves $ 39,393 $ 25,013 $ 21,501 $ 18,984
Proved undeveloped reserves $ 26,455 $ 9,494 $ 6,478 $ 4,594
--------------------------------------------------------------------------------------------------------------------------------
TOTAL PROVED RESERVES $ 65,848 $ 34,507 $ 27,979 $ 23,578
TOTAL PROVED & PROBABLE RESERVES $ 104,860 $ 46,364 $ 35,860 $ 29,208
================================================================================================================================
NOTES
1. "Company Gross" reserves means the total working interest share of
remaining recoverable reserves owned by the Company before consideration of
royalties.
2. "Net" reserves mean the Company's gross reserves less all royalties payable
to others plus royalties receivable from others.
3. "Proved developed" reserves were evaluated using SEC standards and can be
expected to be recovered through existing wells with existing equipment and
operating methods. SEC standards require that these be evaluated using
year-end constant prices and costs and be disclosed net of royalties. The
Company has also provided these reserves using forecast prices and costs as
well as before royalties and their associated net present values as
additional voluntary information.
4. "Proved undeveloped" reserves were evaluated using SEC standards and are
expected to be recovered from new wells on undrilled acreage, or from
existing wells where relatively major 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 offsetting productive
wells that are reasonably certain of production when drilled. SEC standards
require that these be evaluated using year-end constant prices and costs
and be disclosed net of royalties. The Company has also provided these
reserves using forecast prices and costs as well as before royalties and
their associated net present values as additional voluntary information.
5. "Proved" reserves were evaluated using SEC standards and are those
quantities of crude oil, natural gas and NGLs, which geological and
engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions. SEC standards require that these be evaluated using year-end
constant prices and costs and be disclosed net of royalties. The Company
has also provided these reserves using forecast prices and costs as well as
before royalties and their associated net present values as additional
voluntary information.
CANADIAN NATURAL RESOURCES LIMITED 31
6. "Total Proved and Probable" reserves were evaluated using the COGEH
standards of NI 51-101 and are those reserves where there is at least a 50%
probability that the quantities actually recovered will equal or exceed the
stated values. The Company has elected to disclose proved and probable
reserves using both constant prices and costs as well as forecast prices
and costs and has disclosed these before and net of royalties and their
associated net present values. The calculation of a probable reserves and
value component by subtracting the proved reserves from the proved and
probable reserves may be subject to immaterial error due to the different
standards applied in the determination of each value.
7. Canadian securities legislation and policies permit the disclosure of
probable reserves which may not be disclosed in reports filed with the SEC
by United States companies. Probable reserves are generally believed to be
less likely to be recovered than proved reserves. The reserve estimates,
included or incorporated by reference in this Annual Information Form could
be materially different from the quantities and values ultimately realized.
8. All values are shown in Canadian dollars.
9. The constant price and cost case assumes that prices in effect at year-end
2007 adjusted for quality and transportation as well as the 2007 costs are
held constant over life. The constant price assumptions assume the
continuance of current laws, regulations and operating costs in effect on
the date of the Evaluation Report. Product prices have been held constant
at the 2008 values shown below. In addition, operating and capital costs
have not been increased on an inflationary basis.
The crude oil and natural gas constant prices used in the Evaluation
Reports are as follows (based on a foreign exchange rate of
US$1.01/C$1.00):
Natural gas
---------------------------------------------------------------------------
Company
average Henry Hub Huntingdon/
price Louisiana AECO Sumas
(Year) (C$/mcf) (US$/mmbtu) (C$/mmbtu) (C$/mmbtu)
---------------------------------------------------------------------------
2007 6.48 6.80 6.52 6.96
===========================================================================
Crude oil & NGLs
---------------------------------------------------------------------------
Company Hardisty
average WTI @ Heavy Edmonton North Sea
price Cushing(1) 12(0) API Par(2) Brent
(Year) (C$/bbl) (US$/bbl) (C$/bbl) (C$/bbl) (US$/bbl)
---------------------------------------------------------------------------
2007 62.87 96.00 41.70 93.44 96.02
===========================================================================
(1) "WTI @ Cushing" refers to the price of West Texas Intermediate crude
oil at Cushing, Oklahoma.
(2) "Edmonton Par" refers to the price of light gravity (40(0) API), low
sulphur content crude oil At Edmonton, Alberta.
10. The forecast price and cost cases 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 below and adjusted for quality and transportation. Reference
prices and costs are escalated at 2% per year. Future crude oil, NGLs and
natural gas price forecasts were based on Sproule's December 31, 2007 crude
oil, NGLs and natural gas pricing model.
32 CANADIAN NATURAL RESOURCES LIMITED
The Company's weighted average crude oil and NGLs price and the weighted average
natural gas price in the 2007 evaluation were $62.87 per barrel and $6.48 per
mcf respectively. The crude oil and natural gas forecast prices used in the
Evaluation Reports are as follows:
Natural gas
---------------------------------------------------------------------------
Company
average Henry Hub Huntingdon/
price Louisiana AECO Sumas
(Year) (C$/mcf) (US$/mmbtu) (C$/mmbtu) (C$/mmbtu)
---------------------------------------------------------------------------
2008 6.37 7.56 6.51 6.51
2009 7.07 8.27 7.22 7.22
2010 7.50 8.74 7.69 7.69
2011 7.49 8.75 7.70 7.70
2012 7.41 8.66 7.61 7.61
2013 7.45 8.83 7.78 7.78
2014 7.65 9.01 7.96 7.96
2015 7.84 9.19 8.14 8.14
2016 8.04 9.37 8.32 8.32
2017 8.25 9.56 8.51 8.51
2018 8.44 9.75 8.68 8.68
===========================================================================
Crude oil & NGLs
---------------------------------------------------------------------------
Company Hardisty
average WTI @ Heavy Edmonton North Sea
price Cushing(1) 12(0) API Par(2) Brent
(Year) (C$/bbl) (US$/bbl) (C$/bbl) (C$/bbl) (US$/bbl)
---------------------------------------------------------------------------
2008 65.51 89.61 54.67 88.17 87.61
2009 63.58 86.01 52.42 84.54 83.97
2010 61.86 84.65 51.56 83.16 82.57
2011 60.76 82.77 50.38 81.26 80.65
2012 60.90 82.26 50.05 80.73 80.10
2013 63.20 82.81 50.38 81.25 80.60
2014 63.53 84.46 51.39 82.88 82.21
2015 63.96 86.15 52.42 84.55 83.85
2016 65.04 87.87 53.47 86.25 85.53
2017 66.86 89.63 54.55 87.98 87.24
2018 67.43 91.42 55.64 89.74 88.99
===========================================================================
Note: Foreign exchange rate used was US$1.00/C$1.00 throughout the forecast
11. Estimated future net revenue from all assets is income derived from the
sale of net reserves of crude oil, natural gas and NGLs, less all capital
costs, production taxes, and operating costs and before provision for
income taxes, administrative overhead costs and existing asset abandonment
liabilities.
12. The estimated total development capital costs net to the Company necessary
to achieve the estimated future net "proved" and "proved and probable"
production revenues are:
Proved Proved & probable
Forecast Constant Forecast Constant
price price price price
($ millions) case case case case
--------------------------------------------------------------------------------
2008 1,642 1,632 1,851 1,841
2009 2,200 2,095 2,520 2,418
2010 1,092 1,023 1,482 1,408
2011 803 733 1,398 1,293
2012 945 836 1,540 1,388
2013 594 508 1,086 961
2014 338 286 653 570
2015 332 275 768 655
2016 339 253 587 472
2017 218 178 436 361
2018 201 160 350 285
2019 272 210 485 387
Thereafter 1,927 1,274 3,324 2,225
================================================================================
13. The Evaluation Reports involved data supplied by the Company with respect
to quality, heating value and transportation adjustments, interests owned,
royalties payable, operating costs and contractual commitments. This data
was found by Sproule and Ryder Scott to be reasonable and no field
inspection was conducted.
CANADIAN NATURAL RESOURCES LIMITED 33
A report on conventional reserves data by Sproule and Ryder Scott and a report
on oil sands mining reserves data by GLJ are provided in Schedule "A" to this
Annual Information Form. A report by the Company's management and directors on
crude oil and natural gas disclosure is provided in Schedule "B" to this Annual
Information Form. The Company does not file estimates of its total crude oil and
natural gas reserves with any U. S. agency or federal authority other than the
SEC.
C. RECONCILIATION OF CHANGES IN NET CONVENTIONAL RESERVES
The following table summarizes the changes during the past year in reserves
after deduction of royalties payable to others and using constant prices and
costs:
Crude oil & NGLs (mmbbl) | Natural gas (bcf)
------------------------ | -----------------
Offshore | Offshore
North North West | North North West
America Sea Africa Total | America Sea Africa Total
-------------------------------------------------------------------------------------|-------------------------------------------
PROVED RESERVES |
-------------------------------------------------------------------------------------|-------------------------------------------
RESERVES, DEC 31, 2005 694 290 134 1,118 | 2,741 29 72 2,842
-------------------------------------------------------------------------------------|-------------------------------------------
Extensions & discoveries 53 3 -- 56 | 250 -- -- 250
Infill drilling 190 14 -- 204 | 71 -- -- 71
Improved recovery -- 12 -- 12 | 3 -- -- 3
Property purchases 26 -- -- 26 | 1,111 -- -- 1,111
Property disposals -- -- -- -- | (1) -- -- (1)
Production (75) (22) (13) (110) | (433) (5) (3) (441)
Revisions of prior estimates (1) 2 9 10 | (37) 13 (13) (37)
-------------------------------------------------------------------------------------|-------------------------------------------
RESERVES, DEC 31, 2006 887 299 130 1,316 | 3,705 37 56 3,798
-------------------------------------------------------------------------------------|-------------------------------------------
Extensions & discoveries 30 -- -- 30 | 134 -- -- 134
Infill drilling 10 6 -- 16 | 124 3 -- 127
Improved recovery 3 -- -- 3 | 8 -- -- 8
Property purchases 1 -- -- 1 | 12 -- -- 12
Property disposals -- (3) -- (3) | -- -- -- --
Production (77) (20) (10) (107) | (503) (5) (4) (512)
Revisions of prior estimates 66 28 8 102 | 41 46 12 99
-------------------------------------------------------------------------------------|-------------------------------------------
RESERVES, DEC 31, 2007 920 310 128 1,358 | 3,521 81 64 3,666
-------------------------------------------------------------------------------------|-------------------------------------------
|
PROVED AND PROBABLE RESERVES |
-------------------------------------------------------------------------------------|-------------------------------------------
RESERVES, DEC 31, 2005 1,035 417 206 1,658 | 3,548 69 110 3,727
-------------------------------------------------------------------------------------|-------------------------------------------
Extensions & discoveries 128 3 -- 131 | 307 -- -- 307
Infill drilling 384 17 -- 401 | 95 -- -- 95
Improved recovery -- 12 -- 12 | 4 -- -- 4
Property purchases 34 -- -- 34 | 1,466 -- -- 1,466
Property disposals -- -- -- -- | (1) -- -- (1)
Production (75) (22) (13) (110) | (433) (5) (3) (441)
Revisions of prior estimates (4) (5) 2 (7) | (129) 29 (8) (108)
-------------------------------------------------------------------------------------|-------------------------------------------
RESERVES, DEC 31, 2006 1,502 422 195 2,119 | 4,857 93 99 5,049
-------------------------------------------------------------------------------------|-------------------------------------------
Extensions & discoveries 41 -- -- 41 | 177 -- -- 177
Infill drilling 52 6 -- 58 | 163 3 -- 166
Improved recovery 4 -- -- 4 | 8 -- -- 8
Property purchases 2 6 -- 8 | 17 1 -- 18
Property disposals -- (3) -- (3) | (1) -- -- (1)
Production (77) (20) (10) (107) | (503) (5) (4) (512)
Revisions of prior estimates 21 (6) 1 16 | (116) 21 (7) (102)
-------------------------------------------------------------------------------------|-------------------------------------------
RESERVES, DEC 31, 2007 1,545 405 186 2,136 | 4,602 113 88 4,803
=====================================================================================|===========================================
34 CANADIAN NATURAL RESOURCES LIMITED
Information on the Company's conventional crude oil, NGLs and natural gas
reserves is provided in accordance with United States FAS 69, "Disclosures About
Oil and Gas Producing Activities" in the Company's Form 40-F filed with the SEC
and in the Company's 2007 Annual Report under "Supplementary Oil and Gas
Information" on pages 97 to 101 and is incorporated herein by reference.
D. OIL SANDS MINING DISCLOSURE
INTRODUCTION
Canadian Natural holds a 100% working interest in its Athabasca Oil Sands leases
in Northern Alberta, of which a portion (being lease 18), is subject to a 5% net
carried interest in the bitumen development. The Horizon Project was initiated
in 2000 to evaluate the potential for mining and processing the oil sands on
these leases.
The Horizon Project is located in northeastern Alberta approximately 70
kilometers north of Fort McMurray in Townships 96 and 97, Ranges 11, 12 and 13,
west of the 4th Meridian. The project site is accessible by a private road as
well as a private airstrip. Figure 1 shows the location of the Horizon Project
within Alberta, Canada and within the region. The leases being developed for the
Horizon Project are 18, 25, 10, 19 and 20. Synthetic crude oil production is
targeted for the third quarter of 2008 ramping up to 110,000 bbl/d and is
targeted to reach 232,000 bbl/d with future expansion. Mining of the oil sands
will be done using conventional truck and shovel technology. The ore is then
processed through extraction and froth treatment to produce bitumen, which is
upgraded on-site into synthetic crude oil. The synthetic crude oil is
transported from the site by pipeline to the Edmonton area for distribution. An
on-site cogeneration plant provides power and steam for the operation.
An independent qualified reserves evaluator, GLJ, was retained to evaluate 100%
of the first three phases of the Horizon Project's development plan. GLJ's
Evaluation Report indicates that the gross lease proved and probable reserves
associated with the Horizon Project are approximately 3.0 billion barrels of
synthetic crude oil with a production life of 39 years.
Since 1999, Canadian Natural has acquired over 46,000 hectares, comprising 11
leases in the Fort McMurray area.
CANADIAN NATURAL RESOURCES LIMITED 35
FIGURE 1 - LOCATION OF THE HORIZON OIL SANDS PROJECT
[GRAPHIC OMITTED]
TABLE 1 - CANADIAN NATURAL ATHABASCA REGION OIL SAND LEASES
Short Official Lease Area
lease lease expiry in
name number date(1) hectares
--------------------------------------------------------------------------------
Lease 18 727912T18 Continued Producing(2) 19,988
Lease 10 7400120010 December 14, 2015 3,840
Lease 25 7401050025 May 17, 2016 1,536
Lease 11 7400120011 December 14, 2015 518
Lease 12 7400120012 December 14, 2015 9,216
Lease 13 7400120013 December 14, 2015 69
Lease 15 7400120015 December 14, 2015 1,536
Lease 19 7402050019 May 30, 2017 5,120
Lease 20 7402050020 May 30, 2017 768
Lease 6 7597050T06 May 6, 2012 2,584
Lease 7 7597050T07 May 6, 2012 1,144
================================================================================
(1) The company can apply for an extension of the leases past the expiry date.
(2) Pursuant to section 14 of the Oil Sands Tenure Regulation.
Lease 18, the main oil sand lease for the Horizon Project, has a gradual
topographic slope from west to east. To the west, the topography begins to rise
into the Birch Mountains and reaches an elevation of 485 meters above sea level
in the northwest corner of the lease. To the east, the elevation drops sharply
at the Athabasca River escarpment to 230 meters above sea level along the river.
The Tar and Calumet Rivers flow through the lease.
36 CANADIAN NATURAL RESOURCES LIMITED
PROJECT DEVELOPMENT
On June 28, 2002, pursuant to Sections 10 and 11 of the Oil Sands Conservation
Act, Canadian Natural filed Application No. 1273113 for approval for an oil
sands mine, a bitumen extraction plant, a bitumen upgrader and associated
facilities for the proposed Horizon Project. As part of the application to the
Alberta Energy and Utilities Board ("EUB"), the Company also submitted an
Environmental Impact Assessment ("EIA") report to the Director of the Regulatory
Assurance Division, Alberta Environment, pursuant to the Environmental
Protection Enhancement Act ("EPEA"). On June 26, 2003, the Federal Minister of
Fisheries and Oceans referred the EIA of the project to a review panel charged
with fulfilling the review as required by both the Canadian Environmental
Assessment Act ("CEAA") and the Energy Resources Conservation Act ("ERCA"). A
public hearing was held in Fort McMurray, Alberta on September 15-19, 22-26 and
29, 2003. The application and hearing provided significant background detail on
the geology, mine planning and development scheme and formed the basis for the
approval from the EUB in February 2004 and Alberta Environment ("AENV") under
the Environmental Protection and Enhancement Act, in April 2004.
The following are the primary regulatory applications and approvals for the
Horizon Project, which contain information pertaining to the project of a
material engineering, geologic or metallurgic nature:
1. Application for Approval of Horizon Oil Sands Project submitted in June
2002 to the EUB (Application No.1273113) and AENV (Application No.
001-149968) (available at the EUB library, 640 5th Ave. SW, Calgary,
Alberta - Tel: (403) 297-8311).
2. Supplemental Information for the Horizon Oil Sands Project (Application No.
1273113 and Application No. 001-149968) submitted in March 2003 to the EUB
and AENV) (available at the EUB library, 640 5th Ave. SW, Calgary, Alberta
- Tel: (403) 297-8311).
3. Horizon Oil Sands Project Decision 2004-005 by a joint panel review
established by the EUB and the Government of Canada dated January 27, 2004
(available online at www.eub.gov.ab.ca).
4. Horizon Oil Sands Project Order in Council Authorization 26/2004 by the
Province of Alberta dated February 4, 2004 (available at the EUB library,
640 5th Ave. SW, Calgary, Alberta - Tel: (403) 297-8311).
5. Horizon Oil Sands Project Approval No. 9752 by the EUB dated February 10,
2004 (available at the EUB library, 640 5th Ave. SW, Calgary, Alberta -
Tel: (403) 297-8311).
6. Horizon Oil Sands Project Environmental Protection and Enhancement Act
Approval No. 149968-00-01 from AENV dated April 6, 2004 (available online
at WWW.GOV.AB.CA/ENV/WATER/APPROVALVIEWER.HTML search parameter - Approval
No. 149968-00-01).
7. Horizon Oil Sands Project Water Act Approval No. 00201931-00-00 from AENV
dated April 6, 2004 (available online at
WWW.GOV.AB.CA/ENV/WATER/APPROVALVIEWER.HTML search parameter - Approval No.
149968-00-01).
As of year-end 2007, key development achievements associated with the Horizon
Project were as follows:
|X| Phase 1 work progress is 90% complete.
|X| Mine overburden has removed 49.9 million bank cubic meters of material.
CANADIAN NATURAL RESOURCES LIMITED 37
REGIONAL AND PROJECT GEOLOGY
In the area of the Horizon Project, the oil sands resource is found within the
Cretaceous McMurray Formation. The McMurray Formation is comprised of a sequence
of uncemented quartz sands and associated shales that reside above the
unconformity with the underlying Upper Devonian carbonates (limestone) of the
Waterways Formation. The general stratigraphy of the Horizon Project is shown in
Figure 2.
The McMurray Formation was formed by the infilling of a broad northwest trending
depression in the exposed Devonian limestone landscape by mostly non-marine and
estuarine sediments about 115 million years ago. The deposition of these
terrestrial derived sediments ended when the Boreal Sea transgressed the entire
region, ushering in marine conditions that formed the Clearwater Formation
shales and glauconitic Wabiskaw member. This interplay between rising sea level
and sediment transport from the northeast gave rise to various depositional
environments (fluvial, estuarine, and marine). The entire McMurray/Clearwater
succession was (most recently about 10,000 years ago) covered by unconsolidated
sands, silts, and clays (glacial drift) deposited by glaciers as they melted and
receded from the region at the end of the last ice age.
The McMurray Formation at the site of the Horizon Project is subdivided into
three informal members: lower, middle, and upper. These informal divisions
correspond to changes in the depositional environments within the McMurray from
predominantly fluvial to tidal/estuarine through to tidal/marine conditions.
Most of the Horizon Project's oil sands resource is found within the lower and
middle McMurray.
The lower McMurray, where present, is comprised of predominantly fluvial channel
deposits. The lower McMurray occupies lows on the Devonian (Paleozoic) surface
resulting in the thickest McMurray intervals. Clean sands in these fluvial
channels result in excellent quality ore. Flood plain deposits of significant
thickness are found in the upper portions of the lower McMurray and are
typically removed as waste. In the deepest portions of the mine area, the lower
McMurray is comprised of "water sands". These sands are barren of bitumen;
having never been saturated with bitumen or, in some places, originally
containing bitumen that has since been removed from the sands through the
movement of basal waters over time producing "swept" zones.
The middle McMurray is comprised of thick estuarine channel successions and
tidal flat deposits resulting in interbedded sands and muds. The estuarine
channel sands provide good quality ore. The muddier intervals within the
channels and the tidal flat deposits within the middle McMurray represent zones
of interburden in the mining area.
The upper McMurray consists of shoreface/channel transition deposits and is
typically thin, less than five meters. Locally, this member may be entirely
eroded. Exceptional thickness of about 15 meters can be found within the upper
McMurray. In most cases, the bitumen saturation in the upper McMurray is poor
and the material is included with the overburden.
38 CANADIAN NATURAL RESOURCES LIMITED
FIGURE 2 - GENERAL STRATIGRAPHY OF THE HORIZON OIL SANDS PROJECT
[GRAPHIC OMITTED]
HORIZON OIL SANDS PROJECT MINING RESERVES
For the year ended December 31, 2007, the Company retained GLJ to evaluate 100%
of Phase 1 to Phase 3 of the Horizon Project and prepare an Evaluation Report on
the Company's proved, and probable oil sands mining reserves incorporating both
the mining and upgrading projects. These reserves were evaluated adhering to the
requirements of SEC Industry Guide 7 using constant pricing and have been
disclosed separately from the Company's conventional proved and probable crude
oil, NGLs and natural gas reserves.
The pit limits and mine plans were evaluated in 2007 incorporating the results
from the most recent and past drilling programs. Figure 3 shows the mining areas
associated with the reserves and Figure 4 shows the drill hole coverage used to
develop the mine plan. The oil sands mining reserves from GLJ's Evaluation
Report are provided in Table 2. The 3.0 billion barrels of gross lease proved
and probable synthetic crude oil reserves shown in the table are produced from
39 years of projected production commencing in 2008.
The Reserve Committee of the Company's Board of Directors has met with and
carried out independent due diligence procedures with GLJ to review the
qualifications of and procedures used by the evaluator in determining the
estimate of the Company's oil sands mining reserves.
CANADIAN NATURAL RESOURCES LIMITED 39
FIGURE 3 - HORIZON OIL SANDS PROJECT RESOURCE AREAS AND GENERAL LAYOUT
[GRAPHIC OMITTED]
40 CANADIAN NATURAL RESOURCES LIMITED
FIGURE 4 - HORIZON OIL SANDS PROJECT CORE HOLE COVERAGE
[GRAPHIC OMITTED]
CANADIAN NATURAL RESOURCES LIMITED 41
OIL SANDS MINING RESERVES
The following table sets out Canadian Natural's reserves of bitumen and
synthetic crude oil from the Horizon Project as of December 31, 2007:
Constant Prices
--------------------------------------------------------------------------------
Bitumen Synthetic crude oil
(mmbbl) (1) (mmbbl)
Gross Gross
Lease (2) Net Lease (2) Net
--------------------------------------------------------------------------------
Total proved
reserves 2,385 1,995 1,956 1,761
Total Proved and
probable reserves 3,525 2,969 2,958 2,680
================================================================================
(1) Synthetic crude oil reserves are based on the upgrading of bitumen using
technologies implemented at the Horizon Project. the reserves shown for
bitumen and synthetic crude oil are not additive.
(2) Gross Lease reserves are the total remaining recoverable reserves on the
lease before consideration of Company interests or royalties.
E. CRUDE OIL, NGLS AND NATURAL GAS PRODUCTION
The Company's working interest share of crude oil, NGLs and natural gas
production and revenues received for the last three financial years is
summarized in the following tables:
Year Ended Dec 31
2007 2006 2005
--------------------------------------------------------------------------------
Daily production, before
royalties
Crude oil and NGLs (bbl/d) 331,232 331,998 313,168
Natural gas (mmcf/d) 1,668 1,492 1,439
--------------------------------------------------------------------------------
Annual production, before
royalties
Crude oil and NGLs (mbbl) 120,900 121,179 114,306
Natural gas (bcf) 609 545 525
================================================================================
42 CANADIAN NATURAL RESOURCES LIMITED
NETBACKS
INFORMATION BY QUARTER
2007
-------------------------------------------------------------------------------------
YEAR
Q1 Q2 Q3 Q4 ENDED
-------------------------------------------------------------------------------------
AVERAGE DAILY PRODUCTION
VOLUMES, BEFORE ROYALTIES
Crude oil and
NGLs (bbl/d) 327,001 327,494 333,062 337,240 331,232
Natural gas (mmcf/d) 1,717 1,722 1,647 1,589 1,668
-------------------------------------------------------------------------------------
PRODUCT NETBACKS
Crude oil and
NGLs ($/bbl)
Sales price (1) $ 51.71 $ 53.74 $ 58.10 $ 58.03 $ 55.45
Royalties 4.92 5.46 6.65 6.66 5.94
Production
expenses 13.81 15.01 13.13 11.53 13.34
-------------------------------------------------------------------------------------
NETBACK $ 32.98 $ 33.27 $ 38.32 $ 39.84 $ 36.17
-------------------------------------------------------------------------------------
Natural gas ($/mcf)
Sales price (1) $ 7.74 $ 7.44 $ 5.87 $ 6.28 $ 6.85
Royalties 1.48 1.10 0.89 0.94 1.11
Production
expenses 0.97 0.89 0.88 0.91 0.91
-------------------------------------------------------------------------------------
NETBACK $ 5.29 $ 5.45 $ 4.10 $ 4.43 $ 4.83
-------------------------------------------------------------------------------------
CRUDE OIL AND NGLS
NETBACKS BY TYPE
Light/Pelican Lake/
NGLs ($/bbl)
Sales price (1) $ 60.19 $ 64.10 $ 67.34 $ 72.62 $ 65.99
Royalties 4.89 5.87 7.24 8.34 6.57
Production
expenses 13.85 14.91 14.40 12.64 13.95
-------------------------------------------------------------------------------------
NETBACK $ 41.45 $ 43.32 $ 45.70 $ 51.64 $ 45.47
-------------------------------------------------------------------------------------
Heavy crude
oil ($/bbl)
Sales price (1) $ 41.24 $ 41.85 $ 48.10 $ 43.06 $ 43.66
Royalties 4.96 4.98 6.00 4.95 5.23
Production
expenses 13.76 15.12 11.75 10.38 12.66
-------------------------------------------------------------------------------------
NETBACK $ 22.52 $ 21.75 $ 30.35 $ 27.73 $ 25.77
=====================================================================================
2006
-------------------------------------------------------------------------------------
YEAR
Q1 Q2 Q3 Q4 ENDED
-------------------------------------------------------------------------------------
AVERAGE DAILY PRODUCTION
VOLUMES, BEFORE ROYALTIES
Crude oil and
NGLs (bbl/d) 323,662 338,852 321,665 343,705 331,998
Natural gas (mmcf/d) 1,436 1,475 1,437 1,620 1,492
-------------------------------------------------------------------------------------
PRODUCT NETBACKS
Crude oil and
NGLs ($/bbl)
Sales price (1) $ 43.79 $ 60.05 $ 62.55 $ 47.27 $ 53.65
Royalties 3.48 5.14 5.11 4.10 4.48
Production
expenses 11.33 11.92 13.47 12.32 12.29
-------------------------------------------------------------------------------------
NETBACK $ 28.98 $ 42.99 $ 43.97 $ 30.85 $ 36.88
-------------------------------------------------------------------------------------
Natural gas ($/mcf)
Sales price (1) $ 8.30 $ 6.16 $ 5.83 $ 6.66 $ 6.72
Royalties 1.70 1.11 1.11 1.26 1.29
Production
expenses 0.80 0.80 0.84 0.86 0.82
-------------------------------------------------------------------------------------
NETBACK $ 5.80 $ 4.25 $ 3.88 $ 4.54 $ 4.61
-------------------------------------------------------------------------------------
CRUDE OIL AND NGLS
NETBACKS BY TYPE
Light/Pelican Lake/
NGLs ($/bbl)
Sales price (1) $ 58.28 $ 69.02 $ 71.65 $ 57.68 $ 64.33
Royalties 4.65 5.53 5.39 4.39 5.00
Production
expenses 11.15 11.18 14.12 12.99 12.42
-------------------------------------------------------------------------------------
NETBACK $ 42.48 $ 52.31 $ 52.14 $ 40.30 $ 46.91
-------------------------------------------------------------------------------------
Heavy crude
oil ($/bbl)
Sales price (1) $ 25.22 $ 50.08 $ 51.38 $ 36.11 $ 41.20
Royalties 1.98 4.71 4.76 3.78 3.88
Production
expenses 11.55 12.73 12.67 11.60 12.15
-------------------------------------------------------------------------------------
NETBACK $ 11.69 $ 32.64 $ 33.95 $ 20.73 $ 25.17
=====================================================================================
NOTE: PELICAN LAKE CRUDE OIL HAS AN API OF 14(0) TO 17(0), BUT RECEIVES MEDIUM
QUALITY CRUDE NETBACKS DUE TO LOWER PRODUCTION COSTS AND LOWER ROYALTY RATES.
(1) Net of transportation and blending costs and excluding risk management
activities.
CANADIAN NATURAL RESOURCES LIMITED 43
NETBACKS
INFORMATION BY QUARTER
2005
Year
Q1 Q2 Q3 Q4 Ended
------------------------------------------------------------------------------------
AVERAGE DAILY PRODUCTION VOLUMES
Crude oil and NGLs
(bbl/d) 287,803 289,064 334,724 340,268 313,168
Natural gas (mmcf/d) 1,455 1,454 1,423 1,423 1,439
------------------------------------------------------------------------------------
PRODUCT NETBACKS
Crude oil and NGLs ($/bbl)
Sales price (1) $ 39.81 $ 42.51 $ 57.35 $ 46.38 $ 46.86
Royalties 3.39 3.33 5.11 3.89 3.97
Production
expenses 11.30 11.66 11.48 10.33 11.17
------------------------------------------------------------------------------------
Netback $ 25.12 $ 27.52 $ 40.76 $ 32.16 $ 31.72
------------------------------------------------------------------------------------
Natural gas ($/mcf)
Sales price (1) $ 6.68 $ 7.33 $ 8.61 $ 11.67 $ 8.57
Royalties 1.30 1.48 1.93 2.30 1.75
Production
expenses 0.69 0.71 0.76 0.76 0.73
------------------------------------------------------------------------------------
Netback $ 4.69 $ 5.14 $ 5.92 $ 8.61 $ 6.09
------------------------------------------------------------------------------------
CRUDE OIL AND NGLS NETBACKS BY TYPE
Light/Pelican Lake/
NGLs ($/bbl)
Sales price (1) $ 53.14 $ 56.85 $ 66.81 $ 8.87 $ 59.16
Royalties 5.20 4.55 5.50 4.40 4.90
Production
expenses 11.58 12.28 11.47 8.90 10.93
------------------------------------------------------------------------------------
Netback $ 36.36 $ 40.02 $ 49.84 $ 45.57 $ 43.33
------------------------------------------------------------------------------------
Heavy crude oil ($/bbl)
Sales price (1) $ 25.21 $ 27.82 $ 47.25 $ 30.27 $ 33.09
Royalties 1.41 2.07 4.83 3.08 2.92
Production
expenses 11.00 11.03 11.50 12.18 11.44
------------------------------------------------------------------------------------
Netback $ 12.80 $ 14.72 $ 30.92 $ 15.01 $ 18.73
=====================================================================================
NOTE: PELICAN LAKE CRUDE OIL HAS AN API OF 14(0) TO 17(0), BUT RECEIVES MEDIUM
QUALITY CRUDE NETBACKS DUE TO LOWER PRODUCTION COSTS AND LOWER ROYALTY RATES.
(1) NET OF TRANSPORTATION AND BLENDING COSTS AND EXCLUDING RISK MANAGEMENT
ACTIVITIES.
44 CANADIAN NATURAL RESOURCES LIMITED
2007
YEAR
Q1 Q2 Q3 Q4 ENDED
-------------------------------------------------------------------------------------
SEGMENTED
NORTH AMERICA PRODUCT
NETBACKS
Light/Pelican Lake/NGLs
($/bbl)
Sales price (1) $ 54.13 $ 56.06 $ 60.26 $ 63.94 $ 58.66
Royalties 8.84 9.22 11.55 12.56 10.57
Production
expenses 11.74 12.11 11.58 10.82 11.56
-------------------------------------------------------------------------------------
NETBACK $ 33.55 $ 34.73 $ 37.13 $ 40.56 $ 36.53
-------------------------------------------------------------------------------------
Heavy crude oil ($/bbl)
Sales price (1) $ 41.24 $ 41.85 $ 48.10 $ 43.06 $ 43.66
Royalties 4.96 4.98 6.00 4.95 5.23
Production
expenses 13.76 15.12 11.75 10.38 12.66
-------------------------------------------------------------------------------------
NETBACK $ 22.52 $ 21.75 $ 30.35 $ 27.73 $ 25.77
-------------------------------------------------------------------------------------
Natural gas ($/mcf)
Sales price (1) $ 7.79 $ 7.47 $ 5.88 $ 6.31$ 6.87
Royalties 1.50 1.11 0.90 0.95 1.12
Production
expenses 0.95 0.87 0.87 0.90 0.90
-------------------------------------------------------------------------------------
NETBACK $ 5.34 $ 5.49 $ 4.11 $ 4.46 $ 4.85
-------------------------------------------------------------------------------------
NORTH SEA PRODUCT NETBACKS
Light crude oil ($/bbl)
Sales price (1) $ 68.83 $ 73.18 $ 77.55 $ 83.44 $ 74.99
Royalties 0.13 0.13 0.14 0.19 0.14
Production
expenses 18.57 22.11 23.61 18.95 20.78
-------------------------------------------------------------------------------------
NETBACK $ 50.13 $ 50.94 $ 53.80 $ 64.30 $ 54.07
-------------------------------------------------------------------------------------
Natural Gas ($/mcf)
Sales price (1) $ 4.49 $ 3.92 $ 5.26 $ 3.62 $ 4.26
Royalties -- -- -- -- --
Production
expenses 2.58 2.26 2.29 1.50 2.17
-------------------------------------------------------------------------------------
NETBACK $ 1.91 $ 1.66 $ 2.97 $ 2.12$ 2.09
-------------------------------------------------------------------------------------
OFFSHORE WEST AFRICA PRODUCT
NETBACKS
Light crude oil ($/bbl)
Sales price (1) $ 58.60 $ 72.84 $ 70.52 $ 81.89 $ 71.68
Royalties 3.70 7.12 6.81 7.59 6.40
Production
expenses 8.93 7.98 7.00 9.32 8.32
------------------------------------------------------------------------------------
NETBACK $ 45.97 $ 57.74 $ 56.71 $ 64.98 $ 56.96
-------------------------------------------------------------------------------------
Natural gas ($/mcf)
Sales price (1) $ 5.97 $ 6.22 $ 5.31 $ 5.49 $ 5.68
Royalties 0.38 0.59 0.51 0.52 0.51
Production
expenses 1.48 1.10 1.39 1.89 1.48
------------------------------------------------------------------------------------
NETBACK $ 4.11 $ 4.53 $ 3.41 $ 3.08 $ 3.69
======================================================================================
2006
Year
Q1 Q2 Q3 Q4 Ended
-----------------------------------------------------------------------------------
SEGMENTED
NORTH AMERICA PRODUCT
NETBACKS
Light/Pelican Lake/NGLs
($/bbl)
Sales price (1) $ 48.83 $ 64.35 $ 65.15 $ 48.47 $ 56.52
Royalties 8.98 10.87 10.86 7.80 9.59
Production
expenses 9.86 9.75 10.81 13.18 10.93
-----------------------------------------------------------------------------------
NETBACK $ 29.99 $ 43.73 $ 43.48 $ 27.49 $ 36.00
-------------------------------------------------------------------------------------
Heavy crude oil ($/bbl)
Sales price (1) $ 25.22 $ 50.08 $ 51.38 $ 36.11 $ 41.20
Royalties 1.98 4.71 4.76 3.78 3.88
Production
expenses 11.55 12.73 12.67 11.60 12.15
-----------------------------------------------------------------------------------
NETBACK $ 11.69 $ 32.64 $ 33.95 $ 20.73 $ 25.17
-------------------------------------------------------------------------------------
Natural gas ($/mcf)
Sales price (1) $ 8.39 $ 6.21 $ 5.86 $ 6.70 $ 6.77
Royalties 1.73 1.13 1.12 1.29 1.31
Production
expenses 0.79 0.79 0.83 0.84 0.81
-----------------------------------------------------------------------------------
NETBACK $ 5.87 $ 4.29 $ 3.91 $ 4.57 $ 4.65
-------------------------------------------------------------------------------------
NORTH SEA PRODUCT NETBACKS
Light crude oil ($/bbl)
Sales price (1) $ 68.05 $ 73.19 $ 78.68 $ 67.72 $ 72.62
Royalties 0.12 0.17 0.11 0.14 0.13
Production
expenses 16.85 17.18 20.28 14.76 17.57
------------------------------------------------------------------------------------
NETBACK $ 51.08 $ 55.84 $ 58.29 $ 52.82 $ 54.92
-------------------------------------------------------------------------------------
Natural Gas ($/mcf)
Sales price (1) $ 2.38 $ 2.33 $ 2.38 $ 3.48 $ 2.66
Royalties -- -- -- -- --
Production
expenses 1.26 1.47 1.30 1.54 1.40
-----------------------------------------------------------------------------------
NETBACK $ 1.12 $ 0.86 $ 1.08 $ 1.94 $ 1.26
-------------------------------------------------------------------------------------
OFFSHORE WEST AFRICA PRODUCT
NETBACKS
Light crude oil ($/bbl)
Sales price (1) $ 65.23 $ 72.97 $ 70.59 $ 63.50 $ 67.99
Royalties 1.55 1.87 4.89 3.02 2.81
Production
expenses 6.08 5.61 7.97 10.05 7.45
-----------------------------------------------------------------------------------
NETBACK $ 57.60 $ 65.49 $ 57.73 $ 50.43 $ 57.73
-------------------------------------------------------------------------------------
Natural gas ($/mcf)
Sales price (1) $ 5.59 $ 5.30 $ 4.97 $ 5.72 $ 5.37
Royalties 0.13 0.14 0.34 0.27 0.22
Production
expenses 1.00 0.36 1.39 2.01 1.19
-----------------------------------------------------------------------------------
NETBACK $ 4.46 $ 4.80 $ 3.24 $ 3.44 $ 3.96
=====================================================================================
NOTE: PELICAN LAKE CRUDE OIL HAS AN API OF 14(0) TO 17(0), BUT RECEIVES MEDIUM
QUALITY CRUDE NETBACKS DUE TO LOWER PRODUCTION COSTS AND LOWER ROYALTY RATES.
(1) NET OF TRANSPORTATION AND BLENDING COSTS AND EXCLUDING RISK MANAGEMENT
ACTIVITIES.
CANADIAN NATURAL RESOURCES LIMITED 45
2005
Year
Q1 Q2 Q3 Q4 Ended
--------------------------------------------------------------------------------------
SEGMENTED
NORTH AMERICA PRODUCT NETBACKS
Light/Pelican Lake/NGLs ($/bbl)
Sales price (1) $ 45.80 $ 49.78 $ 61.21 $ 52.10 $ 52.35
Royalties 10.64 8.77 11.49 9.62 10.13
Production
expenses 8.30 8.40 9.27 8.60 8.65
-------------------------------------------------------------------------------------
NETBACK $ 26.86 $ 32.61 $ 40.45 $ 33.88 $ 33.57
-------------------------------------------------------------------------------------
Heavy Crude Oil ($/bbl)
Sales price (1) $ 25.21 $ 27.82 $ 47.25 $ 30.27 $ 33.09
Royalties 1.41 2.07 4.83 3.08 2.92
Production
expenses 11.00 11.03 11.50 12.18 11.44
-------------------------------------------------------------------------------------
NETBACK $ 12.80 $ 14.72 $ 30.92 $ 15.01 $ 18.73
-------------------------------------------------------------------------------------
Natural gas ($/mcf)
Sales price (1) $ 6.73 $ 7.38 $ 8.69 $ 11.79 $ 8.65
Royalties 1.33 1.50 1.96 2.34 1.78
Production
expenses 0.66 0.68 0.74 0.74 0.71
-------------------------------------------------------------------------------------
NETBACK $ 4.74 $ 5.20 $ 5.99 $ 8.71 $ 6.16
-------------------------------------------------------------------------------------
NORTH SEA PRODUCT NETBACKS
Light crude oil ($/bbl)
Sales price (1) $ 59.56 $ 64.81 $ 74.46 $ 66.88 $ 66.57
Royalties 0.05 0.11 0.12 0.14 0.10
Production
expenses 14.91 17.41 15.15 12.11 14.94
-------------------------------------------------------------------------------------
NETBACK $ 44.60 $ 47.29 $ 59.19 $ 54.63 $ 51.53
-------------------------------------------------------------------------------------
Natural gas ($/mcf)
Sales price (1) $ 3.52 $ 3.07 $ 2.64 $ 3.40 $ 3.17
Royalties -- -- -- -- --
Production
expenses 2.52 2.92 2.30 1.96 2.44
-------------------------------------------------------------------------------------
NETBACK $ 1.00 $ 0.15 $ 0.34 $ 1.44 $ 0.73
-------------------------------------------------------------------------------------
OFFSHORE WEST AFRICA PRODUCT
NETBACKS
Light crude oil ($/bbl)
Sales price (1) $ 62.34 $ 58.24 $ 59.09 $ 60.19 $ 59.91
Royalties 1.90 1.81 1.54 1.57 1.62
Production
expenses 11.43 8.47 5.81 5.62 6.50
-------------------------------------------------------------------------------------
NETBACK $ 49.01 $ 47.96 $ 51.74 $ 53.00 $ 51.79
-------------------------------------------------------------------------------------
Natural gas ($/mcf)
Sales price (1) $ 7.67 $ 6.88 $ 5.52 $ 5.13 $ 5.91
Royalties 0.23 0.21 0.13 0.14 0.16
Production
expenses 1.25 1.37 1.09 0.80 1.05
-------------------------------------------------------------------------------------
NETBACK $ 6.19 $ 5.30 $ 4.30 $ 4.19 $ 4.70
=====================================================================================
NOTE: PELICAN LAKE CRUDE OIL HAS AN API OF 14(0) TO 17(0), BUT RECEIVES MEDIUM
QUALITY CRUDE NETBACKS DUE TO LOWER PRODUCTION COSTS AND LOWER ROYALTY RATES.
(1) NET OF TRANSPORTATION AND BLENDING COSTS AND EXCLUDING RISK MANAGEMENT
ACTIVITIES.
46 CANADIAN NATURAL RESOURCES LIMITED
F. HISTORICAL DRILLING ACTIVITY BY PRODUCT
The following table sets forth the gross and net wells in which the Company has
participated for the period indicated:
Year Ended Dec 31
2007 2006
--------------------------------------------------------------------------------
GROSS NET Gross Net
--------------------------------------------------------------------------------
Natural gas 478 383 855 641
Crude oil 655 592 666 603
Service/Stratigraphic 256 254 376 375
Dry holes 107 93 133 119
--------------------------------------------------------------------------------
Total 1,496 1,322 2,030 1,738
--------------------------------------------------------------------------------
Total success rate (excluding
service and stratigraphic
test wells) 91% 91%
================================================================================
G. NET CAPITAL EXPENDITURES
Costs incurred by the Company in respect of its programs of acquisition and
disposition, and exploration and development of crude oil and natural gas
properties, are summarized in the following tables. Net capital expenditures do
not include non-cash property, plant and equipment additions and disposals.
Year Ended Dec 31
($ millions) 2007 2006
-------------------------------------------------------------------------------
Net property (dispositions)
aquisitions (1) $ (39) $ 4,733
Land acquisition and retention 95 210
Seismic evaluations 124 130
Well drilling, completion and equipping 1,642 2,340
Production and related facilities 1,205 1,314
-------------------------------------------------------------------------------
Total net reserve replacement
expenditures 3,027 8,727
-------------------------------------------------------------------------------
Horizon Project:
Phase 1 construction costs 2,740 2,768
Phase 2/3 costs 124 79
Capitalized interest, stock-based
compensation and other 437 338
-------------------------------------------------------------------------------
Total Horizon Project 3,301 3,185
-------------------------------------------------------------------------------
Midstream 6 12
Abandonments ((2)) 71 75
Head office 20 26
-------------------------------------------------------------------------------
TOTAL NET CAPITAL EXPENDITURES $ 6,425 12,025
================================================================================
CANADIAN NATURAL RESOURCES LIMITED 47
CAPITAL EXPENDITURES BY QUARTER
2007 Three Months Ended
($ millions) Mar 31 Jun 30 Sep 30 Dec 31
----------------------------------------------------------------------------------------
Net property acquisitions (dispositions) (1) $ 46 $ 15 $ 7 $ (107)
Land acquisition and retention 29 22 29 15
Seismic evaluation 50 34 23 17
Well drilling, completion and equipping 714 288 299 341
Production and related facilities 334 243 238 390
----------------------------------------------------------------------------------------
Total net reserve replacement expenditures 1,173 602 596 656
----------------------------------------------------------------------------------------
Horizon Project:
Phase 1 construction costs 674 704 671 691
Phase 2/3 costs 44 19 28 33
Capitalized interest, stock-based
compensation and other 91 118 120 108
----------------------------------------------------------------------------------------
Total Horizon Project 809 841 819 832
----------------------------------------------------------------------------------------
Midstream 2 -- 2 2
Abandonments ((2)) 20 13 22 16
Head office 5 4 3 8
----------------------------------------------------------------------------------------
Total net capital expenditures $ 2,009 $ 1,460 $ 1,442 $ 1,514
========================================================================================
CAPITAL EXPENDITURES BY QUARTER
2006 Three Months Ended
($ millions) Mar 31 Jun 30 Sep 30 Dec 31
----------------------------------------------------------------------------------------
Net property acquisitions (dispositions) (1) $ 12 $ 7 $ (6) $ 4,720
Land acquisition and retention 99 54 29 28
Seismic evaluation 52 35 26 17
Well drilling, completion and equipping 936 418 524 462
Production and related facilities 500 233 270 311
----------------------------------------------------------------------------------------
Total net reserve replacement expenditures 1,599 747 843 5,538
----------------------------------------------------------------------------------------
Horizon Project
Phase 1 construction costs 616 680 727 745
Phase 2/3 costs 1 6 18 54
Capitalized interest, stock-based
compensation and other 69 96 39 134
----------------------------------------------------------------------------------------
Total Horizon Project 686 782 784 933
----------------------------------------------------------------------------------------
Midstream 3 6 2 1
Abandonments ((2)) 15 17 24 19
Head office 6 6 8 6
----------------------------------------------------------------------------------------
Total net capital expenditures $ 2,309 $ 1,558 $ 1,661 $ 6,497
========================================================================================
(1) INCLUDES BUSINESS COMBINATIONS.
(2) ABANDONMENTS REPRESENT EXPENDITURES TO SETTLE ASSET RETIREMENT OBLIGATIONS
AND HAVE BEEN REFLECTED AS CAPITAL EXPENDITURES IN THIS TABLE.
48 CANADIAN NATURAL RESOURCES LIMITED
H. UNDEVELOPED ACREAGE
The following table summarizes the Company's working interest holdings in core
region undeveloped acreage as at December 31, 2007:
(thousands) Gross Acres Net Acres
--------------------------------------------------------------------------------
North America
Alberta 10,563 9,001
British Columbia 3,317 2,373
Saskatchewan 890 775
Manitoba 11 11
--------------------------------------------------------------------------------
North Sea
United Kingdom 356 287
--------------------------------------------------------------------------------
Offshore West Africa
Cote d'Ivoire 95 55
Gabon 152 151
--------------------------------------------------------------------------------
Total 15,384 12,653
================================================================================
I. DEVELOPED ACREAGE
The following table summarizes the Company's working interest holdings in core
region developed acreage as at December 31, 2007:
(thousands) Gross Acres Net Acres
--------------------------------------------------------------------------------
North America
Alberta 6,081 4,805
British Columbia 1,357 1,024
Saskatchewan 812 590
Manitoba 5 5
--------------------------------------------------------------------------------
North Sea
United Kingdom 122 88
--------------------------------------------------------------------------------
Offshore West Africa
Cote d'Ivoire 7 4
--------------------------------------------------------------------------------
Total 8,384 6,516
================================================================================
CANADIAN NATURAL RESOURCES LIMITED 49
SELECTED FINANCIAL INFORMATION
The following table summarizes the consolidated financial statements of the
Company, which follows the full cost method of accounting for crude oil and
natural gas operations:
Year Ended Dec 31
($ millions, except per share information) 2007 2006
--------------------------------------------------------------------------------
Revenues(1)(net of royalties) $ 11,152 $ 10,398
Cash flow from operations $ 6,198 $ 4,932
Per common share - basic $ 11.49 $ 9.18
- diluted $ 11.49 $ 9.18
Net earnings $ 2,608 $ 2,524
Per common share - basic $ 4.84 $ 4.70
- diluted $ 4.84 $ 4.70
Total assets $ 36,114 $ 33,160
Total long-term debt $ 10,940 $ 11,043
================================================================================
2007 Three Months Ended
($ millions, except per share
information) Mar 31 Jun 30 Sep 30 Dec 31
-------------------------------------------------------------------------------
Revenues (net of royalties) $ 2,742 $ 2,821 $ 2,732 $ 2,857
Net earnings $ 269 $ 841 $ 700 $ 798
Per common share - basic and diluted $ 0.50 $ 1.56 $ 1.30 $ 1.48
================================================================================
2006 Three Months Ended
($ millions, except per share
information) Mar 31 Jun 30 Sep 30 Dec 31
--------------------------------------------------------------------------------
Revenues (1) (net of royalties) $ 2,352 $ 2,739 $ 2,798 $ 2,509
Net (loss) earnings $ 57 $ 1,038 $ 1,116 $ 313
Per common share - basic and diluted $ 0.11 $ 1.93 $ 2.08 $ 0.58
--------------------------------------------------------------------------------
(1) BLENDING COSTS PREVIOUSLY NETTED AGAINST GROSS REVENUES IN PRIOR YEARS HAVE
BEEN RECLASSIFIED TO TRANSPORTATION AND BLENDING EXPENSE TO CONFORM TO THE
PRESENTATION ADOPTED IN 2006.
50 CANADIAN NATURAL RESOURCES LIMITED
CAPITAL STRUCTURE
COMMON SHARES
The Company is authorized to issue an unlimited number of common shares, without
nominal or par value. Holders of common shares are entitled to one vote per
share at a meeting of shareholders of Canadian Natural, to receive such
dividends as declared by the Board of Directors on the common shares and to
receive pro-rata the remaining property and assets of the Company upon its
dissolution or winding-up, subject to any rights having priority over the common
shares.
PREFERRED SHARES
The Company has no preferred shares outstanding; however, the Company is
authorized to issue two hundred thousand (200,000) preferred shares designated
as Class 1 Preferred Shares. Holders of preferred shares shall not be entitled
as such to receive notice of or to attend any meeting of the shareholders of the
Company and shall not be entitled to vote at any such meeting except under
certain circumstances as described in the Articles of Amalgamation. Holders of
preferred shares are entitled to receive such dividends as and when declared by
the Board of Directors in priority to common shares and shall be entitled to
receive pro-rata in priority to holders of commons shares the remaining property
and assets of Canadian Natural upon its dissolution or winding-up. The Company
may redeem or purchase for cancellation at any time all or any part of the then
outstanding preferred shares and the holders of the preferred shares shall have
the right at any time and from time to time to convert such preferred shares
into the common shares of the Company.
CREDIT RATINGS
Credit ratings accorded to the Company's debt securities are not recommendations
to purchase, hold or sell the debt securities inasmuch as such ratings do not
comment as to market price or suitability for a particular investor. Any rating
may not remain in effect for any given period of time or may be revised or
withdrawn entirely by a rating agency in the future if in its judgment
circumstances so warrant, and if any such rating is so revised or withdrawn, we
are under no obligation to update this Annual Information Form.
The Company is rated "Baa2" with a stable outlook by Moody's Investors Service
("Moody's"), "BBB" with a stable outlook by Standard & Poor's ("S&P") and "BBB
(high)" with a negative trend by DBRS Limited ("DBRS").
Moody's credit ratings are on a long-term debt rating scale that ranges from Aaa
to C, which represents the range from highest to lowest quality of such
securities rated. According to the Moody's rating system, debt securities rated
Baa are considered as medium-grade obligations, i.e., they are neither highly
protected nor poorly secured. Interest payments and principal security appear
adequate for the present, but certain protective elements may be lacking or may
be characteristically unreliable over any great length of time. Such securities
lack outstanding investment characteristics and in fact have speculative
characteristics as well. Moody's applies numerical modifiers 1, 2 and 3 in each
generic rating classification from Aa through Caa in its corporate bond rating
system. The modifier 1 indicates that the issue ranks in the higher end of its
generic rating category, the modifier 2 indicates a mid-range ranking and the
modifier 3 indicates that the issue ranks in the lower end of its generic rating
category. A Moody's rating outlook is an opinion regarding the likely direction
of a rating over the medium term.
S&P's credit ratings are on a long-term debt rating scale that ranges from AAA
to D, which represents the range from highest to lowest quality of such
securities rated. According to the S&P rating system, debt securities rated BBB
exhibit adequate protection parameters. However, adverse economic conditions or
changing circumstances are more likely to lead to a weakened capacity of the
obligor to meet its financial commitments on the debt securities. The ratings
from AA to B may be modified by the addition of a plus (+) or minus (-) sign to
show relative standing within the major rating categories. An S&P rating outlook
assesses the potential direction of a long term credit rating over the
intermediate to longer term. In determining a rating outlook, consideration is
given to any changes in the economic and/or fundamental business conditions.
DBRS' credit ratings are on a long-term debt rating scale that ranges from AAA
to D, which represents the range from highest to lowest quality of such
securities rated. According to the DBRS rating system, debt securities rated BBB
are of adequate credit quality. Protection of interest and principal is
considered acceptable, but the entity is fairly susceptible to adverse changes
in financial and economic conditions. The assignment of a "(high)" or "(low)"
modifier within each rating category indicates relative standing within such
category. The rating trend is DBRS' opinion regarding the outlook for the
rating.
CANADIAN NATURAL RESOURCES LIMITED 51
MARKET FOR CANADIAN NATURAL RESOURCES LIMITED SECURITIES
The Company's common shares are listed and posted for trading on Toronto Stock
Exchange ("TSX") and the New York Stock Exchange ("NYSE") under the symbol CNQ.
2007 Monthly Historical Trading on Toronto Stock Exchange
Month High Low Close Volume Traded
--------------------------------------------------------------------------------
January $ 62.60 $ 52.45 $ 58.84 47,395,230
February $ 61.19 $ 57.62 $ 58.73 34,356,234
March $ 65.50 $ 57.01 $ 63.75 35,412,762
April $ 68.54 $ 63.71 $ 66.14 24,726,552
May $ 72.31 $ 65.48 $ 71.09 30,970,877
June $ 74.99 $ 67.01 $ 70.78 38,391,312
July $ 77.80 $ 70.04 $ 73.21 29,655,617
August $ 73.52 $ 65.43 $ 72.19 37,051,383
September $ 80.02 $ 71.25 $ 75.56 34,242,541
October $ 78.98 $ 71.05 $ 78.56 44,953,346
November $ 79.91 $ 64.50 $ 64.92 46,778,688
December $ 73.72 $ 64.24 $ 72.58 25,099,487
================================================================================
On January 20, 2005, the Company announced its intention to make a Normal Course
Issuer Bid through the facilities of TSX and the NYSE, commencing January 24,
2005 and ending January 23, 2006, to purchase for cancellation up to 13,409,006
(26,818,012 post May 20, 2005 two-for-one stock split) common shares of the
Company, being 5% of the 268,180,123 (536,360,246 post May 20, 2005 two-for-one
stock split) common shares of the Company outstanding on January 12, 2005. Under
this program, the Company purchased a total of 850,000 common shares for
cancellation at a weighted average purchase price of $53.26 for each common
share purchased, $53.29 after costs.
At the Annual and Special Meeting of Shareholders held May 5, 2005, the
shareholders passed a special resolution amending the Articles of the Company to
divide the issued and outstanding Common Shares on a two-for-one basis. The
subdivision of the Common Shares occurred on May 20, 2005.
On January 20, 2006, the Company announced its intention to make a Normal Course
Issuer Bid through the facilities of TSX and the NYSE, commencing January 24,
2006 and ending January 23, 2007, to purchase for cancellation up to 26,852,545
common shares of the Company, being 5% of the 537,050,902 common shares of the
Company outstanding on January 17, 2006. Under this program, the Company
purchased a total of 485,000 common shares for cancellation at a weighted
average purchase price of $57.29 for each common share purchased, $57.33 after
costs.
On January 22, 2007, the Company announced its intention to make a Normal Course
Issuer Bid through the facilities of TSX and the NYSE, commencing January 24,
2007 and ending January 23, 2008, to purchase for cancellation up to 26,941,730
common shares of the Company, being 5% of the 538,834,606 common shares of the
Company outstanding on January 15, 2007. No shares were purchased under the
program. The Company has decided not to renew the Normal Course Issuer Bid until
subsequent to the completion of Phase 1 of the Horizon Project.
52 CANADIAN NATURAL RESOURCES LIMITED
DIVIDEND HISTORY
The dividend policy of the Company undergoes a periodic review by the Board of
Directors and is subject to change at any time depending upon the earnings of
the Company, its financial requirements and other factors existing at the time.
Prior to 2001, dividends had not been paid on the common shares of the Company.
On January 17, 2001 the Board of Directors approved a dividend policy for the
payment of regular quarterly dividends. Dividends have been paid on the first
day of January, April, July and October of each year since 2001.
The following table, restated for the two-for-one subdivision of the common
shares which occurred in May 2005, shows the aggregate amount of the cash
dividends declared per common share of the Company and accrued in each of its
last three years ended December 31.
2007 2006 2005
--------------------------------------------------------------------------------
Cash dividends declared per
common share $ 0.34 $ 0.30 $ 0.24
================================================================================
In February 2008 the Board of Directors approved an 18% increase in the 2008
quarterly dividend from $0.085 per common share to $0.10 per common share,
effective with the April 1, 2008 payment.
TRANSFER AGENTS AND REGISTRAR
The Company's transfer agent and registrar for its common shares is
Computershare Trust Company of Canada in the cities of Calgary and Toronto and
Computershare Shareholder Services, Inc. in the city of New York. The registers
for transfers of the Company's common shares are maintained by Computershare
Trust Company of Canada.
CANADIAN NATURAL RESOURCES LIMITED 53
DIRECTORS AND OFFICERS
The names, municipalities of residence, offices held with the Company and
principal occupations of the directors and officers of the Company are set forth
below:
NAME POSITION PRESENTLY HELD PRINCIPAL OCCUPATION DURING PAST 5 YEARS
-------------------------------------------------------------------------------------------------------------------------------
Catherine M. Best Director (2)(4) Executive Vice-President, Risk Management and Chief Financial Officer
Calgary, Alberta (age 54) of the Calgary Health Region, a fully integrated publicly funded
Canada health care system, from 2002 to present; Vice-President, Corporate
Services and Chief Financial Officer of the Calgary Health Region from
February 2000 to 2002; prior thereto with Ernst & Young since 1980,
most recently as a Corporate Audit Partner from 1991 to 2000. Has
served continuously as a director of the Company since November 2003.
Currently serving on the board of directors of Enbridge Income Fund
and Superior Plus Income Fund.
N. Murray Edwards Vice-Chairman and President, Edco Financial Holdings Ltd. (a private management and
Calgary/Banff, Alberta Director(3) consulting company). Has served continuously as a director of the
Canada (age 48) Company since September 1988. Currently serving on the board of
directors of Ensign Energy Services Inc. and Magellan Aerospace
Corporation.
Honourable Gary A. Filmon Director (1)(2) Consultant, The Exchange Group (business consulting firm based in
Winnipeg, Manitoba (age 65) Winnipeg, Manitoba). Prior thereto, served as Premier of Manitoba
Canada from 1988 to 1999. Has served continuously as a director of the
Company since February 2006. Currently serving on the board of
directors of MTS Allstream Inc., Pollard Banknote Income Fund, Arctic
Glacier Income Trust, Exchange Industrial Income Fund, Wellington
West Capital Inc. and FWS Construction Inc.
Ambassador Gordon D. Giffin Director (1)(2) Senior Partner, McKenna Long & Aldridge LLP (law firm) since May
Atlanta, Georgia (age 58) 2001; prior thereto United States Ambassador to Canada. Has served
USA continuously as a director of the Company since May 2002. Currently
serving on the board of directors of Abitibi Bowater Inc.; Canadian
National Railway Company; Canadian Imperial Bank of Commerce, Ontario
Energy Savings Corp. and, Transalta Corporation.
John G. Langille Vice-Chairman and Officer of the Company. Has served continuously as a director of the
Calgary, Alberta Director Company since June 1982.
Canada (age 62)
Steve W. Laut President and Chief President and Chief Operating Officer of the Company since April
Calgary, Alberta Operating Officer and 2005. Prior thereto Executive Vice-President, Operations 2001 to 2003
Canada Director and most recently Chief Operating Officer 2003 to 2005. Has served
(age 50) continuously as a director of the Company since August 2006.
Keith A.J. MacPhail Director (3)(5) Chairman, President and Chief Executive Officer, Bonavista Energy
Calgary, Alberta (age 51) Trust since November 1997 and Chairman, NuVista Energy Ltd since July
Canada 2003. Has served continuously as a director of the Company since
October 1993. Currently serving on the board of directors of Bonavista
Energy Trust and NuVista Energy Ltd.
Allan P. Markin Chairman and Director(5) Chairman of the Company. Has served continuously as a director of the
Calgary, Alberta (age 62) Company since January 1989.
Canada
54 CANADIAN NATURAL RESOURCES LIMITED
NAME POSITION PRESENTLY HELD PRINCIPAL OCCUPATION DURING PAST 5 YEARS
-------------------------------------------------------------------------------------------------------------------------------
Norman F. McIntyre Director (3)(4)(5) An independent businessman. Prior thereto Executive Vice-President,
Calgary, Alberta (age 62) Petro-Canada from 1995 to 2002 and most recently President,
Canada Petro-Canada 2002 to 2004. Has served continuously as a director of
the Company since July 2005. Currently serving on the board of
directors of Petro Andina Resources Inc.
Frank J. McKenna Director (1)(4) Deputy Chair, TD Bank Financial Group. Prior thereto Premier of New
Cap Pele, New Brunswick (age 60) Brunswick from 1987 to 1997; Counsel to Atlantic Canada law firm
Canada McInnes Cooper from 1998 to 2005, and most recently Canadian
Ambassador to the United States from 2005 to 2006. He has served
continuously as a director of the Company since August 2006. Currently
serving on the board of directors of Brookfield Asset Management Inc.
James S. Palmer, C.M., Director (3)(4)(5) Chairman and a Partner of Burnet, Duckworth & Palmer LLP (law firm).
A. O. E., Q.C. (age 79) Has served continuously as a director of the Company since May 1997.
Calgary, Alberta Currently serving on the board of directors of Magellan Aerospace
Canada Corporation.
Dr. Eldon R. Smith, OC, M.D. Director (4)(5) President of Eldon R. Smith & Associates Ltd., and he is Emeritus
Calgary, Alberta (age 68) Professor and Former Dean, Faculty of Medicine, University of
Canada Calgary. Has served continuously as a director of the Company since
May 1997. Currently serving on the board of directors of Vasogen
Inc., Sernova Corp.; Aston Hill Financial; and Ventripoint
Diagnostics Inc.
David A. Tuer Director (1)(2)(3) Chairman, Calgary Health Region since October 2001 and Executive
Calgary, Alberta (age 58) Vice-Chairman BA Energy Inc. from April 2005 to February 2008. Prior
Canada thereto President and Chief Executive Officer, PanCanadian Energy
Corporation from December 1994 to October 2001, President and CEO of
Hawker Resources Inc. (independent oil and natural gas company) from
January 2003 to March 2005 and most recently President, Value Creation
Inc. from April 2005 to February 2006. Has served continuously as a
director of the Company since May 2002. Currently serving on the board
of directors of Daylight Resources Trust; Xtreme Coil Drilling Corp.;
Canadian Phoenix Resources and, Altalink Management LLP., a private
limited partnership.
Real M. Cusson Senior Vice-President, Officer of the Company.
Calgary, Alberta Marketing
Canada (age 57)
Real J. H. Doucet Senior Vice-President, Officer of the Company.
Calgary, Alberta Oil Sands
Canada (age 55)
Allen M. Knight Senior Vice-President, Officer of the Company.
Calgary, Alberta International &
Canada Corporate Development
(age 58)
Tim S. McKay Senior Vice-President, Officer of the Company.
Calgary, Alberta Operations
Canada (age 46)
Douglas A. Proll Chief Financial Officer Officer of the Company.
Calgary, Alberta and Senior
Canada Vice-President, Finance
(age 57)
CANADIAN NATURAL RESOURCES LIMITED 55
NAME POSITION PRESENTLY HELD PRINCIPAL OCCUPATION DURING PAST 5 YEARS
-------------------------------------------------------------------------------------------------------------------------------
Lyle G. Stevens Senior Vice-President, Officer of the Company.
Calgary, Alberta Exploitation
Canada (age 53)
Jeffrey W. Wilson Senior Vice-President, Officer of the Company since September 2003; prior thereto
Calgary, Alberta Exploration Exploration Manager of the Company.
Canada (age 55)
Jeffrey J. Bergeson Vice-President, Officer of the Company since May 2007; prior thereto Exploitation
Calgary, Alberta Exploitation West Manager of the Company until May 2007.
Canada (age 51)
Corey B. Bieber Vice-President, Finance Officer of the Company since April 2005; prior thereto Treasurer of
Calgary, Alberta and Investor Relations the Company March 2001 to July 2002; Director, Investor Relations of
Canada (age 44) Canada the Company from July 2002 to April 2005 and most recently
Vice-President, Investor Relations April 2005 to February 2007.
Mary-Jo E. Case Vice-President, Officer of the Company.
Calgary, Alberta Land
Canada (age 49)
William R. Clapperton Vice-President, Officer of the Company.
Calgary, Alberta Regulatory, Stakeholder
Canada and Environmental
Affairs
(age 45)
James F. Corson Vice-President, Officer of the Company since January 2007; prior thereto
Calgary, Alberta Human Resources, Vice-President, Human Resources of Qatar Petroleum Corp. from March
Canada Horizon 1997 to July 2005 and most recently Director Human Resources and
(age 57) Stakeholder Relations of the Company from July 2005 to 2007.
Randall S. Davis Vice-President, Officer of the Company since July 2004; prior thereto Manager,
Calgary, Alberta Finance and Accounting Financial Reporting of the Company to July 2002; Financial Controller
Canada (age 41) of the Company from July 2002 to July 2004 and most recently
Vice-President Financial Accounting and Controls July 2004 to February
2007.
Allan E. Frankiw Vice-President, Officer of the Company since March 2007; prior thereto Manager
Calgary, Alberta Production, Central Midstream for Anadarko Canada Corporation from November 1998 to March
Canada (age 51) 2005, Manager Facilities & Construction for Anadarko Canada
Corporation from April 2005 to November 2006, and most recently
Manager Production of the Company from November 2006 to March 2007.
Jerome W. Harvey Vice-President, Officer of the Company since April 2004; prior thereto Manager,
Calgary, Alberta Commercial Operations Commercial Operations.
Canada (age 54)
Peter J. Janson Vice-President, Officer of the Company since December 2004; prior thereto Director,
Calgary, Alberta Engineering Integration Production Planning and Control at Suncor Oil Sands to June 2000,
Canada (age 50) Director, Health and Safety and Environment from June 2000 to
November 2002 at Suncor Oil Sands and most recently Director,
Engineering Integration of the Company from November 2002 to December
2004.
56 CANADIAN NATURAL RESOURCES LIMITED
NAME POSITION PRESENTLY HELD PRINCIPAL OCCUPATION DURING PAST 5 YEARS
-------------------------------------------------------------------------------------------------------------------------------
Philip A. Keele Vice-President, Officer of the Company since December 2004; prior thereto Mine Manager
Calgary, Alberta Mining, at Fording Coal Limited to February 2001, Chief Mine Engineer of the
Canada Project Horizon Company February 2001 to September 2002 and most recently Director,
Oil Sands Mine Engineering of the Company from September 2002 to December 2004.
(age 48)
Cameron S. Kramer Vice-President, Officer of the Company.
Calgary, Alberta Development Operations
Canada (age 40)
Leon Miura Vice-President, Officer of the Company since August 2003; prior thereto held
Calgary, Alberta Upgrading progressively senior positions at Petroleos de Venezuela including
(age 53) Canada Cerro Negro Execution Manager, Heavy Oil Upgrading from 1997 to
2001 and most recently Nitrogen Injection Project Director, Secondary
Recovery at Petroleos de Venezuela 2002 to 2003.
S. John Parr Vice-President, Officer of the Company since April 2004; prior thereto Production
Calgary, Alberta Production, East Engineer, NE Gas of the Company to July 2001, Manager, Production
Canada (age 46) Engineering of the Company from July 2001 to June 2002 and most
recently Production Manager, Heavy Oil of the Company from July 2002
to April 2004.
David A. Payne Vice-President, Officer of the Company since October 2004; prior thereto Exploitation
Calgary, Alberta Exploitation, Central Manager, Thermal Heavy of the Company to July 2000, Director,
Canada (age 46) Exploitation of CNR International (U.K.) Limited a wholly-owned
subsidiary of the Company from July 2000 to August 2003, Exploitation
Manager, Technical Projects of the Company from August 2003 to October
2004, Vice-President, Exploitation, West from October 2004 to April
2007, and most recently Vice-President, Exploitation, East from May
2007 to February 2008.
William R. Peterson Vice-President, Officer of the Company since April 2004; prior thereto Production
Calgary, Alberta Production, West Manager, West of the Company.
Canada (age 41)
John C. Puckering Vice President, Officer of the Company since April 2004; prior thereto General
Calgary, Alberta Site Development Manager DCL Construction Inc. to November 2001, President of 960925
Canada (age 61) Alberta Ltd. from November 2001 to April 2002, Manager, Site
Development of the Company from May 2002 to December 2002 and most
recently General Manager Site Development of the Company from January
2003 to April 2004.
Timothy G. Reed Vice-President, Officer of the Company since January 2007; prior thereto Manager,
Calgary, Alberta Human Resources Human Resources of the Company 2000 to 2005 and most recently Director
Canada (age 51) Human Resources 2005 to January 2007.
Joy P. Romero Vice President, Officer of the Company since March 2008; prior thereto Manager,
Calgary, Alberta Bitumen Production Bitumen Production Process of the Company January 2001 to September
Canada (age 51) 2002 and most recently Director, Bitumen Production Process of the
Company from September 2002 to March 2008.
Sheldon L. Schroeder Vice-President, Officer of the Company since April 2004; prior thereto engineer with
Fort McMurray, Alberta Project Control 729248 Alberta Ltd. to June 2001, Project Control Manager of the
Canada (age 40) Company from June 2001 to September 2002 and most recently Director,
Project Control of the Company from September 2002 to April 2004.
CANADIAN NATURAL RESOURCES LIMITED 57
NAME POSITION PRESENTLY HELD PRINCIPAL OCCUPATION DURING PAST 5 YEARS
-------------------------------------------------------------------------------------------------------------------------------
Kendall W. Stagg Vice-President, Officer of the Company since October 2004; prior thereto Cardium
Calgary, Alberta Exploration, West Geophysicist of the Company to April 2001, Chief Geophysicist of the
Canada (age 46) Company from April 2001 to June 2002 and most recently Manager
Exploration, B. C. of the Company from June 2002 to September 2004.
Scott G. Stauth Vice-President, Officer of the Company since November 2006; prior thereto Operations
Calgary, Alberta Field Operations Superintendent of the Company April 1997 to April 2003 and most
Canada (age 50) recently Manager, Eastern Field Operations of the Company April 2003
to November 2006.
Stephen C. Suche Vice-President, Officer of the Company since July 2006; prior thereto Manager
Calgary, Alberta Information and Information and Corporate Services of the Company January 2000 to
Canada Corporate Services July 2006.
(age 48)
Domenic Torriero Vice-President, Officer of the Company since November 2006; prior thereto
Calgary, Alberta Exploration, Central Vice-President Geology and Geophysics of Petrovera Resources Limited
Canada (age 43) January 1999 to March 2004 and most recently Exploration Manager of
the Company March 2004 to November 2006.
Grant M. Williams Vice-President, Officer of the Company since March 2007; prior thereto Chief
Calgary, Alberta Exploration, East Geophysicist of the Company October 1999 to October 2003 and most
Canada (age 50) recently Manager, Exploration Heavy Oil of the Company October 2003 to
April 2007.
Daryl G. Youck Vice-President, Officer of the Company since February 2008; prior thereto Manager,
Calgary, Alberta Exploitation, East Exploitation of the Company July 2002 to February 2008.
Canada (age 39)
Lynn M. Zeidler Vice-President, Officer of the Company since August 2003; prior thereto held
Calgary, Alberta Utilities and Offsites progressively senior positions at Shell Canada Limited including on
Canada and Horizon Construc- secondment from Shell Canada Limited as Manager-Tier 1 Implementation
tion Management at Sable Offshore Energy Inc to September 2000 and most recently
(age 51) General Project Manager, Athabasca Oil Sands Project at Shell Canada
Limited October 2000 to May 2003 and concurrently as Vice President &
Project Director, Muskeg River Mine at Albian Sands Energy Inc. May
2002 to July 2003 and General Manager Claims Athabasca Oil Sands
Project at Shell Canada Limited May 2003 to July 2003.
Bruce E. McGrath Corporate Secretary Officer of the Company.
Calgary, Alberta (age 58)
Canada
------------------------------------------------------------------------------------------------------------------------------
(1) MEMBER OF THE NOMINATING AND CORPORATE GOVERNANCE COMMITTEE
(2) MEMBER OF THE AUDIT COMMITTEE
(3) MEMBER OF THE RESERVES COMMITTEE
(4) MEMBER OF THE COMPENSATION COMMITTEE
(5) MEMBER OF THE HEALTH, SAFETY, AND ENVIRONMENTAL COMMITTEE
All directors stand for election at each Annual General Meeting of Canadian
Natural shareholders. All of the current directors were elected to the Board at
the last annual general and special meeting of shareholders held on May 3,
2007. All of the current directors are standing for election at the Annual
General Meeting of Shareholders scheduled for May 8, 2008.
As at December 31, 2007, the directors and officers of the Company, as a group,
beneficially owned or controlled or directed, directly or indirectly, in the
aggregate, approximately 4% of the total outstanding common shares
(approximately 5% after the exercise of options held by them pursuant to the
Company's stock option plan).
58 CANADIAN NATURAL RESOURCES LIMITED
CONFLICTS OF INTEREST
There are potential conflicts of interest to which the directors and officers
of the Company may become subject in connection with the operations of the
Company. Some of the directors and officers have been and will continue to be
engaged in the identification and evaluation of businesses and assets with a
view to potential acquisition of interests on their own behalf and on behalf of
other corporations, and situations may arise where the directors and officers
will be in direct competition with the Company. Conflicts, if any, will be
subject to the procedures and remedies under the BUSINESS CORPORATIONS ACT
(Alberta).
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
No director, executive officer or principal shareholder of Canadian Natural, or
associate or affiliate of those persons, has any material interest, direct or
indirect, in any transaction within the last three years that has materially
affected or is reasonably expected to materially affect the Company.
CANADIAN NATURAL RESOURCES LIMITED 59
AUDIT COMMITTEE INFORMATION
AUDIT COMMITTEE MEMBERS
The Audit Committee of the Board of Directors of the Company is comprised of
Ms. C. M. Best, Chair, Messrs. G. A. Filmon, G. D. Giffin and D. A. Tuer each
of whom is independent and financially literate as those terms are defined
under Canadian securities regulations Multilateral Instrument 52-110 and the
NYSE listing standards as they pertain to audit committees of listed issuers.
The education and experience of each member of the Audit Committee relevant to
their responsibilities as an Audit Committee member is described below.
Ms. C. M. Best is a chartered accountant with 20 years experience as a staff
member and partner of an international public accounting firm. During her
tenure she was responsible for direct oversight and supervision of a large
staff of auditors conducting audits of the financial reporting of significant
publicly traded entities, many of which were oil and gas companies. This
oversight and supervision required Ms. C. M. Best to maintain a current
understanding of generally accepted accounting principles, and be able to
assess their application in each of her clients. It also required an
understanding of internal controls and financial reporting processes and
procedures.
Honourable G. A. Filmon holds both a Bachelor of Science degree and a Master of
Science degree in Civil Engineering. He was Premier of the Province of Manitoba
for several years and during that time chaired the Treasury Board for a period
of five years. He was President of Success Commercial College for 11 years and
is currently a business management consultant. Mr. G. A. Filmon is a director
of other public companies and is an active member of other audit committees,
one of which he chairs.
Ambassador G. D. Giffin's education and experience relevant to the performance
of his responsibilities as an audit committee member is derived from a
thirty-year law practice involving complex accounting and audit-related issues
associated with complicated commercial transactions and disputes. He has
developed extensive practical experience and an understanding of internal
controls and procedures for financial reporting from his service on audit
committees for several publicly traded issuers and continues pursuit of
extensive professional reading and study on related subjects.
Mr. D. A. Tuer's education and experience relevant to the performance of his
responsibilities as an audit committee member is derived from professional
training and a business career as a chief executive officer in a large publicly
traded company which provided experience in analyzing and evaluating financial
statements and supervising persons engaged in the preparation, analysis and
evaluation of financial statements of publicly traded companies. He has gained
an understanding of internal controls and procedures for financial reporting
through oversight of those functions, and the understanding of Audit Committee
functions through his years of chief executive involvement.
AUDITOR SERVICE FEES
The Audit Committee of the Board of Directors in 2007 approved specified audit
and non-audit services to be performed by PricewaterhouseCoopers ("PwC"). The
services provided include: (i) the annual audit of the Corporation's internal
controls and December 31, 2007 consolidated financial statements included in
the Annual Information Form and Form 40-F, reviews of the Corporation's
quarterly unaudited Consolidated Financial Statements, audits of certain of the
Corporation's subsidiary companies' annual financial statements as well as
other audit services provided in connection with statutory and regulatory
filings; (ii) audit related services including debt covenant compliance and
Crown Royalty Statements; (iii) tax related services related to expatriate
personal tax and compliance as well as other corporate tax return matters; and
(iv) non-audit services related to accessing resource materials through PwC's
accounting literature library.
Fees accrued to PwC are shown in the table below.
Auditor service 2007 2006
-------------------------------------------------------------------------------
Audit fees $ 2,729,315 $ 3,126,287
Audit related fees 164,000 121,353
Tax related fees 154,459 134,025
All other fees 9,440 9,516
-------------------------------------------------------------------------------
$ 3,057,214 $ 3,391,181
===============================================================================
The Charter of the Audit Committee of the Company is attached as Schedule "C"
to this Annual Information Form.
60 CANADIAN NATURAL RESOURCES LIMITED
LEGAL PROCEEDINGS
From time to time, Canadian Natural is the subject of litigation arising out of
the Company's operations. Damages claimed under such litigation may be material
or may be indeterminate and the outcome of such litigation may materially
impact the Company's financial condition or results of operations. While the
Company assesses the merits of each lawsuit and defends itself accordingly, the
Company may be required to incur significant expenses or devote significant
resources to defend itself against such litigation. The claims that have been
made to date are not currently expected to have a material impact on the
Company's financial position.
MATERIAL CONTRACTS
Other than contracts entered into in the ordinary course of business, the
Company has not entered into any material contracts in the most recently
completed financial year nor has it entered into any material contracts before
the most recently completed financial year and which are still in effect.
INTERESTS OF EXPERTS
The Company's auditors are PricewaterhouseCoopers LLP, Chartered Accountants,
who have prepared an independent auditors' report dated February 26, 2008 in
respect of the Company's consolidated financial statements with accompanying
notes as at and for the three years ended December 31, 2007 and the Company's
internal control over financial reporting as at December 31, 2007.
PricewaterhouseCoopers LLP has advised that they are independent with respect
to the Company within the meaning of the Rules of Professional Conduct of the
Institute of Chartered Accountants of Alberta and the rules of the US
Securities and Exchange Commission.
Based on information provided by the relevant persons or companies, there are
beneficial interests, direct or indirect, in less than 1% of the Company's
securities or property or securities or property of our associates or
affiliates held by Sproule Associates Limited, Ryder Scott Company or GLJ
Petroleum Consultants Ltd. or any partners, employees or consultants of such
independent reserves evaluators who participated in and who were in a position
to directly influence the preparation of the relevant report, or any such
person who, at the time of the preparation of the report was in a position to
directly influence the outcome of the preparation of the report.
ADDITIONAL INFORMATION
Additional information relating to the Company can be found on the SEDAR website
at WWW.SEDAR.COM
Additional information including Directors' and Executive Officers'
remuneration and indebtedness, principal holders of the Company's securities,
options to purchase the Company's securities and interest of insiders in
material transactions is contained in the Company's Notice of Annual General
Meeting and Information Circular dated March 19, 2008 in connection with the
Annual General Meeting of Shareholders of Canadian Natural to be held on May 8,
2008 which information is incorporated herein by reference. Additional
financial information and discussion of the affairs of the Company and the
business environment in which the Company operates is provided in the Company's
Management Discussion and Analysis, comparative Consolidated Financial
Statements and Supplementary Oil & Gas Information for the most recently
completed fiscal year ended December 31, 2007 found on pages 39 to 68, 69 to 96
and 97 to 101 respectively, of the 2007 Annual Report to the Shareholders,
which information is incorporated herein by reference.
For additional copies of this Annual Information Form, please contact:
Corporate Secretary of the Corporation at:
2500, 855 - 2nd Street S.W.
Calgary, Alberta T2P 4J8
CANADIAN NATURAL RESOURCES LIMITED 61
SCHEDULE "A"
AMENDED FORM 51-101F2
REPORT ON RESERVES DATA BY
INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR
REPORT ON RESERVES DATA
To the Board of Directors of Canadian Natural Resources Limited (the
"Corporation"):
1. We have evaluated the Corporation's reserves data as at December 31, 2007.
The reserves data consist of the following:
(a) (i) proved conventional crude oil, natural gas liquids and natural gas
reserve quantities estimated as at December 31, 2007 using constant
prices and costs;
(ii) the related estimated net present value; and
(iii) the related standardized measure calculation for proved
conventional crude oil, natural gas liquids and natural gas reserve
quantities.
(b) (i) both proved, and proved and probable conventional crude oil,
natural gas liquids and natural gas reserve quantities estimated as
at December 31, 2007 using forecast prices and costs; and
(ii) the related estimated net present value.
(c) (i) both proved, and proved and probable bitumen and synthetic crude
oil reserve quantities relating to surface mineable oil sands
projects estimated as at December 31, 2007.
2. The reserves data are the responsibility of the Corporation's management.
Our responsibility is to express an opinion on the reserves data based on
our evaluation.
3. We carried out our evaluation in accordance with standards set out in the
Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") prepared
jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter)
and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum
Society) with the necessary modifications to reflect definitions and
standards under the U.S. Financial Accounting Standards Board policies
(the "FASB Standards") and the legal requirements of the U.S. Securities
and Exchange Commission ("SEC Requirements").
4. Those standards require that we plan and perform an evaluation to obtain
reasonable assurance as to whether the reserves data are free of material
misstatement. An evaluation also includes assessing whether the reserves
data are in accordance with principles and definitions as outlined above.
5. The following table sets forth the estimated net present value of
conventional reserves (before deduction of income taxes) attributed to
proved conventional crude oil, NGL and natural gas reserves quantities,
estimated using constant prices and costs and calculated using a discount
rate of 10 percent, included in the reserves data of the Corporation
evaluated by us for the year ended December 31, 2007 except as noted in
1(c)(i), and identifies the respective portions thereof that we have
evaluated and reported on to the Corporation's management and board of
directors:
62 CANADIAN NATURAL RESOURCES LIMITED
------------------------------------------------------------------------------|-----------------------------------------------
| NET PRESENT VALUES OF CONVENTIONAL RESERVES
|
INDEPENDENT LOCATION OF RESERVES | (BEFORE INCOME TAXES, 10% DISCOUNT RATE)
QUALIFIED RESERVES DESCRIPTION AND PREPARATION DATE COUNTRY OR FOREIGN | ($ MILLIONS)
EVALUATOR OR AUDITOR OF EVALUATION REPORT (GEOGRAPHIC AREA) | AUDITED EVALUATED REVIEWED TOTAL
------------------------------------------------------------------------------|-----------------------------------------------
Sproule Associates Sproule Evaluated the |
Ltd. P&NG Reserves as reported |
February 11th, 2008. Canada, USA | $0 $22,325 $0 $22,325
------------------------------------------------------------------------------|-----------------------------------------------
Ryder Scott Company Ryder Scott Evaluated the |
P&NG Reserves as reported United Kingdom and |
February 11th, 2008. Offshore West Africa | $0 $12,253 $0 $12,253
|
------------------------------------------------------ -----------------------|-----------------------------------------------
TOTALS | $0 $34,578 $0 $34,578
------------------------------------------------------------------------------|-----------------------------------------------
In addition, both proved, and proved and probable reserves have been evaluated
for oil sands mining properties located in Canada. The Horizon Project reserves
were evaluated as at December 31, 2007. GLJ Petroleum Consultants ("GLJ"), an
independent qualified reserves evaluator, was retained by the Reserves
Committee of Canadian Natural's Board of Directors to evaluate reserves
associated with the Horizon Project incorporating both the mining and upgrading
projects. These reserves were evaluated under SEC Industry Guide 7 and are
disclosed separately from the Company's conventional crude oil and natural gas
activities.
6. In our opinion, the reserves data respectively evaluated by us have, in
all material respects, been determined and are in accordance with the COGE
Handbook as modified by the FASB Standards and SEC requirements. We
express no opinion on the reserves data that we reviewed but did not audit
or evaluate.
7. We have no responsibility to update our evaluation for events and
circumstances occurring after their respective preparation dates.
8. Reserves are estimates only, and not exact quantities. In addition, as the
reserves data are based on judgments regarding future events, actual
results will vary and the variations may be material.
CANADIAN NATURAL RESOURCES LIMITED 63
Executed as to our report referred to above:
February 11th, 2008
SPROULE ASSOCIATES LIMITED
CALGARY, ALBERTA, CANADA
ORIGINAL SIGNED BY:
/s/ Harry J. Helwerda
---------------------------
Harry J. Helwerda, P.Eng.,
Executive Vice-President
ORIGINAL SIGNED BY:
/s/ Doug Ho
---------------------------
Doug Ho, P.Eng.
Vice-President, Unconventional
ORIGINAL SIGNED BY:
/s/ R. Keith MacLeod
---------------------------
R. Keith MacLeod, P.Eng.
President
RYDER SCOTT COMPANY
CALGARY, ALBERTA, CANADA
ORIGINAL SIGNED BY:
/s/ Jane L. Tink
---------------------------
Jane L. Tink, P.Eng.,
Vice-President
GLJ PETROLEUM CONSULTANTS
CALGARY, ALBERTA, CANADA
ORIGINAL SIGNED BY:
/s/ James H. Willmon
---------------------------
James H. Willmon, P.Eng.
Vice-President
64 CANADIAN NATURAL RESOURCES LIMITED
SCHEDULE "B"
REPORT OF
MANAGEMENT AND DIRECTORS
ON OIL AND GAS DISCLOSURE
Report of Management and Directors on Reserves Data and Other Information
Management of Canadian Natural Resources Limited (the "Corporation") is
responsible for the preparation and disclosure of information with respect to
the Corporation's conventional crude oil, natural gas and surface mineable oil
sands activities in accordance with securities regulatory requirements. This
information includes reserves data, which consist of the following:
(a) (i) proved conventional crude oil, NGLs and natural gas reserve
quantities estimated as at December 31, 2007 using constant
prices and costs;
(ii) the related estimated net present value; and
(iii) the related standardized measure calculation for proved
conventional crude oil, NGLs and natural gas reserve quantities.
(b) (i) both proved, and proved and probable conventional crude oil, NGLs
and natural gas reserve quantities estimated as at December 31,
2007 using forecast prices and costs;
(ii) the related estimated net present value; and,
(c) (i) both proved, and proved and probable bitumen and synthetic crude
oil reserve quantities relating to surface mineable oil sands
operations estimated as at December 31, 2007.
Sproule Associates Limited, Ryder Scott Company and GLJ Petroleum Consultants,
all independent qualified reserves evaluators have evaluated the Corporation's
reserves data. The report of the independent qualified reserves evaluators will
be filed with securities regulatory authorities concurrently with this report.
The reserves committee (the "Reserves Committee") of the board of directors
(the "Board of Directors") of the Corporation has:
(a) reviewed the Corporation's procedures for providing information to the
independent qualified reserves evaluator;
(b) met with each of the independent qualified reserves evaluators to
determine whether any restrictions placed by management affected the
ability of the independent qualified reserves evaluators to report
without reservation; and
(c) reviewed the reserves data with management and the independent qualified
reserves evaluators.
The Reserves Committee of the Board of Directors has reviewed the Corporation's
procedures for assembling and reporting other information associated with crude
oil and natural gas activities and has reviewed that information with
management. The Board of Directors has, on the recommendation of the Reserves
Committee, approved:
(a) the content and filing with securities regulatory authorities of the
reserves data and other crude oil and natural gas and surface mineable
oil sands information;
(b) the filing of the reports of the independent qualified reserves
evaluators on the reserves data; and
(c) the content and filing of this report.
Reserves data are estimates only, and are not exact quantities. In addition, as
the reserves data are based on judgments regarding future events, actual
results will vary and the variations may be material.
CANADIAN NATURAL RESOURCES LIMITED 65
ORIGINAL SIGNED BY:
Steve W. Laut
President and Chief Operating Officer
ORIGINAL SIGNED BY:
Douglas A. Proll
Chief Financial Officer and Senior Vice President, Finance
ORIGINAL SIGNED BY:
David A. Tuer
Independent Director and Chair of the Reserve Committee
ORIGINAL SIGNED BY:
Norman F. McIntyre
Independent Director and Member of the Reserve Committee
Dated this 26th day of February, 2008
Calgary, Alberta
66 CANADIAN NATURAL RESOURCES LIMITED
SCHEDULE "C"
CANADIAN NATURAL RESOURCES LIMITED
(THE "CORPORATION")
CHARTER OF THE AUDIT COMMITTEE OF THE BOARD OF DIRECTORS
I AUDIT COMMITTEE PURPOSE
The Audit Committee is appointed by the Board of Directors (the "Board") to
assist the Board in fulfilling its responsibility for the stewardship of the
Corporation in overseeing the business and affairs of the Corporation. The Audit
Committee's primary duties and responsibilities are to:
1. ensure that the Corporation's management has designed and implemented an
effective system of internal financial controls;
2. monitor and report on the integrity of the Corporation's financial
statements, financial reporting processes and systems of internal
controls regarding financial, accounting and compliance with regulatory
and statutory requirements as they relate to financial statements,
taxation matters and disclosure of material facts;
3. select and recommend for appointment by the shareholders, the
Corporation's independent auditors, pre-approve all audit and non-audit
services to be provided to the Corporation by the Corporation's
independent auditors consistent with all applicable laws, and establish
the fees and other compensation to be paid to the independent auditors;
4. monitor the independence and performance of the Corporation's independent
auditors;
5. monitor the performance of the internal auditing function;
6. establish procedures for the receipt, retention, response to and
treatment of complaints, including confidential, anonymous submissions by
the Corporation's employees, regarding accounting, internal controls or
auditing matters; and,
7. provide an avenue of communication among the independent auditors,
management, the internal auditing function and the Board.
II AUDIT COMMITTEE COMPOSITION, PROCEDURES AND ORGANIZATION
1. The Audit Committee shall consist of at least three (3) directors as
determined by the Board, each of whom shall be independent, non-executive
directors, free from any relationship that would interfere with the
exercise of his or her independent judgment. Audit Committee members
shall meet the independence and experience requirements of the regulatory
bodies to which the Corporation is subject. All members of the Audit
Committee shall have a basic understanding of finance and accounting and
be able to read and understand fundamental financial statements at the
time of their appointment to the Audit Committee. At least one member of
the Audit Committee shall have accounting or related financial management
expertise and qualify as a "financial expert" or similar designation in
accordance with the requirements of the regulatory bodies to which the
Corporation may be subject to.
2. The Board at its organizational meeting held in conjunction with each
annual general meeting of the shareholders shall appoint the members of
the Audit Committee for the ensuing year. The Board may at any time
remove or replace any member of the Audit Committee and may fill any
vacancy in the Audit Committee.
3. The Board shall appoint a member of the Audit Committee as chair of the
Audit Committee. If an Audit Committee Chair is not designated by the
Board, or is not present at a meeting of the Audit Committee, the members
of the Audit Committee may designate a chair by majority vote of the
Audit Committee membership.
4. The Secretary or the Assistant Secretary of the Corporation shall be
secretary of the Audit Committee unless the Audit Committee appoints a
secretary of the Audit Committee.
5. The quorum for meetings shall be one half (or where one half of the
members of the Audit Committee is not a whole number, the whole number
which is closest to and less than one half) of the members of the Audit
Committee subject to a minimum of two members of the Audit Committee
CANADIAN NATURAL RESOURCES LIMITED 67
present in person or by telephone or other telecommunications device that
permits all persons participating in the meeting to speak and to hear
each other.
6. Meetings of the Audit Committee shall be conducted as follows:
a. the Audit Committee shall meet at least four (4) times annually at
such times and at such locations as may be requested by the Chair of
the Audit Committee;
b. the Audit Committee shall meet privately in executive sessions at
each meeting with management, the manager of internal auditing, the
independent auditors, and as a committee to discuss any matters that
the Audit Committee or each of these groups believe should be
discussed.
7. The independent auditors and internal auditors shall have a direct line
of communication to the Audit Committee through its chair and may bypass
management if deemed necessary. Any employee may bring before the Audit
Committee directly and may bypass management if deemed necessary any
matter involving questionable, illegal or improper financial practices or
transactions.
III AUDIT COMMITTEE DUTIES AND RESPONSIBILITIES
1. The overall duties and responsibilities of the Audit Committee shall be
as follows:
a. to assist the Board in the discharge of its responsibilities
relating to the Corporation's accounting principles, reporting
practices and internal controls and its approval of the
Corporation's annual and quarterly consolidated financial
statements;
b. to establish and maintain a direct line of communication with the
Corporation's internal auditors and independent auditors and assess
their performance;
c. to ensure that the management of the Corporation has designed,
implemented and is maintaining an effective system of internal
controls;
d. to report regularly to the Board on the fulfillment of its duties
and responsibilities; and,
e. to review annually the Audit Committee Charter and recommend any
changes to the Nominating and Corporate Governance Committee for
approval by the Board.
2. The duties and responsibilities of the Audit Committee as they relate to
the independent auditors shall be as follows:
a. to select and recommend to the Board of Directors for appointment by
the shareholders, the Corporation's independent auditors, review the
independence and monitor the performance of the independent auditors
and approve any discharge of auditors when circumstances warrant;
b. to approve the fees and other significant compensation to be paid to
the independent auditors, scope and timing of the audit and other
related services rendered by the independent auditors;
c. to approve the independent auditor's annual audit plan, including
scope, staffing, locations and reliance upon management and internal
audit department prior to the commencement of the audit;
d. to pre-approve all proposed non-audit services to be provided by the
independent auditors except those non-audit services prohibited by
legislation;
e. on an annual basis, obtain and review a report by the independent
auditors describing (i) the independent auditor's internal quality
control procedures; (ii) any material issues raised by the most
recent quality-control review, or peer review, of the firm, or by
any inquiry or investigation by governmental or professional
authorities within the preceding five years respecting one or more
independent audits carried out by the firm; and, (iii) any steps
taken to address any such issues arising from the review, inquiry or
investigation, and , receive a written statement from the
independent auditors outlining all significant relationships they
have with the Corporation that could impair the auditor's
independence. The Corporation's independent auditors may not be
engaged to perform prohibited activities under the Sarbanes-Oxley
Act of 2002 or the rules of the Public Company Accounting Oversight
Board or other regulatory bodies, which the Corporation is governed
by;
68 CANADIAN NATURAL RESOURCES LIMITED
f. to review and discuss with the independent auditors, upon completion
of their audit and prior to the filing or releasing annual financial
statements:
(i) contents of their report, including :
(a) all critical accounting policies and practices used;
(b) all alternative treatments of financial information
within GAAP that have been discussed with management,
ramifications of the use of such treatments and the
treatment preferred by the independent auditor;
(c) other material written communications between the
independent auditor and management;
(ii) scope and quality of the audit work performed;
(iii) adequacy of the Corporation's financial and auditing
personnel;
(iv) cooperation received from the Corporation's personnel during
the audit;
(v) internal resources used;
(vi) significant transactions outside of the normal business of
the Corporation;
(vii) significant proposed adjustments and recommendations for
improving internal accounting controls, accounting principles
or management systems;
(viii) the non-audit services provided by the independent auditors;
and,
(ix) consider the independent auditor's judgments about the
quality and appropriateness of the Corporation's accounting
principles and critical accounting estimates as applied in
its financial reporting; and,
g. to review and approve a report to shareholders as required, to be
included in the Corporation's Information Circular and Proxy
Statement, disclosing any non-audit services approved by the Audit
Committee.
h. to review and approve the Corporation's hiring policies regarding
partners, employees and former partners and employees of the present
and former independent auditor of the Corporation.
3. The duties and responsibilities of the Audit Committee as they relate to
the internal auditors shall be as follows:
a. to review the budget, internal audit function with respect to the
organization structure, staffing, effectiveness and qualifications
of the Corporation's internal audit department;
b. to review and approve the internal audit plan; and
c. to review significant internal audit findings and recommendations
together with management's response and follow-up thereto.
4. The duties and responsibilities of the Audit Committee as they relate to
the internal control procedures of the Corporation shall be as follows:
a. to review the appropriateness and effectiveness of the Corporation's
policies and business practices which impact on the financial
integrity of the Corporation, including those relating to internal
auditing, insurance, accounting, information services and systems
and financial controls, management reporting and risk management;
b. to review any unresolved issues between management and the
independent auditors that could affect the financial reporting or
internal controls of the Corporation; and
c. to periodically review the Corporation's financial and auditing
procedures and the extent to which recommendations made by the
internal audit staff or by the independent auditors have been
implemented.
CANADIAN NATURAL RESOURCES LIMITED 69
5. Other duties and responsibilities of the Audit Committee shall be as
follows:
a. to review the Corporation's unaudited quarterly consolidated
financial statements and related Management Discussion & Analysis
including the impact of unusual items and changes in accounting
principles and estimates, the earnings press releases before
disclosure to the public and report to the Board with respect
thereto;
b. to review the Corporation's audited annual consolidated financial
statements and related Management Discussion & Analysis including
the impact of unusual items and changes in accounting principles and
estimates, the earnings press releases before disclosure to the
public and report to the Board with respect thereto;
c. to ensure adequate procedures are in place for the review of the
Corporation's public disclosure of financial information extracted
or derived from the Corporation's financial statements, other than
the quarterly and annual earnings press releases, and periodically
assess the adequacy of those procedures;
d. to review the appropriateness of the policies and procedures used in
the preparation of the Corporation's consolidated financial
statements and other required disclosure documents and consider
recommendations for any material change to such policies;
e. to review with management, the independent auditors and if necessary
with legal counsel, any litigation, claim or other contingency,
including tax assessments that could have a material affect upon the
financial position or operating results of the Corporation and the
manner in which such matters have been disclosed in the consolidated
financial statements;
f. to establish procedures for:
(i) the receipt, retention and treatment of complaints received
by the Corporation regarding accounting, internal accounting
controls, or auditing matters; and
(ii) the confidential, anonymous submission by employees of the
Corporation of concerns regarding questionable accounting or
auditing matters.
g. to co-ordinate meetings with the Reserves Committee of the
Corporation, the Corporation's senior engineering management,
independent evaluating engineers and auditors as required and
consider such further inquiries as are necessary to approve the
consolidated financial statements;
h. to develop a calendar of activities to be undertaken by the Audit
Committee for each ensuing year and to submit the calendar in the
appropriate format to the Board following each annual general
meeting of shareholders;
i. to perform any other activities consistent with this Charter, the
Corporation's By-laws and governing law, as the Audit Committee or
the Board deems necessary or appropriate; and,
j. to maintain minutes of meetings and to report on a regular basis to
the Board on significant results of the foregoing activities.
The Audit Committee has the authority to conduct any investigation appropriate
to fulfilling its responsibilities, and it has direct access to the independent
auditors as well as officers and employees of the Corporation. The Audit
Committee has the authority to retain, at the Corporation's expense, special
legal, accounting or other consultants or experts it deems necessary in the
performance of its duties. The Corporation shall at all times make adequate
provisions for the payment of all fees and other compensation approved by the
Audit Committee, to the Corporation's independent auditors in connection with
the issuance of its audit report, or to any consultants or experts employed by
the Audit Committee.
70 CANADIAN NATURAL RESOURCES LIMITED
MANAGEMENT'S ASSESSMENT OF INTERNAL CONTROL OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal
control over financial reporting for the Company as defined in Rule 15(d)-15(f)
under the United States Securities Exchange Act of 1934, as amended.
Management, together with the Company's President and Chief Operating Officer
and the Company's Chief Financial Officer and Senior Vice-President, Finance,
performed an assessment of the Company's internal control over financial
reporting based on the criteria established in INTERNAL CONTROL - INTEGRATED
FRAMEWORK issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO).
Based on the assessment, management, together with the Company's President and
Chief Operating Officer and the Company's Chief Financial Officer and Senior
Vice-President, Finance, has concluded that the Company's internal control over
financial reporting is effective as at December 31, 2007. Management recognizes
that all internal control systems have inherent limitations. Because of its
inherent limitations, internal control over financial reporting may not prevent
or detect misstatements. Also, projections of any evaluation of effectiveness
to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.
(signed) Steve W. Laut (signed) Douglas A. Proll
STEVE W. LAUT DOUGLAS A. PROLL, CA
President & Chief Operating Officer Chief Financial Officer &
Senior Vice President, Finance
February 26, 2008
Calgary, Alberta, Canada
[GRAPHIC OMITTED]
[LOGO - PRICEWATERHOUSECOOPERS LLP]
|
| PRICEWATERHOUSECOOPERS LLP
| CHARTERED ACCOUNTANTS
| 111 5 Avenue SW, Suite 3100
| Calgary, Alberta
| Canada T2P 5L3
| Telephone +1 (403) 509 7500
| Facsimile +1 (403) 781 1825
INDEPENDENT AUDITORS' REPORT |
To the Shareholders of Canadian Natural Resources Limited
We have completed integrated audits of the consolidated financial statements
and internal control over financial reporting of Canadian Natural Resources
Limited (the "Company") as at December 31, 2007 and 2006 and an audit of its
2005 consolidated financial statements. Our opinions, based on our audits, are
presented below.
CONSOLIDATED FINANCIAL STATEMENTS
We have audited the accompanying consolidated balance sheets of the Company as
at December 31, 2007 and December 31, 2006, and the related consolidated
statements of earnings, shareholders' equity, comprehensive income and cash
flows for each of the years in the three year period ended December 31, 2007.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits of the Company's financial statements as at December
31, 2007 and for each of the years in the two year period then ended in
accordance with Canadian generally accepted auditing standards and the
standards of the Public Company Accounting Oversight Board (United States). We
conducted our audit of the Company's financial statements for the year ended
December 31, 2005 in accordance with Canadian generally accepted auditing
standards. Those standards require that we plan and perform an audit to obtain
reasonable assurance about whether the financial statements are free of
material misstatement. An audit of financial statements includes examining, on
a test basis, evidence supporting the amounts and disclosures in the financial
statements. A financial statement audit also includes assessing the accounting
principles used and significant estimates made by management, and evaluating
the overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of the Company as at
December 31, 2007 and December 31, 2006 and the results of its operations and
its cash flows for each of the years in the three year period ended December
31, 2007 in accordance with Canadian generally accepted accounting principles.
INTERNAL CONTROL OVER FINANCIAL REPORTING
We have also audited the Company's internal control over financial reporting as
at December 31, 2007, based on criteria established in INTERNAL CONTROL -
INTEGRATED FRAMEWORK issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). The Company's management is responsible for
maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting
included in the accompanying management's assessment of internal control over
financial reporting. Our responsibility is to express an opinion on the
effectiveness of the Company's internal control over financial reporting based
on our audit.
We conducted our audit of internal control over financial reporting in
accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether effective internal control over
financial reporting was maintained in all material respects. An audit of
internal control over financial reporting includes obtaining an understanding
of internal control over financial reporting, assessing the risk that a
material weakness exists, testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk, and performing
such other procedures as we consider necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control
over financial reporting includes those policies and procedures that (i)
pertain to the maintenance of records that, in reasonable detail, accurately
and fairly reflect the transactions and dispositions of the assets of the
company; (ii) provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in accordance with
generally accepted accounting principles, and that receipts and
2
[GRAPHIC OMITTED]
[LOGO - PRICEWATERHOUSECOOPERS LLP]
expenditures of the company are being made only in accordance with
authorizations of management and directors of the company; and (iii) provide
reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the company's assets that could have a
material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting
may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may
become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective
internal control over financial reporting as at December 31, 2007 based on
criteria established in Internal Control -- Integrated Framework issued by the
COSO.
(signed) PricewaterhouseCoopers LLP
Chartered Accountants
Calgary, Alberta, Canada
February 26, 2008
COMMENTS BY AUDITOR FOR U.S. READERS ON CANADA-U.S. REPORTING DIFFERENCES
In the United States, reporting standards for auditors require the addition of
an explanatory paragraph (following the opinion paragraph) when there is a
change in accounting principles that has a material effect on the comparability
of the Company's consolidated financial statements, such as the change
described in Note 2 to the consolidated financial statements. Our report to the
shareholders dated February 26, 2008 is expressed in accordance with Canadian
reporting standards which do not require a reference to such a change in
accounting principles in the Auditors' report when the change is properly
accounted for and adequately disclosed in the consolidated financial
statements.
(signed) PricewaterhouseCoopers LLP
Chartered Accountants
Calgary, Alberta, Canada
February 26, 2008
3
CONSOLIDATED BALANCE SHEETS
As at December 31
(millions of Canadian dollars) 2007 2006
==========================================================================================================
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 21 $ 23
Accounts receivable and other 1,662 1,947
Future income tax (note 8) 480 163
Current portion of other long-term assets (note 3) 18 106
----------------------------------------------------------------------------------------------------------
2,181 2,239
PROPERTY, PLANT AND EQUIPMENT (note 4) 33,902 30,767
OTHER LONG-TERM ASSETS (note 3) 31 154
----------------------------------------------------------------------------------------------------------
$ 36,114 $ 33,160
==========================================================================================================
LIABILITIES
CURRENT LIABILITIES
Accounts payable 379 842
Accrued liabilities 1,567 1,618
Current portion of other long-term liabilities (note 6) 1,617 611
----------------------------------------------------------------------------------------------------------
3,563 3,071
LONG-TERM DEBT (note 5) 10,940 11,043
OTHER LONG-TERM LIABILITIES (note 6) 1,561 1,393
FUTURE INCOME TAX (note 8) 6,729 6,963
----------------------------------------------------------------------------------------------------------
22,793 22,470
----------------------------------------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
SHARE CAPITAL (note 9) 2,674 2,562
RETAINED EARNINGS 10,575 8,141
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (note 10) 72 (13)
----------------------------------------------------------------------------------------------------------
13,321 10,690
----------------------------------------------------------------------------------------------------------
$ 36,114 $ 33,160
==========================================================================================================
COMMITMENTS AND CONTINGENCIES (NOTE 13)
Approved by the Board of Directors:
(signed) Catherine M. Best (signed) N. Murray Edwards
CATHERINE M. BEST N. MURRAY EDWARDS
Chair of the Audit Committee Vice-Chairman of the Board
and Director of Directors and Director
4
CONSOLIDATED STATEMENTS OF EARNINGS
For the years ended December 31
(millions of Canadian dollars, except per common share amounts) 2007 2006 2005
================================================================================================================================
REVENUE $ 12,543 $ 11,643 $ 11,130
Less: royalties (1,391) (1,245) (1,366)
--------------------------------------------------------------------------------------------------------------------------------
REVENUE, NET OF ROYALTIES 11,152 10,398 9,764
--------------------------------------------------------------------------------------------------------------------------------
EXPENSES
Production 2,184 1,949 1,663
Transportation and blending 1,570 1,443 1,293
Depletion, depreciation and amortization 2,863 2,391 2,013
Asset retirement obligation accretion (note 6) 70 68 69
Administration 208 180 151
Stock-based compensation (note 6) 193 139 723
Interest, net 276 140 149
Risk management activities (note 12) 1,562 312 1,952
Foreign exchange (gain) loss (471) 122 (132)
--------------------------------------------------------------------------------------------------------------------------------
8,455 6,744 7,881
--------------------------------------------------------------------------------------------------------------------------------
EARNINGS BEFORE TAXES 2,697 3,654 1,883
Taxes other than income tax (note 8) 165 256 194
Current income tax expense (note 8) 380 222 286
Future income tax (recovery) expense (note 8) (456) 652 353
--------------------------------------------------------------------------------------------------------------------------------
NET EARNINGS $ 2,608 $ 2,524 $ 1,050
================================================================================================================================
NET EARNINGS PER COMMON SHARE (note 11)
Basic $ 4.84 $ 4.70 $ 1.96
Diluted $ 4.84 $ 4.70 $ 1.95
================================================================================================================================
5
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
For the years ended December 31
(millions of Canadian dollars) 2007 2006 2005
===============================================================================================================================
SHARE CAPITAL
Balance - beginning of year $ 2,562 $ 2,442 $ 2,408
Issued upon exercise of stock options 21 21 9
Previously recognized liability on stock options exercised for common shares 91 101 29
Purchase of common shares under Normal Course Issuer Bid - (2) (4)
-------------------------------------------------------------------------------------------------------------------------------
Balance - end of year 2,674 2,562 2,442
-------------------------------------------------------------------------------------------------------------------------------
RETAINED EARNINGS
Balance - beginning of year, as originally reported 8,141 5,804 4,922
Transition adjustment on adoption of financial instruments standards (note 2) 10 - -
-------------------------------------------------------------------------------------------------------------------------------
Balance - beginning of year, as restated 8,151 5,804 4,922
Net earnings 2,608 2,524 1,050
Dividends on common shares (note 9) (184) (161) (127)
Purchase of common shares under Normal Course Issuer Bid - (26) (41)
-------------------------------------------------------------------------------------------------------------------------------
Balance - end of year 10,575 8,141 5,804
-------------------------------------------------------------------------------------------------------------------------------
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (note 2)
Balance - beginning of year (13) (9) (6)
Transition adjustment on adoption of financial instruments standards 159 - -
-------------------------------------------------------------------------------------------------------------------------------
Balance - beginning of year, after effect of transition adjustment 146 (9) (6)
Other comprehensive loss, net of taxes (74) (4) (3)
-------------------------------------------------------------------------------------------------------------------------------
Balance - end of year 72 (13) (9)
-------------------------------------------------------------------------------------------------------------------------------
SHAREHOLDERS' EQUITY $ 13,321 $ 10,690 $ 8,237
===============================================================================================================================
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the years ended December 31
(millions of Canadian dollars) 2007 2006 2005
===============================================================================================================================
NET EARNINGS $ 2,608 $ 2,524 $ 1,050
-------------------------------------------------------------------------------------------------------------------------------
NET CHANGE IN DERIVATIVE FINANCIAL INSTRUMENTS DESIGNATED AS CASH FLOW
HEDGES
Unrealized income during the year, net of taxes of $6 million
(2006 - $nil, 2005 - $nil) 38 - -
Reclassification to net earnings, net of taxes of $45 million
(2006 - $nil, 2005 - $nil) (96) - -
-------------------------------------------------------------------------------------------------------------------------------
(58) - -
-------------------------------------------------------------------------------------------------------------------------------
FOREIGN CURRENCY TRANSLATION ADJUSTMENT
Translation of net investment (16) (4) (12)
Hedge of net investment, net of taxes - - 9
-------------------------------------------------------------------------------------------------------------------------------
(16) (4) (3)
-------------------------------------------------------------------------------------------------------------------------------
OTHER COMPREHENSIVE LOSS, NET OF TAXES (74) (4) (3)
-------------------------------------------------------------------------------------------------------------------------------
COMPREHENSIVE INCOME $ 2,534 $ 2,520 $ 1,047
===============================================================================================================================
6
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the years ended December 31
(millions of Canadian dollars) 2007 2006 2005
=================================================================================================================================
OPERATING ACTIVITIES
Net earnings $ 2,608 $ 2,524 $ 1,050
Non-cash items
Depletion, depreciation and amortization 2,863 2,391 2,013
Asset retirement obligation accretion 70 68 69
Stock-based compensation 193 139 723
Unrealized risk management loss (gain) 1,400 (1,013) 925
Unrealized foreign exchange (gain) loss (524) 134 (103)
Deferred petroleum revenue tax expense (recovery) 44 37 (9)
Future income tax (recovery) expense (456) 652 353
Deferred charges and other 38 (2) (31)
Abandonment expenditures (71) (75) (46)
Net change in non-cash working capital (note 14) (346) (679) (147)
---------------------------------------------------------------------------------------------------------------------------------
5,819 4,176 4,797
---------------------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
(Repayment) issue of bank credit facilities, net (1,925) 6,499 (435)
Issue of medium-term notes 273 400 400
Repayment of senior unsecured notes (33) - (194)
Issue of US dollar debt securities 2,553 788 -
Repayment of preferred securities - - (107)
Issue of common shares on exercise of stock options 21 21 9
Dividends on common shares (178) (153) (121)
Purchase of common shares - (28) (45)
Net change in non-cash working capital (note 14) 8 37 19
---------------------------------------------------------------------------------------------------------------------------------
719 7,564 (474)
---------------------------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Expenditures on property, plant and equipment (6,464) (7,266) (5,340)
Net proceeds on sale of property, plant and equipment 110 71 454
---------------------------------------------------------------------------------------------------------------------------------
Net expenditures on property, plant and equipment (6,354) (7,195) (4,886)
Acquisition of Anadarko Canada Corporation (note 15) - (4,641) -
Net proceeds on sale of other assets - - 11
Net change in non-cash working capital (note 14) (186) 101 542
---------------------------------------------------------------------------------------------------------------------------------
(6,540) (11,735) (4,333)
---------------------------------------------------------------------------------------------------------------------------------
(DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS (2) 5 (10)
CASH AND CASH EQUIVALENTS - BEGINNING OF YEAR 23 18 28
---------------------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS - END OF YEAR $ 21 $ 23 $ 18
=================================================================================================================================
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (NOTE 14)
7
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(TABULAR AMOUNTS IN MILLIONS OF CANADIAN DOLLARS, UNLESS OTHERWISE STATED)
1. ACCOUNTING POLICIES
Canadian Natural Resources Limited (the "Company") is a senior independent
crude oil and natural gas exploration, development and production company
head-quartered in Calgary, Alberta, Canada. The Company's conventional crude
oil and natural gas operations are focused in North America, largely in Western
Canada; the United Kingdom ("UK") portion of the North Sea; and Cote d'Ivoire
and Gabon, Offshore West Africa.
Within Western Canada, the Company is developing its Horizon Oil Sands Project
(the "Horizon Project") in a series of staged development phases. Each
development phase ("Phase") is planned to result in incremental production
capacity. The Horizon Project is designed to produce synthetic crude oil
through bitumen mining and upgrading operations.
Also within Western Canada, the Company maintains certain midstream activities
that include pipeline operations and an electricity co-generation system.
The consolidated financial statements of the Company have been prepared in
accordance with accounting principles generally accepted in Canada ("Canadian
GAAP"). A summary of differences between accounting principles in Canada and
those generally accepted in the United States ("US GAAP") is contained in note
17.
Significant accounting policies are summarized as follows:
(A) PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the Company and
all of its subsidiary companies and partnerships. A significant portion of the
Company's activities are conducted jointly with others and the consolidated
financial statements reflect only the Company's proportionate interest in such
activities.
(B) MEASUREMENT UNCERTAINTY
Management has made estimates and assumptions regarding certain assets,
liabilities, revenues and expenses in the preparation of the consolidated
financial statements. Such estimates primarily relate to unsettled transactions
and events as of the date of the consolidated financial statements.
Accordingly, actual results may differ from estimated amounts.
Purchase price allocations, depletion, depreciation and amortization, and
amounts used for impairment calculations are based on estimates of crude oil
and natural gas reserves and commodity prices, production expenses and capital
costs required to develop and produce those reserves. All of the Company's
reserve estimates are evaluated annually by independent engineering firms. The
imprecise nature of reserves estimates makes it likely that the reserve base
and the related future cash flows will be revised over time as additional data
becomes available. As a result, reserve estimates are subject to measurement
uncertainty and the impact of differences between actual and estimated amounts
on the consolidated financial statements of future periods could be material.
The calculation of asset retirement obligations includes estimates of the
future costs to settle the asset retirement obligation, the timing of the cash
flows to settle the obligation, and the future inflation rates. The impact of
differences between actual and estimated costs, timing and inflation on the
consolidated financial statements of future periods could be material.
The calculation of income taxes requires judgment in applying tax laws and
regulations, estimating the timing of temporary difference reversals, and
estimating the realizability of future tax assets. These estimates impact
current and future income tax assets and liabilities, and expenses
(recoveries).
The measurement of petroleum revenue tax expense in the United Kingdom and the
related provision in the consolidated financial statements are subject to
uncertainty associated with future recoverability of crude oil and natural gas
reserves, commodity prices and the timing of future events, which could result
in material changes to deferred amounts.
(C) CASH AND CASH EQUIVALENTS
Cash comprises cash on hand and demand deposits. Other investments (term
deposits and certificates of deposit) with an original term to maturity at
purchase of three months or less are reported as cash equivalents on the
balance sheet.
8
(D) PROPERTY, PLANT AND EQUIPMENT
CONVENTIONAL CRUDE OIL AND NATURAL GAS
The Company follows the full cost method of accounting for its conventional
crude oil and natural gas properties and equipment as prescribed by Accounting
Guideline 16 ("AcG 16") by the Canadian Institute of Chartered Accountants
("CICA"). Accordingly, all costs relating to the exploration for and
development of crude oil and natural gas reserves are capitalized and
accumulated in country-by-country cost centres. Administrative overhead
incurred during the development of certain large capital projects is
capitalized until the projects are available for their intended use. Proceeds
on disposal of properties are ordinarily deducted from such costs without
recognition of a gain or loss except where such dispositions result in a change
in the depletion rate of the specific cost centre of 20% or more.
OIL SANDS MINING OPERATIONS AND UPGRADING OPERATIONS
The Company's Horizon Project constitutes mining operations and upgrading
operations and accordingly, capitalized costs related to the Horizon Project
are accounted for separately from the Company's Canadian conventional crude oil
and natural gas costs. Capitalized costs for mining activities include property
acquisition, construction and development costs. Construction and development
costs are capitalized separately to each Phase of the Horizon Project.
Construction and development for a particular Phase of the Horizon Project is
considered complete once the Phase is ready for its intended use. Costs related
to major maintenance turnaround activities will be deferred and amortized on a
straight-line basis over the period to the next scheduled major maintenance
turnaround.
MIDSTREAM AND OTHER
The Company capitalizes all costs that expand the capacity or extend the useful
life of the assets.
(E) OVERBURDEN REMOVAL COSTS
Overburden removal costs incurred during development of the Horizon Project
mine are capitalized to property, plant and equipment. Overburden removal costs
incurred during production of the Horizon Project mine will be included in the
cost of inventory produced, unless the overburden removal activity has resulted
in a betterment of the mineral property, in which case the costs will be
capitalized to property, plant and equipment. Capitalized overburden removal
costs will be amortized over the life of the mining reserves that directly
benefited from the overburden removal activity.
(F) CAPITALIZED INTEREST
The Company capitalizes construction period interest based on the Horizon
Project costs incurred and the Company's cost of borrowing. Interest
capitalization on a particular Phase ceases once construction is substantially
complete and this Phase of the Horizon Project is available for its intended
use. The Company continues to capitalize a portion of interest costs related to
subsequent on-going Phases of the Horizon Project.
(G) LEASES
Contractual arrangements that meet the definition of a lease are accounted for
as capital leases or operating leases as appropriate. Leases that transfer
substantially all of the benefits and risks of ownership to the Company are
accounted for as capital leases and are recorded as property, plant and
equipment with an offsetting liability. All other leases are accounted for as
operating leases and lease costs are expensed as incurred.
(H) DEPLETION, DEPRECIATION AND AMORTIZATION
CONVENTIONAL CRUDE OIL AND NATURAL GAS
Substantially all costs related to each country-by-country cost centre are
depleted on the unit-of-production method based on the estimated proved
reserves of that country. Volumes of net production and net reserves before
royalties are converted to equivalent units on the basis of estimated relative
energy content. In determining its depletion base, the Company includes
estimated future costs to be incurred in developing proved reserves and
excludes the cost of unproved properties and major development projects.
Unproved properties are assessed periodically to determine whether impairment
has occurred. When proved reserves are assigned or the value of unproved
property is considered to be impaired, the cost of the unproved property or the
amount of the impairment is added to costs subject to depletion. Costs for
major development projects, as identified by management, are not subject to
depletion until the projects are available for their intended uses. Processing
and production facilities are depreciated on a straight-line basis over their
estimated lives.
The Company reviews the carrying amount of its conventional crude oil and
natural gas properties ("the properties") relative to their recoverable amount
("the ceiling test") for each cost centre at each annual balance sheet date, or
more frequently if circumstances or events indicate impairment may have
occurred. The recoverable amount is calculated as the undiscounted cash flow
from the properties using proved reserves and expected future prices and costs.
If the carrying amount of the properties exceeds their recoverable amount, an
impairment loss is recognized in depletion expense equal to the amount by which
the carrying amount of the properties exceeds their fair value. Fair value is
calculated as the cash flow from those properties using proved and probable
reserves and expected future prices and costs, discounted at a risk-free
interest rate.
9
OIL SANDS MINING OPERATIONS AND UPGRADING OPERATIONS
Upon commencement of operations for the Horizon Project, mine-related costs and
costs of the upgrader located on the Horizon Project site will be amortized on
the unit-of-production method based on the estimated proved and probable
reserves of the Horizon Project or the productive capacity, as appropriate.
Moveable mine-related equipment is depreciated on a straight-line basis over
its estimated useful life.
The Company reviews the carrying amount of the Horizon Project relative to its
recoverable amount if circumstances or events indicate impairment may have
occurred. The recoverable amount is calculated as the undiscounted cash flow
from the Horizon Project assets using proved and probable reserves and expected
future prices and costs. If the carrying amount exceeds the recoverable amount,
an impairment loss is recognized in depletion equal to the amount by which the
carrying amount of the assets exceeds fair value. Fair value is calculated as
the cash flow from the Horizon Project using proved and probable reserves and
expected future prices and costs, discounted at a risk-free interest rate.
MIDSTREAM AND OTHER
Midstream assets are depreciated on a straight-line basis over their estimated
lives. The Company reviews the recoverability of the carrying amount of the
midstream assets when events or circumstances indicate that the carrying amount
might not be recoverable. If the carrying amount of the midstream assets
exceeds their recoverable amount, an impairment loss equal to the amount by
which the carrying amount of the midstream assets exceeds their fair value is
recognized in depreciation.
Other capital assets are amortized on a declining balance basis.
(I) ASSET RETIREMENT OBLIGATIONS
The Company provides for future asset retirement obligations on its resource
properties, facilities, production platforms, gathering systems, and oil sands
mining operations and tailings ponds based on current legislation and industry
operating practices. The fair values of asset retirement obligations related to
property, plant and equipment are recognized as a liability in the period in
which they are incurred. Retirement costs equal to the fair value of the asset
retirement obligations are capitalized as part of the cost of the associated
property, plant and equipment and are amortized to expense through depletion
and depreciation over the lives of the respective assets. The fair value of an
asset retirement obligation is estimated by discounting the expected future
cash flows to settle the asset retirement obligation at the Company's average
credit-adjusted risk-free interest rate. In subsequent periods, the asset
retirement obligation is adjusted for the passage of time and for changes in
the amount or timing of the underlying future cash flows. Actual expenditures
are charged against the accumulated asset retirement obligation as incurred.
The Company's Horizon Project upgrader and related infrastructure and its
midstream pipelines have an indeterminate life and therefore the fair values of
the related asset retirement obligations cannot be reasonably determined. The
asset retirement obligations for these assets will be recorded in the year in
which the lives of the assets are determinable.
(J) FOREIGN CURRENCY TRANSLATION
Foreign operations that are self-sustaining are translated using the current
rate method. Under this method, assets and liabilities are translated to
Canadian dollars from their functional currency using the exchange rate in
effect at the consolidated balance sheet date. Revenues and expenses are
translated to Canadian dollars at the monthly average exchange rates. Gains or
losses on translation are included in accumulated other comprehensive income
(loss) in shareholders' equity in the consolidated balance sheets.
Foreign operations that are integrated are translated using the temporal
method. For foreign currency balances and integrated subsidiaries, monetary
assets and liabilities are translated to Canadian dollars at the exchange rate
in effect at the consolidated balance sheet date. Non-monetary assets and
liabilities are translated at the exchange rate in effect when the assets were
acquired or obligations incurred. Revenues and expenses are translated to
Canadian dollars at the monthly average exchange rates. Provisions for
depletion, depreciation and amortization are translated at the same rate as the
related assets. Gains or losses on translation of integrated foreign operations
and foreign currency balances are included in the consolidated statement of
earnings.
10
(K) REVENUE RECOGNITION
Revenue from the production of crude oil and natural gas is recognized when
title passes to the customer, delivery has taken place and collection is
reasonably assured. The Company assesses customer creditworthiness, both before
entering into contracts and throughout the revenue recognition process.
Revenue as reported represents the Company's share and is presented before
royalty payments to governments and other mineral interest owners. Revenue, net
of royalties represents the Company's share after royalty payments to
governments and other mineral interest owners.
(L) TRANSPORTATION AND BLENDING
Transportation and blending costs incurred to transport crude oil and natural
gas to customers are recorded as a separate cost in the consolidated statement
of earnings.
(M) PRODUCTION SHARING CONTRACTS
Production generated from Offshore West Africa is currently shared under the
terms of various Production Sharing Contracts ("PSCs"). Revenues are divided
into cost recovery oil and profit oil. Cost recovery oil allows the Company to
recover its capital and production costs and the costs carried by the Company
on behalf of the Government State Oil Company. Profit oil is allocated to the
joint venture partners in accordance with their respective equity interests,
after a portion has been allocated to the Government. The Government's share of
profit oil attributable to the Company's equity interest is allocated to
royalty expense and current income tax expense in accordance with the terms of
the PSCs.
(N) PETROLEUM REVENUE TAX
The Company accounts for the UK petroleum revenue tax ("PRT") by the
life-of-the-field method. The total future liability or recovery of PRT is
estimated using proved and probable reserves and anticipated future sales
prices and costs. The estimated future PRT is then apportioned to accounting
periods on the basis of total estimated future operating income. Changes in the
estimated total future PRT are accounted for prospectively.
(O) INCOME TAX
The Company follows the liability method of accounting for income taxes. Under
this method, future income tax assets and liabilities are recognized based on
the estimated tax effects of temporary differences in the carrying value of
assets and liabilities in the consolidated financial statements and their
respective tax bases, using income tax rates substantively enacted as of the
consolidated balance sheet date. The effect of a change in income tax rates on
the future income tax assets and liabilities is recognized in net earnings in
the period of the change.
Taxable income from the conventional crude oil and natural gas business in
Canada is primarily generated through partnerships, with the related income
taxes payable in a future period. Accordingly, North America current income
taxes have been provided on the basis of the corporate structure and available
income tax deductions and will vary depending upon the nature, timing and
amount of capital expenditures incurred in Canada in any particular year.
(P) STOCK-BASED COMPENSATION PLANS
The Company accounts for stock-based compensation using the intrinsic value
method as the Company's Stock Option Plan (the "Option Plan") provides current
employees with the right to elect to receive common shares or a direct cash
payment in exchange for options surrendered. A liability for potential cash
settlements under the Option Plan is accrued over the vesting period of the
stock options based on the difference between the exercise price of the stock
options and the market price of the Company's common shares and an estimated
forfeiture rate. This liability is revalued at each reporting date to reflect
changes in the market price of the Company's common shares and actual
forfeitures, with the net change recognized in net earnings, or capitalized
during the construction period in the case of the Horizon Project. When stock
options are surrendered for cash, the cash settlement paid reduces the
outstanding liability. When stock options are exercised for common shares under
the Option Plan, consideration paid by employees and any previously recognized
liability associated with the stock options are recorded as share capital.
The Company has an employee stock savings plan and a stock bonus plan.
Contributions to the employee stock savings plan are recorded as compensation
expense at the time of the contribution. Contributions to the stock bonus plan
are recognized as compensation expense over the related vesting period.
11
(Q) FINANCIAL INSTRUMENTS
The Company classifies its financial instruments into one of the following
categories as defined by the CICA Handbook: held-for-trading financial assets
and financial liabilities, held-to-maturity investments, loans and receivables,
available-for-sale financial assets, and other financial liabilities. All
financial instruments are required to be measured at fair value on initial
recognition. Measurement in subsequent periods is dependent on the
classification of the financial instrument.
Held-for-trading financial instruments are subsequently measured at fair value
with changes in fair value recognized in net earnings. Available-for-sale
financial assets are subsequently measured at fair value with changes in fair
value recognized in other comprehensive income, net of tax. All other
categories of financial instruments are measured at amortized cost using the
effective interest method.
Cash and cash equivalents are classified as held-for-trading and are measured
at fair value. Accounts receivable are classified as loans and receivables.
Accounts payable, accrued liabilities and long-term debt are classified as
other financial liabilities. Although the Company does not intend to trade its
derivative financial instruments, risk management assets and liabilities are
classified as held-for-trading for accounting purposes unless designated as
hedges.
Transaction costs that are directly attributable to the acquisition or issue of
a financial asset or financial liability and original issue discounts on
long-term debt have been included in the carrying value of the related
financial asset or liability and are amortized to consolidated net earnings
over the life of the financial instrument using the effective interest method.
(R) RISK MANAGEMENT ACTIVITIES
The Company utilizes various derivative financial instruments to manage its
commodity price, currency and interest rate exposures. These derivative
financial instruments are not intended for trading or speculative purposes.
Effective January 1, 2007, all derivative financial instruments are recognized
at estimated fair value on the consolidated balance sheet at each balance sheet
date. The estimated fair value of derivative instruments has been determined
based on appropriate internal valuation methodologies and/or third party
indications. However, these estimates may not necessarily be indicative of the
amounts that could be realized or settled in a current market transaction and
these differences may be material.
The Company formally documents all derivative financial instruments that are
designated as hedging transactions at the inception of the hedging
relationship, in accordance with the Company's risk management policies. The
effectiveness of the hedging relationship is evaluated, both at inception of
the hedge and on an ongoing basis.
The Company periodically enters into commodity price contracts to manage
anticipated sales of crude oil and natural gas production in order to protect
cash flow for capital expenditure programs. The effective portion of changes in
the fair value of derivative commodity price contracts designated as cash flow
hedges is initially recognized in other comprehensive income and is
reclassified to risk management activities in consolidated net earnings in the
same period or periods in which the crude oil or natural gas is sold. The
ineffective portion of changes in the fair value of these designated contracts
is immediately recognized in risk management activities in consolidated net
earnings. All changes in the fair value of non-designated crude oil and natural
gas commodity price contracts are recognized in risk management activities in
consolidated net earnings.
The Company enters into interest rate swap contracts to manage its fixed to
floating interest rate mix on certain of its long-term debt. The interest rate
swap contracts require the periodic exchange of payments without the exchange
of the notional principal amounts on which the payments are based. Changes in
the fair value of interest rate swap contracts designated as fair value hedges
and corresponding changes in the fair value of the hedged long-term debt are
included in interest expense in consolidated net earnings. Changes in the fair
value of non-designated interest rate swap contracts are included in risk
management activities in consolidated net earnings.
Cross currency swap contracts are periodically used to manage currency exposure
on US dollar denominated long-term debt. The cross currency swap contracts
require the periodic exchange of payments with the exchange at maturity of
notional principal amounts on which the payments are based. Changes in the fair
value of the foreign exchange component of cross currency swap contracts
designated as cash flow hedges are included in foreign exchange in consolidated
net earnings. The effective portion of changes in the fair value of the
interest rate component of cross currency swap contracts designated as cash
flow hedges is initially included in other comprehensive income and is
reclassified to interest expense when realized, with the ineffective portion
recognized in risk management activities in consolidated net earnings. Changes
in the fair value of non-designated cross currency swap contracts are included
in risk management activities in consolidated net earnings.
12
Gains or losses on the termination of financial instruments that have been
designated as cash flow hedges are deferred under accumulated other
comprehensive income on the consolidated balance sheets and amortized into
consolidated net earnings in the period in which the underlying hedged item is
recognized. In the event a designated hedged item is sold, extinguished or
matures prior to the termination of the related derivative instrument, any
unrealized derivative gain or loss is recognized immediately in consolidated
net earnings. Gains or losses on the termination of financial instruments that
have not been designated as hedges are recognized in consolidated net earnings
immediately.
Embedded derivatives are derivatives that are included in a non-derivative host
contract. Embedded derivatives are recorded at fair value separately from the
host contract when their economic characteristics and risks are not clearly and
closely related to the host contract.
(S) COMPREHENSIVE INCOME
Comprehensive income is comprised of the Company's net earnings and other
comprehensive income. Other comprehensive income includes the effective portion
of changes in the fair value of derivative financial instruments designated as
cash flow hedges and foreign currency translation gains and losses on the net
investment in self-sustaining foreign operations. Other comprehensive income is
shown net of related income taxes.
(T) PER COMMON SHARE AMOUNTS
The Company uses the treasury stock method to determine the dilutive effect of
stock options and other dilutive instruments. This method assumes that proceeds
received from the exercise of in-the-money stock options not accounted for as a
liability are used to purchase common shares at the average market price during
the year. The Company's Option Plan described in note 9 results in a liability
and expense for all outstanding stock options. As such, the potential common
shares associated with the stock options are not included in diluted earnings
per share. The dilutive effect of other convertible securities is calculated by
applying the "if-converted" method, which assumes that the securities are
converted at the beginning of the period and that income items are adjusted to
net earnings.
(U) RECENTLY ISSUED ACCOUNTING STANDARDS UNDER CANADIAN GAAP
Effective January 1, 2008, the Company will adopt the following three new
accounting standards issued by the CICA:
CAPITAL DISCLOSURES
o Section 1535 - "Capital Disclosures" requires entities to disclose their
objectives, policies and processes for managing capital, as well as
quantitative data about capital. The section also requires the disclosure
of any externally-imposed capital requirements and compliance with those
requirements. The section does not define capital. The section affects
disclosures only and will not impact the Company's accounting for
capital.
INVENTORIES
o Section 3031 - "Inventories" replaces Section 3030 - "Inventories" and
establishes new standards for the measurement of cost of inventories and
expands disclosure requirements for inventories. Adoption of this
standard is not anticipated to have a material impact on the Company's
financial statements.
FINANCIAL INSTRUMENTS
o Section 3862 - "Financial Instruments - Disclosure" and Section 3863
"Financial Instruments - Presentation" replace Section 3861 - "Financial
Instruments - Disclosure and Presentation". Section 3862 enhances
disclosure requirements concerning risks and requires disclosures of
quantitative and qualitative disclosures about exposures to risks arising
from financial instruments. Section 3863 carries forward the presentation
requirements from Section 3861 unchanged. These standards affect
disclosures only and will not impact the Company's accounting for
financial instruments.
In addition, the following standard was issued during 2008 and will be
effective for the Company's year beginning on January 1, 2009, with earlier
adoption permitted:
GOODWILL AND INTANGIBLE ASSETS
o Section 3064 - "Goodwill and Intangible Assets" replaces Section 3062 -
"Goodwill and Other Intangible Assets" and Section 3450 - "Research and
Development Costs". In addition, EIC-27 - "Revenue and Expenditures
during the Pre-Operating Period" has been withdrawn. The new standard
addresses when an internally generated intangible asset meets the
definition of an asset. Adoption of the new standard may impact the
Company's capitalization of certain costs during the development and
start-up of large development projects.
(V) COMPARATIVE FIGURES
Certain prior year figures have been reclassified to conform to the
presentation adopted in 2007.
13
2. CHANGE IN ACCOUNTING POLICY
Effective January 1, 2007, the Company adopted the following new accounting
standards issued by the CICA relating to the accounting for and disclosure of
financial instruments and comprehensive income:
o Section 1530 - "Comprehensive Income" introduces the concept of
comprehensive income to Canadian GAAP. Comprehensive income is the change
in equity (net assets) of the Company during a reporting period from
transactions and other events and circumstances from non-owner sources.
It includes all changes in equity during a period except transactions
with owners. The foreign currency translation adjustment, which was
previously a separate component of shareholders' equity, is now recorded
as part of accumulated other comprehensive income.
o Section 3251 - "Equity" replaces Section 3250 - "Surplus" and establishes
standards for the presentation of equity and changes in equity during a
reporting period.
o Section 3855 - "Financial Instruments - Recognition and Measurement"
prescribes when a financial asset, financial liability, or non-financial
derivative should be recognized on the balance sheet as well as its
measurement amount.
o Section 3865 - "Hedges" replaces Accounting Guideline 13 - "Hedging
Relationships" and EIC 128 - "Accounting for Trading, Speculative or
Non-Hedging Derivative Financial Instruments" and specifies how hedge
accounting is to be applied and what disclosures are necessary when hedge
accounting is applied.
Adoption of these standards required the Company to record all of its
derivative financial instruments on the balance sheet at estimated fair value
as at January 1, 2007, including those designated as hedges. Designated hedges,
other than cross currency swaps, were previously not recognized on the balance
sheet but were disclosed in the notes to the financial statements. The
adjustment to recognize all designated hedges on the balance sheet was recorded
as an adjustment to the opening balance of retained earnings or accumulated
other comprehensive income, as appropriate.
With the exception of the foreign currency translation adjustment, these
standards were adopted prospectively; accordingly, comparative amounts for
prior periods have not been restated. The reclassification of the foreign
currency translation adjustment to other comprehensive income was applied
retroactively with prior period restatement.
The effects of adopting these standards on the opening balance sheet were as
follows:
JANUARY 1, 2007
===============================================================================
Increased current portion of other long-term assets (1) $ 193
Decreased other long-term assets (2) $ (16)
Decreased long-term debt (3) $ (72)
Increased retained earnings (4) $ 10
Increased foreign currency translation adjustment (5) $ 13
Increased accumulated other comprehensive income (6) $ 146
Decreased current portion of future income tax asset (7) $ (62)
Increased future income tax liability (7) $ 18
===============================================================================
(1) RELATES TO THE RECOGNITION OF THE CURRENT PORTION OF THE FAIR VALUE OF
DERIVATIVE FINANCIAL INSTRUMENTS DESIGNATED AS CASH FLOW HEDGES.
(2) RELATES TO THE RECOGNITION OF THE LONG-TERM PORTION OF THE FAIR VALUE OF
DERIVATIVE FINANCIAL INSTRUMENTS DESIGNATED AS CASH FLOW AND FAIR VALUE
HEDGES, AS WELL AS THE RECLASSIFICATION OF TRANSACTION COSTS AND ORIGINAL
ISSUE DISCOUNTS FROM DEFERRED CHARGES TO LONG-TERM DEBT.
(3) RELATES TO THE FAIR VALUE IMPACT OF DERIVATIVE FINANCIAL INSTRUMENTS
DESIGNATED AS FAIR VALUE HEDGES, AS WELL AS THE RECLASSIFICATION OF
TRANSACTION COSTS AND ORIGINAL ISSUE DISCOUNTS.
(4) RELATES TO THE IMPACT ON ADOPTION OF THE MEASUREMENT OF INEFFECTIVENESS
ON DERIVATIVE FINANCIAL INSTRUMENTS DESIGNATED AS CASH FLOW HEDGES.
(5) RELATES TO THE RETROACTIVE RESTATEMENT OF FOREIGN CURRENCY TRANSLATION
ADJUSTMENT TO ACCUMULATED OTHER COMPREHENSIVE INCOME.
(6) RELATES TO THE RECOGNITION OF ACCUMULATED OTHER COMPREHENSIVE INCOME
ARISING FROM THE MEASUREMENT OF EFFECTIVENESS ON DERIVATIVE FINANCIAL
INSTRUMENTS DESIGNATED AS CASH FLOW HEDGES.
(7) RELATES TO THE FUTURE INCOME TAX IMPACTS OF THE ABOVE NOTED ADJUSTMENTS.
14
3. OTHER LONG-TERM ASSETS
2007 2006
----------------------------------------------------------------------------------------------------------------------------------
Deferred charges $ 28 $ 109
Risk management (note 12) - 128
Other 21 23
----------------------------------------------------------------------------------------------------------------------------------
49 260
Less: current portion 18 106
----------------------------------------------------------------------------------------------------------------------------------
$ 31 $ 154
----------------------------------------------------------------------------------------------------------------------------------
4. PROPERTY, PLANT AND EQUIPMENT
2007 2006
ACCUMULATED Accumulated
DEPLETION AND depletion and
COST DEPRECIATION NET Cost depreciation Net
==================================================================================================================================
Conventional crude oil
and natural gas
North America $ 34,195 $ 12,162 $ 22,033 $ 31,715 $ 9,836 $ 21,879
North Sea 3,174 1,446 1,728 3,370 1,341 2,029
Offshore West Africa 1,833 645 1,188 1,685 481 1,204
Other 39 14 25 38 14 24
Horizon Project 8,651 - 8,651 5,350 - 5,350
Midstream 269 64 205 263 56 207
Head office 170 98 72 150 76 74
----------------------------------------------------------------------------------------------------------------------------------
$ 48,331 $ 14,429 $ 33,902 $ 42,571 $ 11,804 $ 30,767
==================================================================================================================================
During the year ended December 31, 2007, the Company capitalized administrative
overhead of $47 million (2006 - $41 million, 2005 - $41 million) relating to
exploration and development in the North Sea and Offshore West Africa and $312
million (2006 - $255 million, 2005 - $134 million) relating primarily to the
Horizon Project in North America.
During the year ended December 31, 2007, the Company capitalized $356 million
(2006 - $196 million, 2005 - $72 million) in construction period interest costs
related to the Horizon Project.
Included in property, plant and equipment are unproved land and major
development projects that are not currently subject to depletion or
depreciation:
2007 2006
==================================================================================================================================
Conventional crude oil and natural gas
North America $ 2,259 $ 2,244
North Sea 10 24
Offshore West Africa 138 84
Other 25 24
Horizon Project 8,651 5,350
----------------------------------------------------------------------------------------------------------------------------------
$ 11,083 $ 7,726
==================================================================================================================================
15
The Company has used the following estimated benchmark future prices
("escalated pricing") in its full cost ceiling tests for conventional crude oil
and natural gas activities prepared in accordance with Canadian GAAP, as at
December 31, 2007:
Average
annual
increase
2008 2009 2010 2011 2012 thereafter
================================================================================================================================
CRUDE OIL AND NGLS
North America
WTI at Cushing (US$/bbl) $ 89.61 $ 86.01 $ 84.65 $ 82.77 $ 82.26 2.0%
Hardisty Heavy 12(degree) API (C$/bbl) $ 54.67 $ 52.42 $ 51.56 $ 50.38 $ 50.05 2.0%
Edmonton Par (C$/bbl) $ 88.17 $ 84.54 $ 83.16 $ 81.26 $ 80.73 2.0%
North Sea and Offshore West Africa
North Sea Brent (US$/bbl) $ 87.61 $ 83.97 $ 82.57 $ 80.65 $ 80.10 2.0%
--------------------------------------------------------------------------------------------------------------------------------
NATURAL GAS
North America
Henry Hub Louisiana (US$/mmbtu) $ 7.56 $ 8.27 $ 8.74 $ 8.75 $ 8.66 2.0%
AECO (C$/mmbtu) $ 6.51 $ 7.22 $ 7.69 $ 7.70 $ 7.61 2.3%
Huntingdon/Sumas (C$/mmbtu) $ 6.51 $ 7.22 $ 7.69 $ 7.70 $ 7.61 2.3%
================================================================================================================================
16
5. LONG-TERM DEBT
2007 2006
=================================================================================================================================
CANADIAN DOLLAR DENOMINATED DEBT
Bank credit facilities
Bankers' acceptances $ 4,696 $ 6,621
Medium-term notes
7.40% unsecured debentures repaid March 1, 2007 - 125
5.50% unsecured debentures due December 17, 2010 400 -
4.50% unsecured debentures due January 23, 2013 400 400
4.95% unsecured debentures due June 1, 2015 400 400
---------------------------------------------------------------------------------------------------------------------------------
5,896 7,546
---------------------------------------------------------------------------------------------------------------------------------
US DOLLAR DENOMINATED DEBT
Senior unsecured notes
Adjustable rate due May 27, 2009 (2007 - US$62 million, 2006 - US$93 million) 61 108
US dollar debt securities
7.80% due July 2, 2008 (2007 - US$8 million, 2006 - US$8 million) 8 9
6.70% due July 15, 2011 (2007 - US$400 million, 2006 - US$400 million) 395 466
5.45% due October 1, 2012 (2007 - US$350 million, 2006 - US$350 million) 346 408
4.90% due December 1, 2014 (2007 - US$350 million, 2006 - US$350 million) 346 408
6.00% due August 15, 2016 (2007 - US$250 million, 2006 - US$250 million) 247 291
5.70% due May 15, 2017 (2007 - US$1,100 million, 2006 - US$nil) 1,087 -
7.20% due January 15, 2032 (2007 - US$400 million, 2006 - US$400 million) 395 466
6.45% due June 30, 2033 (2007 - US$350 million, 2006 - US$350 million) 346 408
5.85% due February 1, 2035 (2007 - US$350 million, 2006 - US$350 million) 346 408
6.50% due February 15, 2037 (2007 - US$450 million, 2006 - US$450 million) 445 525
6.25% due March 15, 2038 (2007 - US$1,100 million, 2006 - US$nil) 1,087 -
Less - original issue discount on senior unsecured notes and US dollar debt securities (1) (23) -
---------------------------------------------------------------------------------------------------------------------------------
5,086 3,497
Change in fair value of interest rate swaps on US dollar debt securities (2) 9 -
---------------------------------------------------------------------------------------------------------------------------------
5,095 3,497
---------------------------------------------------------------------------------------------------------------------------------
Long-term debt before transaction costs 10,991 11,043
Less - transaction costs (1) (3) (51) -
---------------------------------------------------------------------------------------------------------------------------------
$ 10,940 $ 11,043
=================================================================================================================================
(1) EFFECTIVE JANUARY 1, 2007, THE COMPANY HAS INCLUDED UNAMORTIZED ORIGINAL
ISSUE DISCOUNTS AND DIRECTLY ATTRIBUTABLE TRANSACTION COSTS IN THE
CARRYING VALUE OF THE OUTSTANDING DEBT.
(2) THE CARRYING VALUES OF US$350 MILLION OF 5.45% NOTES DUE OCTOBER 2012 AND
US$350 MILLION OF 4.90% NOTES DUE DECEMBER 2014 HAVE BEEN ADJUSTED BY $9
MILLION TO REFLECT THE FAIR VALUE IMPACT OF HEDGE ACCOUNTING.
(3) TRANSACTION COSTS PRIMARILY REPRESENT UNDERWRITING COMMISSIONS CHARGED AS
A PERCENTAGE OF THE RELATED DEBT OFFERINGS, AS WELL AS LEGAL, RATING
AGENCY AND OTHER PROFESSIONAL FEES.
BANK CREDIT FACILITIES
As at December 31, 2007, the Company had in place unsecured bank credit
facilities of $6,209 million, comprised of:
o a $100 million demand credit facility;
o a non-revolving syndicated credit facility of $2,350 million maturing
October 2009;
o a revolving syndicated credit facility of $2,230 million maturing June
2012;
o a revolving syndicated credit facility of $1,500 million maturing June
2012; and
o a (pound)15 million demand credit facility related to the Company's North
Sea operations.
17
During 2007, one of the revolving syndicated credit facilities was increased
from $1,825 million to $2,230 million and a $500 million demand credit facility
was terminated. The revolving syndicated credit facilities were also extended
and now mature June 2012. Both facilities are extendible annually for one year
periods at the mutual agreement of the Company and the lenders. If the
facilities are not extended, the full amount of the outstanding principal would
be repayable on the maturity date.
In conjunction with the closing of the acquisition of Anadarko Canada
Corporation ("ACC") in November 2006 (note 15), the Company executed a $3,850
million, non-revolving syndicated credit facility maturing in October 2009. In
March 2007, $1,500 million was repaid, reducing the facility to $2,350 million.
The weighted average interest rate of the bank credit facilities outstanding at
December 31, 2007, was 5.2% (2006 - 4.8%).
In addition to the outstanding debt, letters of credit and financial guarantees
aggregating $345 million, including $300 million related to the Horizon
Project, were outstanding at December 31, 2007.
MEDIUM-TERM NOTES
In December 2007, the Company issued $400 million of unsecured notes maturing
December 2010, bearing interest at 5.50%. Proceeds from the securities issued
were used to repay bankers' acceptances under the Company's bank credit
facilities. After issuing these securities, the Company has $2,600 million
remaining on its outstanding $3,000 million base shelf prospectus filed in
September 2007 that allows for the issue of medium-term notes in Canada until
October 2009. If issued, these securities will bear interest as determined at
the date of issuance.
During 2007, $125 million of the 7.40% unsecured debentures due March 1, 2007
were repaid.
In 2006, the Company issued $400 million of debt securities maturing January
2013, bearing interest at 4.50%. Proceeds from the securities issued were used
to repay bankers' acceptances under the Company's bank credit facilities.
SENIOR UNSECURED NOTES
The adjustable rate senior unsecured notes bear interest at 6.54%, with annual
principal repayments of US$31 million due in May 2008 and May 2009. During
2007, US$31 million of the senior unsecured notes were repaid.
US DOLLAR DEBT SECURITIES
In March 2007, the Company issued US$2,200 million of unsecured notes,
comprised of US$1,100 million of unsecured notes maturing May 2017 and US$1,100
million of unsecured notes maturing March 2038, bearing interest at 5.70% and
6.25%, respectively. Concurrently, the Company entered into cross currency
swaps to fix the Canadian dollar interest and principal repayment amounts on
the entire US$1,100 million of unsecured notes due May 2017 at 5.10% and
C$1,287 million (note 12). The Company also entered into a cross currency swap
to fix the Canadian dollar interest and principal repayment amounts on US$550
million of unsecured notes due March 2038 at 5.76% and C$644 million (note 12).
Proceeds from the securities issued were used to repay bankers' acceptances
under the Company's bank credit facilities.
During 2007, the Company de-designated the portion of the US dollar denominated
debt previously hedged against its net investment in US dollar based
self-sustaining foreign operations. Accordingly, all foreign exchange (gains)
losses arising each period on US dollar denominated long-term debt are now
recognized in the consolidated statement of earnings.
In 2006, the Company issued US$250 million of unsecured notes maturing August
2016 and US$450 million of unsecured notes maturing February 2037, bearing
interest at 6.00% and 6.50%, respectively. Concurrently, the Company entered
into cross currency swaps to fix the Canadian dollar interest and principal
repayment amounts on the US$250 million notes at 5.40% and C$279 million (note
12). Proceeds from the securities issued were used to repay bankers'
acceptances under the Company's bank credit facilities.
In September 2007, the Company filed a base shelf prospectus that allows for
the issue of up to US$3,000 million of debt securities in the United States
until October 2009.
Subsequent to December 31, 2007, the Company issued US$1,200 million of
unsecured notes under this US base shelf prospectus, comprised of US$400
million of 5.15% unsecured notes due February 2013, US$400 million of 5.90%
unsecured notes due February 2018, and US$400 million of 6.75% unsecured notes
due February 2039. Proceeds from the securities issued were used to repay
bankers' acceptances under the Company's bank credit facilities. After issuing
these securities, the Company has US$1,800 million remaining on its outstanding
US$3,000 million base shelf prospectus. If issued, these securities will bear
interest as determined at the date of issuance.
18
REQUIRED DEBT REPAYMENTS
Required debt repayments are as follows:
Year Repayment
==============================================================================================================================
2008 $ 39
2009 $ 2,361
2010 $ 400
2011 $ 395
2012 $ 346
Thereafter $ 5,098
==============================================================================================================================
No debt repayments are reflected for $2,366 million of revolving bank credit
facilities due to the extendable nature of the facilities.
6. OTHER LONG-TERM LIABILITIES
2007 2006
==============================================================================================================================
Asset retirement obligations $ 1,074 $ 1,166
Stock-based compensation 529 744
Risk management (note 12) 1,474 -
Other 101 94
------------------------------------------------------------------------------------------------------------------------------
3,178 2,004
Less: current portion 1,617 611
------------------------------------------------------------------------------------------------------------------------------
$ 1,561 $ 1,393
==============================================================================================================================
ASSET RETIREMENT OBLIGATIONS
At December 31, 2007, the Company's total estimated undiscounted costs to
settle its asset retirement obligations were approximately $4,426 million (2006
- $4,497 million). Payments to settle these asset retirement obligations will
occur on an ongoing basis over a period of approximately 60 years and have been
discounted using a weighted average credit adjusted risk-free interest rate of
6.6% (2006 - 6.7%; 2005 - 6.8%). A reconciliation of the discounted asset
retirement obligations is as follows:
2007 2006 2005
==============================================================================================================================
Asset retirement obligations
Balance - beginning of year $ 1,166 $ 1,112 $ 1,119
Liabilities incurred 21 26 47
Liabilities (disposed) acquired (note 15) (65) 56 -
Liabilities settled (71) (75) (46)
Asset retirement obligation accretion 70 68 69
Revision of estimates 35 (21) (56)
Foreign exchange (82) - (21)
------------------------------------------------------------------------------------------------------------------------------
Balance - end of year $ 1,074 $ 1,166 $ 1,112
==============================================================================================================================
19
STOCK-BASED COMPENSATION
The Company recognizes a liability for the potential cash settlements under its
Option Plan. The current portion represents the maximum amount of the liability
payable within the next twelve month period if all vested options are
surrendered for cash settlement.
2007 2006 2005
================================================================================================================================
Stock-based compensation
Balance - beginning of year $ 744 $ 891 $ 323
Stock-based compensation 193 139 723
Cash payment for options surrendered (375) (264) (227)
Transferred to common shares (91) (101) (29)
Capitalized to Horizon Project 58 79 101
--------------------------------------------------------------------------------------------------------------------------------
Balance - end of year 529 744 891
Less: current portion of stock-based compensation 390 611 629
--------------------------------------------------------------------------------------------------------------------------------
$ 139 $ 133 $ 262
================================================================================================================================
7. EMPLOYEE FUTURE BENEFITS
In connection with the acquisition of ACC, the Company assumed obligations to
provide defined contribution pension benefits to certain ACC employees
continuing their employment with the Company, and defined benefit pension and
other post-retirement benefits to former ACC employees, under registered and
unregistered pension plans.
The estimated future cost of providing defined benefit pension and other
post-retirement benefits to former ACC employees is actuarially determined
using management's best estimates of demographic and financial assumptions. The
discount rate of 5.5% (2006 - 5.0%) used to determine accrued benefit
obligations is based on a year-end market rate of interest for high-quality
debt instruments with cash flows that match the timing and amount of expected
benefit payments. Company contributions to the defined contribution plan are
expensed as incurred.
The benefit obligation under the registered pension plan at December 31, 2007
was $32 million (2006 - $29 million). As required by government regulations,
the Company has set aside funds with an independent trustee to meet these
benefit obligations. As at December 31, 2007, these plan assets had a fair
value of $47 million (2006 - $54 million). The unregistered pension plan and
other post-retirement benefits are unfunded and have a benefit obligation of
$10 million at December 31, 2007 (2006 - $15 million).
8. TAXES
TAXES OTHER THAN INCOME TAX
2007 2006 2005
================================================================================================================================
Current petroleum revenue tax expense $ 97 $ 196 $ 181
Deferred petroleum revenue tax expense (recovery) 44 37 (9)
Provincial capital taxes and surcharges 24 23 22
--------------------------------------------------------------------------------------------------------------------------------
$ 165 $ 256 $ 194
================================================================================================================================
INCOME TAX
The provision for income tax is as follows:
2007 2006 2005
================================================================================================================================
Current income tax - North America $ 96 $ 143 $ 99
Current income tax - North Sea 210 30 155
Current income tax - Offshore West Africa 74 49 32
--------------------------------------------------------------------------------------------------------------------------------
Current income tax expense 380 222 286
Future income tax (recovery) expense (456) 652 353
--------------------------------------------------------------------------------------------------------------------------------
Income tax (recovery) expense $ (76) $ 874 $ 639
--------------------------------------------------------------------------------------------------------------------------------
20
The provision for income tax is different from the amount computed by applying
the combined statutory Canadian federal and provincial income tax rates to
earnings before taxes. The reasons for the difference are as follows:
2007 2006 2005
================================================================================================================================
Canadian statutory income tax rate 32.5% 34.9% 38.0%
--------------------------------------------------------------------------------------------------------------------------------
Income tax provision at statutory rate $ 877 $ 1,275 $ 716
Effect on income taxes of:
Non-deductible portion of Canadian crown payments - 131 309
Canadian resource allowance - (129) (293)
Deductible UK petroleum revenue tax (71) (82) (65)
Foreign tax rate differentials 79 92 (1)
North America income tax rate and other legislative changes (864) (438) (19)
UK income tax rate changes - 110 -
Cote d'Ivoire income tax rate changes - (67) -
Non-taxable portion of foreign exchange (gain) loss (96) 5 (15)
Other (1) (23) 7
--------------------------------------------------------------------------------------------------------------------------------
Income tax (recovery) expense $ (76) $ 874 $ 639
================================================================================================================================
The following table summarizes the temporary differences that give rise to the
net future income tax asset and liability:
2007 2006
================================================================================================================================
Future income tax liabilities
Property, plant and equipment $ 5,695 $ 6,088
Timing of partnership items 1,288 1,394
Unrealized foreign exchange gain on long-term debt 199 93
Unrealized risk management activities - 40
Other 55 13
Future income tax assets
Asset retirement obligations (380) (487)
Loss carryforwards for income tax (104) (85)
Stock-based compensation (125) (232)
Unrealized risk management activities (399) -
Deferred petroleum revenue tax 20 (24)
--------------------------------------------------------------------------------------------------------------------------------
Net future income tax liability 6,249 6,800
Less: current portion future income tax asset (480) (163)
--------------------------------------------------------------------------------------------------------------------------------
Future income tax liability $ 6,729 $ 6,963
================================================================================================================================
During 2007, enacted or substantively enacted income tax rate and other
legislative changes resulted in a reduction of future income tax liabilities of
approximately $864 million in North America. As a result of the enacted income
tax rate changes, the Canadian federal corporate income tax rate will be
reduced over the next five years from 21% in 2007 to 15% in 2012.
During 2006, enacted income tax rate changes resulted in a reduction of future
income tax liabilities of approximately $438 million in North America, an
increase of future income tax liabilities of approximately $110 million in the
UK North Sea and a reduction of future income tax liabilities of approximately
$67 million in Cote d'Ivoire.
During 2005, enacted income tax rate changes resulted in a reduction of future
income tax liabilities of approximately $19 million in North America.
21
During 2003, the Canadian Federal Government enacted legislation to change the
taxation of resource income. The legislation reduced the corporate income tax
rate on resource income from 28% to 21% over five years beginning January 1,
2003. Over the same period, the deduction for resource allowance was phased out
and a deduction for actual crown royalties paid was phased in. As a result, in
2007 crown royalties were fully deductible and the Company is no longer
eligible for the resource allowance.
9. SHARE CAPITAL
AUTHORIZED
200,000 Class 1 preferred shares with a stated value of $10.00 each.
Unlimited number of common shares without par value.
ISSUED
2007 2006
NUMBER OF Number of
SHARES shares
COMMON SHARES (THOUSANDS) AMOUNT (thousands) Amount
==================================================================================================================================
Balance - beginning of year 537,903 $ 2,562 536,348 $ 2,442
Issued upon exercise of stock options 1,826 21 2,040 21
Previously recognized liability on stock options exercised for common
shares - 91 - 101
Purchase of common shares under Normal Course Issuer Bid - - (485) (2)
----------------------------------------------------------------------------------------------------------------------------------
Balance - end of year 539,729 $ 2,674 537,903 $ 2,562
==================================================================================================================================
NORMAL COURSE ISSUER BID
During 2007, the Company did not purchase any common shares for cancellation
pursuant to the Normal Course Issuer Bid previously filed, for the 12-month
period beginning January 24, 2007 and ending on January 23, 2008 (2006 -
485,000 common shares were purchased at an average price of $57.33 per common
share for a total cost of $28 million, 2005 - 850,000 common shares were
purchased at an average price of $53.29 per common share for a total cost of
$45 million). The Company has not renewed the Normal Course Issuer Bid in 2008.
DIVIDEND POLICY
The Company has paid regular quarterly dividends in January, April, July and
October of each year since 2001. The dividend policy undergoes a periodic
review by the Board of Directors and is subject to change.
In February 2008, the Board of Directors set the Company's regular quarterly
dividend at $0.10 per common share (2007 - $0.085 per common share, 2006 -
$0.075 per common share).
STOCK OPTIONS
The Company's Option Plan provides for granting of stock options to employees.
Stock options granted under the Option Plan have terms ranging from five to six
years to expiry and vest equally over a five-year period. The exercise price of
each stock option granted is determined at the closing market price of the
common shares on the Toronto Stock Exchange on the day prior to the grant. Each
stock option granted provides the holder the choice to purchase one common
share of the Company at the stated exercise price or receive a cash payment
equal to the difference between the stated exercise price and the market price
of the Company's common shares on the date of surrender of the option.
22
The following table summarizes information relating to stock options
outstanding at December 31, 2007 and 2006:
----------------------------------------------------------------------------------------------------------------------------------
2007 2006
STOCK OPTIONS WEIGHTED AVERAGE Stock options Weighted average
(thousands) EXERCISE PRICE (thousands) exercise price
----------------------------------------------------------------------------------------------------------------------------------
Outstanding - beginning of year 34,431 $ 33.77 30,510 $ 17.79
Granted 7,502 $ 70.03 13,090 $ 59.61
Surrendered for cash settlement (7,249) $ 16.10 (5,180) $ 12.60
Exercised for common shares (1,826) $ 11.71 (2,040) $ 10.67
Forfeited (2,199) $ 46.46 (1,949) $ 37.51
----------------------------------------------------------------------------------------------------------------------------------
Outstanding - end of year 30,659 $ 47.23 34,431 $ 33.77
----------------------------------------------------------------------------------------------------------------------------------
Exercisable - end of year 7,640 $ 30.00 9,177 $ 14.73
==================================================================================================================================
The range of exercise prices of stock options outstanding and exercisable at
December 31, 2007 were as follows:
----------------------------------------------------------------------------------------------------------------------------------
STOCK OPTIONS OUTSTANDING STOCK OPTIONS EXERCISABLE
----------------------------------------------------------------------------------------------------------------------------------
WEIGHTED
STOCK OPTIONS AVERAGE WEIGHTED STOCK OPTIONS
OUTSTANDING REMAINING TERM AVERAGE EXERCISABLE WEIGHTED AVERAGE
RANGE OF EXERCISE PRICES (thousands) (years) EXERCISE PRICE (thousands) EXERCISE PRICE
----------------------------------------------------------------------------------------------------------------------------------
$9.63 - $9.99 935 0.06 $ 9.63 935 $ 9.63
$10.00 - $19.99 5,510 1.38 $ 15.50 2,886 $ 14.66
$20.00 - $29.99 3,946 2.32 $ 25.47 1,187 $ 25.25
$30.00 - $39.99 1,012 2.72 $ 33.25 278 $ 33.28
$40.00 - $49.99 573 4.06 $ 46.79 133 $ 45.87
$50.00 - $59.99 5,980 3.76 $ 57.99 1,168 $ 57.81
$60.00 - $69.99 5,762 4.16 $ 61.59 1,053 $ 61.75
$70.00 - $73.35 6,941 5.16 $ 70.72 - $ -
----------------------------------------------------------------------------------------------------------------------------------
30,659 3.40 $ 47.23 7,640 $ 30.00
==================================================================================================================================
10. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
The components of accumulated other comprehensive income (loss), net of taxes,
were as follows:
2007 2006
==================================================================================================================================
Derivative financial instruments designated as cash flow hedges $ 101 $ -
Foreign currency translation adjustment (29) (13)
----------------------------------------------------------------------------------------------------------------------------------
$ 72 $ (13)
==================================================================================================================================
During the next 12 months, $22 million is expected to be reclassified to net
earnings from accumulated other comprehensive income.
23
11. NET EARNINGS PER COMMON SHARE
The following table provides a reconciliation between basic and diluted amounts
per common share:
(thousands of shares) 2007 2006 2005
=================================================================================================================================
Weighted average common shares outstanding - basic 539,336 537,339 536,650
Assumed settlement of preferred securities with common shares (1) - - 1,775
---------------------------------------------------------------------------------------------------------------------------------
Weighted average common shares outstanding - diluted 539,336 537,339 538,425
=================================================================================================================================
Net earnings $ 2,608 $ 2,524 $ 1,050
Interest on preferred securities, net of taxes(1) - - 4
Revaluation of preferred securities, net of taxes(1) - - (2)
---------------------------------------------------------------------------------------------------------------------------------
Diluted net earnings $ 2,608 $ 2,524 $ 1,052
=================================================================================================================================
Net earnings per common share
Basic $ 4.84 $ 4.70 $ 1.96
Diluted $ 4.84 $ 4.70 $ 1.95
=================================================================================================================================
(1) THE PREFERRED SECURITIES WERE REDEEMED IN SEPTEMBER 2005.
12. FINANCIAL INSTRUMENTS
RISK MANAGEMENT
The Company uses derivative financial instruments to manage its commodity
price, foreign currency and interest rate exposures. These derivative financial
instruments are entered into solely for hedging purposes and are not intended
for trading or other speculative purposes.
Commencing January 1, 2007, the Company recorded all of its derivative
financial instruments on the balance sheet at fair value, including those
designated as hedges. As at December 31, 2006, the net unrecognized asset
related to the estimated fair values of derivative financial instruments
designated as hedges was $222 million.
The estimated fair values of derivative financial instruments recognized in the
risk management asset (liability) were comprised as follows:
2007 2006
--------------------------------------------------------------------------------------------------------------------------------
RISK Risk
MANAGEMENT management Deferred
ASSET (LIABILITY) MARK-TO-MARKET mark-to-market revenue
================================================================================================================================
Balance - beginning of year $ 128 $ (877) $ (8)
Retained earnings effect of adoption of financial instruments
standards (note 2) 14 - -
Net cost of outstanding put options 58 455 -
Net change in fair value of outstanding derivative financial
instruments attributable to:
- Risk management activities (1,400) 1,005 -
- Interest expense 9 - -
- Foreign exchange (350) - -
- Other comprehensive income 125 - -
Amortization of deferred revenue - - 8
--------------------------------------------------------------------------------------------------------------------------------
(1,416) 583 -
Add: put premium financing obligations (1) (58) (455) -
--------------------------------------------------------------------------------------------------------------------------------
Balance - end of year (1,474) 128 -
Less: current portion (1,227) 88 -
--------------------------------------------------------------------------------------------------------------------------------
$ (247) $ 40 $ -
================================================================================================================================
(1) THE COMPANY HAS NEGOTIATED PAYMENT OF PUT OPTION PREMIUMS WITH VARIOUS
COUNTER-PARTIES AT THE TIME OF ACTUAL SETTLEMENT OF THE RESPECTIVE
OPTIONS. THESE OBLIGATIONS HAVE BEEN REFLECTED IN THE NET RISK MANAGEMENT
ASSET (LIABILITY).
24
Net losses (gains) from risk management activities for the years ended December
31 were as follows:
2007 2006 2005
=================================================================================================================================
Net realized risk management loss $ 162 $ 1,325 $ 1,027
Net unrealized risk management loss (gain) 1,400 (1,013) 925
---------------------------------------------------------------------------------------------------------------------------------
$ 1,562 $ 312 $ 1,952
=================================================================================================================================
FINANCIAL CONTRACTS
The Company's financial instruments recognized in the consolidated balance
sheets consist of cash and cash equivalents, accounts receivable, accounts
payable, accrued liabilities, risk management activities, and long-term debt.
The carrying value of these financial instruments approximates their fair
value, except as noted below.
2007 2006
(LIABILITY) ASSET CARRYING VALUE FAIR VALUE Carrying value Fair value
==================================================================================================================================
Derivative financial instruments $ (1,416) $ (1,416) $ 583 $ 805
Fixed rate notes $ (6,318) $ (6,259) $ (4,410) $ (4,434)
================================================================ === ===== ============= ====== =============== ==================
The estimated fair values of these financial instruments have been determined
based on the Company's assessment of available market information, appropriate
internal valuation methodologies and/or third party indications. However, these
estimates may not necessarily be indicative of the amounts that could be
realized or settled in a current market transaction and the differences may be
material.
COMMODITY PRICE RISK MANAGEMENT
As at December 31, 2007, the Company had the following net financial
derivatives outstanding to manage its commodity price exposures:
REMAINING TERM VOLUME WEIGHTED AVERAGE PRICE INDEX
==================================================================================================================================
CRUDE OIL
Crude oil price collars (1) Jan 2008 - Mar 2008 50,000 bbl/d US$60.00 - US$80.06 WTI
Jan 2008 - Jun 2008 25,000 bbl/d US$60.00 - US$80.44 WTI
Apr 2008 - Sep 2008 25,000 bbl/d US$60.00 - US$80.46 WTI
Jul 2008 - Sep 2008 25,000 bbl/d US$70.00 - US$123.75 WTI
Oct 2008 - Dec 2008 25,000 bbl/d US$70.00 - US$112.63 WTI
Jan 2008 - Dec 2008 20,000 bbl/d US$50.00 - US$65.53 Mayan Heavy
Jan 2008 - Dec 2008 50,000 bbl/d US$60.00 - US$75.22 WTI
Jan 2008 - Dec 2008 50,000 bbl/d US$60.00 - US$76.05 WTI
Jan 2008 - Dec 2008 50,000 bbl/d US$60.00 - US$76.98 WTI
Crude oil puts Jan 2008 - Dec 2008 50,000 bbl/d US$55.00 WTI
==================================================================================================================================
(1) SUBSEQUENT TO DECEMBER 31, 2007, THE COMPANY ENTERED INTO 25,000 BBL/D OF
US$70.00 - US$111.56 WTI COLLARS FOR THE PERIOD JANUARY TO DECEMBER 2009.
The cost of outstanding put options of US$59 million will be settled in 2008.
REMAINING TERM VOLUME WEIGHTED AVERAGE PRICE INDEX
==================================================================================================================================
NATURAL GAS
AECO price collars Jan 2008 - Mar 2008 400,000 GJ/d C$7.00 - C$14.08 AECO
Jan 2008 - Mar 2008 500,000 GJ/d C$7.50 - C$10.81 AECO
==================================================================================================================================
Commodity related derivative financial instruments designated as hedges at
December 31, 2007, were all classified as cash flow hedges.
The Company's outstanding commodity financial derivatives are expected to be
settled monthly based on the applicable index pricing for the respective
contract month.
As at December 31, 2007, the net pre-tax unrealized loss related to the
de-designation of commodity cash flow hedges was $15 million (2006 - $41
million). This unrealized loss will be recognized in net earnings in 2008.
25
INTEREST RATE RISK MANAGEMENT
The Company is exposed to interest rate price risk on its fixed rate long-term
debt and to interest rate cash flow risk on its floating rate long-term debt.
The Company enters into interest rate swap agreements to manage its fixed to
floating interest rate mix on long-term debt. The interest rate swap contracts
require the periodic exchange of payments without the exchange of the notional
principal amounts on which the payments are based. At December 31, 2007, the
Company had the following interest rate swap contracts outstanding:
REMAINING TERM AMOUNT ($ millions) FIXED RATE FLOATING RATE
===============================================================================================================================
INTEREST RATE
Swaps - fixed to floating Jan 2008 - Oct 2012 US$350 5.45% LIBOR (1) + 0.81%
Jan 2008 - Dec 2014 US$350 4.90% LIBOR (1) + 0.38%
===============================================================================================================================
(1) LONDON INTERBANK OFFERED RATE
All interest rate related derivative financial instruments designated as hedges
at December 31, 2007, were classified as fair value hedges.
FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT
The Company is exposed to foreign exchange rate risk in Canada on its US dollar
denominated debt and on product sales based on US dollar denominated
benchmarks. The Company is also exposed to foreign exchange rate risk on
transactions conducted in foreign currencies in its foreign subsidiaries and in
the carrying value of its self-sustaining foreign subsidiaries. The Company
enters into cross currency swap agreements to manage currency exposure on US
dollar denominated long-term debt. The cross currency swap contracts require
the periodic exchange of payments with the exchange at maturity of notional
principal amounts on which the payments are based. The Company may also enter
into foreign currency denominated financial contracts to manage future US
dollar denominated crude oil and natural gas sales. At December 31, 2007, the
Company had the following cross currency swap contracts outstanding:
AMOUNT EXCHANGE RATE INTEREST RATE INTEREST RATE
REMAINING TERM ($ millions) (US$/C$) (US$) (C$)
==================================================================================================================================
CURRENCY
Swaps Jan 2008 - Aug 2016 US$250 1.116 6.00% 5.40%
Jan 2008 - May 2017 US$1,100 1.170 5.70% 5.10%
Jan 2008 - Mar 2038 US$550 1.170 6.25% 5.76%
==================================================================================================================================
All cross currency related derivative financial instruments designated as
hedges at December 31, 2007, were classified as cash flow hedges.
COUNTERPARTY CREDIT RISK MANAGEMENT
Accounts receivable are mainly with customers in the crude oil and natural gas
industry and are subject to normal industry credit risks. The Company manages
these risks by reviewing its exposure to individual companies on a regular
basis and where appropriate, ensures that parental guarantees or letters of
credit are in place to minimize the impact in the event of default.
The Company is also exposed to possible losses in the event of nonperformance
by counterparties to derivative financial instruments; however, the Company
manages this credit risk by entering into agreements with substantially all
investment grade financial institutions and other entities. At December 31,
2007, the Company had net risk management assets of $20 million (December 31,
2006 - $161 million) with specific counterparties related to derivative
financial instruments.
26
13. COMMITMENTS AND CONTINGENCIES
The Company has committed to certain payments as follows:
2008 2009 2010 2011 2012 Thereafter
===================================================================================================================================
Product transportation and pipeline $ 232 $ 151 $ 137 $ 109 $ 91 $ 972
Offshore equipment operating lease (1) $ 114 $ 129 $ 113 $ 111 $ 90 $ 387
Offshore drilling (2) (3) $ 267 $ 185 $ 39 $ - $ - $ -
Asset retirement obligations (4) $ 33 $ 4 $ 5 $ 4 $ 4 $ 4,376
Office leases $ 26 $ 28 $ 28 $ 22 $ 3 $ -
Electricity and other $ 166 $ 173 $ 25 $ 4 $ - $ -
===================================================================================================================================
(1) OFFSHORE EQUIPMENT OPERATING LEASES ARE PRIMARILY COMPRISED OF
OBLIGATIONS RELATED TO FLOATING PRODUCTION, STORAGE AND OFFTAKE VESSELS
("FPSO"). DURING 2006, THE COMPANY ENTERED INTO AN AGREEMENT TO LEASE AN
ADDITIONAL FPSO COMMENCING IN 2008, IN CONNECTION WITH THE PLANNED
OFFSHORE DEVELOPMENT IN GABON, OFFSHORE WEST AFRICA. DURING THE INITIAL
TERM, THE TOTAL ANNUAL PAYMENTS FOR THE GABON FPSO ARE ESTIMATED TO BE
US$50 MILLION.
(2) DURING 2007, THE COMPANY ENTERED INTO A ONE-YEAR AGREEMENT FOR OFFSHORE
DRILLING SERVICES RELATED TO THE BAOBAB FIELD IN COTE D'IVOIRE, OFFSHORE
WEST AFRICA. THE AGREEMENT IS SCHEDULED TO COMMENCE IN 2008, SUBJECT TO
RIG AVAILABILITY. ESTIMATED TOTAL PAYMENTS OF US$100 MILLION, AFTER JOINT
VENTURE RECOVERIES, HAVE BEEN INCLUDED IN THIS TABLE FOR THE PERIOD
2008-2009.
(3) DURING 2007, THE COMPANY AWARDED CONTRACTS FOR A DRILLING RIG AND FOR THE
CONSTRUCTION OF WELLHEAD TOWERS IN CONNECTION WITH THE PLANNED OFFSHORE
DEVELOPMENT IN GABON, OFFSHORE WEST AFRICA. ESTIMATED TOTAL PAYMENTS OF
US$393 MILLION HAVE BEEN INCLUDED IN THIS TABLE FOR THE PERIOD 2008-2010.
(4) AMOUNTS REPRESENT MANAGEMENT'S ESTIMATE OF THE FUTURE UNDISCOUNTED
PAYMENTS TO SETTLE ASSET RETIREMENT OBLIGATIONS RELATED TO RESOURCE
PROPERTIES, FACILITIES, AND PRODUCTION PLATFORMS, BASED ON CURRENT
LEGISLATION AND INDUSTRY OPERATING PRACTICES. AMOUNTS DISCLOSED FOR THE
PERIOD 2008 - 2012 REPRESENT THE MINIMUM REQUIRED EXPENDITURES TO MEET
THESE OBLIGATIONS. ACTUAL EXPENDITURES IN ANY PARTICULAR YEAR MAY EXCEED
THESE MINIMUM AMOUNTS.
In addition to the amounts disclosed above, the Company has budgeted
construction costs of approximately $1.7 billion to $1.9 billion for 2008
related to the planned completion of Phase 1 of the Horizon Project.
The Company is defendant and plaintiff in a number of legal actions that arise
in the normal course of business. In addition, the Company is subject to
certain contractor construction claims related to the Horizon Project. The
Company believes that any liabilities that might arise pertaining to any such
matters would not have a material effect on its consolidated financial
position.
14. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Changes in non-cash working capital were as follows:
2007 2006 2005
==========================================================================================================================
(Increase) decrease in non-cash working capital
Accounts receivable and other $ 334 $ (116) $ (498)
Accounts payable (456) 157 196
Accrued liabilities (402) (582) 716
--------------------------------------------------------------------------------------------------------------------------
Net change in non-cash working capital $ (524) $ (541) $ 414
--------------------------------------------------------------------------------------------------------------------------
Relating to:
Operating activities $ (346) $ (679) $ (147)
Financing activities 8 37 19
Investing activities (186) 101 542
--------------------------------------------------------------------------------------------------------------------------
$ (524) $ (541) $ 414
==========================================================================================================================
Other cash flow information: 2007 2006 2005
==========================================================================================================================
Interest paid $ 556 $ 262 $ 200
Taxes paid $ 418 $ 703 $ 430
==========================================================================================================================
27
15. BUSINESS COMBINATIONS
ANADARKO CANADA CORPORATION
In November 2006, the Company completed the acquisition of all of the issued
and outstanding common shares of ACC, a subsidiary of Anadarko Petroleum
Corporation, for net cash consideration of $4,641 million including working
capital and other adjustments. Substantially all of ACC's land and production
base are located in Western Canada.
The acquisition was accounted for using the purchase method. Operating results
from ACC have been consolidated with the results of the Company effective from
November 2, 2006, the date of acquisition, and are reported in the North
America segment. The allocation of the net purchase price to assets acquired
and liabilities assumed based on their fair values was as follows:
November 2, 2006
================================================================================
Net purchase price:
Net cash consideration (1) $ 4,641
================================================================================
Net purchase price allocated as follows:
Non-cash working capital deficit assumed and other $ (105)
Property, plant and equipment 6,249
Long-term debt (9)
Asset retirement obligation (56)
Future income tax (1,438)
--------------------------------------------------------------------------------
$ 4,641
================================================================================
(1) NET CASH CONSIDERATION WAS REDUCED BY $88 MILLION TO REFLECT THE
SETTLEMENT OF US DOLLAR CURRENCY FORWARD CONTRACTS DESIGNATED AS HEDGES OF
THE ACC PURCHASE PRICE.
28
16. SEGMENTED INFORMATION
The Company's conventional crude oil and natural gas activities are conducted
in three geographic segments: North America, North Sea and Offshore West
Africa. These activities relate to the exploration, development, production and
marketing of conventional crude oil, natural gas liquids and natural gas.
The Company's Horizon Project is a separate segment from conventional crude oil
and natural gas activities as the bitumen will be recovered through mining
operations. There are currently no revenues for this project and all directly
related expenditures have been capitalized.
Midstream activities include the Company's pipeline operations and an
electricity co-generation system.
Activities that are not included in the above segments are included in the
segmented information as other.
Inter-segment eliminations include internal transportation and electricity
charges.
CONVENTIONAL CRUDE OIL AND NATURAL GAS
-----------------------------------------------------------------------------------------------------
NORTH AMERICA NORTH SEA OFFSHORE WEST AFRICA
2007 2006 2005 2007 2006 2005 2007 2006 2005
===================================================================================================================================
SEGMENTED REVENUE $ 10,149 $ 9,066 $ 8,955 $ 1,597 $ 1,616 $ 1,659 $ 776 $ 950 $ 485
Less: royalties (1,318) (1,203) (1,350) (3) (3) (3) (70) (39) (13)
-----------------------------------------------------------------------------------------------------------------------------------
REVENUE, NET OF ROYALTIES 8,831 7,863 7,605 1,594 1,613 1,656 706 911 472
-----------------------------------------------------------------------------------------------------------------------------------
SEGMENTED EXPENSES
Production 1,642 1,436 1,211 432 390 379 94 106 53
Transportation and
blending 1,595 1,465 1,310 16 15 20 1 1 -
Depletion, depreciation
and amortization 2,350 1,897 1,595 340 297 306 165 189 104
Asset retirement
obligation accretion 38 35 34 30 31 34 2 2 1
Realized risk management
activities 129 1,022 870 33 303 157 - - -
-----------------------------------------------------------------------------------------------------------------------------------
TOTAL SEGMENTED EXPENSES 5,754 5,855 5,020 851 1,036 896 262 298 158
-----------------------------------------------------------------------------------------------------------------------------------
SEGMENTED EARNINGS BEFORE $ 3,077 $ 2,008 $ 2,585 $ 743 $ 577 $ 760 $ 444 $ 613 $ 314
THE FOLLOWING
-----------------------------------------------------------------------------------------------------------------------------------
NON-SEGMENTED EXPENSES
Administration
Stock-based compensation
Interest, net
Unrealized risk management activities
Foreign exchange (gain) loss
-----------------------------------------------------------------------------------------------------------------------------------
TOTAL NON-SEGMENTED EXPENSES
-----------------------------------------------------------------------------------------------------------------------------------
EARNINGS BEFORE TAXES
Taxes other than income tax
Current income tax expense
Future income tax (recovery) expense
-----------------------------------------------------------------------------------------------------------------------------------
NET EARNINGS
===================================================================================================================================
29
INTER-SEGMENT
MIDSTREAM ELIMINATION AND OTHER TOTAL
------------------------------------------------------------------------------------------------------
2007 2006 2005 2007 2006 2005 2007 2006 2005
===================================================================================================================================
SEGMENTED REVENUE $ 74 $ 72 $ 77 $ (53) $ (61) $ (46) $ 12,543 $ 11,643 $ 11,130
Less: royalties - - - - - - (1,391) (1,245) (1,366)
-----------------------------------------------------------------------------------------------------------------------------------
REVENUE, NET OF ROYALTIES 74 72 77 (53) (61) (46) 11,152 10,398 9,764
-----------------------------------------------------------------------------------------------------------------------------------
SEGMENTED EXPENSES
Production 22 23 24 (6) (6) (4) 2,184 1,949 1,663
Transportation and blending - - - (42) (38) (37) 1,570 1,443 1,293
Depletion, depreciation
and amortization 8 8 8 - - - 2,863 2,391 2,013
Asset retirement
obligation accretion - - - - - - 70 68 69
Realized risk management
activities - - - - - - 162 1,325 1,027
-----------------------------------------------------------------------------------------------------------------------------------
TOTAL SEGMENTED EXPENSES 30 31 32 (48) (44) (41) 6,849 7,176 6,065
-----------------------------------------------------------------------------------------------------------------------------------
SEGMENTED EARNINGS BEFORE $ 44 $ 41 $ 45 $ (5) $ (17) $ (5) $ 4,303 $ 3,222 $ 3,699
THE FOLLOWING
-----------------------------------------------------------------------------------------------------------------------------------
NON-SEGMENTED EXPENSES
Administration 208 180 151
Stock-based compensation 193 139 723
Interest, net 276 140 149
Unrealized risk management activities 1,400 (1,013) 925
Foreign exchange (gain) loss (471) 122 (132)
-----------------------------------------------------------------------------------------------------------------------------------
TOTAL NON-SEGMENTED EXPENSES 1,606 (432) 1,816
-----------------------------------------------------------------------------------------------------------------------------------
EARNINGS BEFORE TAXES 2,697 3,654 1,883
Taxes other than income tax 165 256 194
Current income tax expense 380 222 286
Future income tax (recovery) expense (456) 652 353
-----------------------------------------------------------------------------------------------------------------------------------
NET EARNINGS $ 2,608 $ 2,524 $ 1,050
===================================================================================================================================
CAPITAL EXPENDITURES
2007 2006
NON CASH/FAIR Non cash/fair
NET VALUE CAPITALIZED Net value Capitalized
EXPENDITURES CHANGES(1) COSTS expenditures changes(1) costs
==================================================================================================================================
Conventional crude oil
and natural gas
North America $ 2,428 $ 52 $ 2,480 $ 7,936 $ 1,521 $ 9,457
North Sea 439 (77) 362 646 (14) 632
Offshore West
Africa 159 (11) 148 134 1 135
Other 1 - 1 11 - 11
----------------------------------------------------------------------------------------------------------------------------------
3,027 (36) 2,991 8,727 1,508 10,235
Horizon Project (2) 3,301 - 3,301 3,185 - 3,185
Midstream 6 - 6 12 - 12
Head office 20 - 20 26 - 26
----------------------------------------------------------------------------------------------------------------------------------
$ 6,354 $ (36) $ 6,318 $ 11,950 $ 1,508 $ 13,458
==================================================================================================================================
(1) ASSET RETIREMENT OBLIGATIONS, FUTURE INCOME TAX ADJUSTMENTS RELATED TO
DIFFERENCES BETWEEN CARRYING VALUE AND TAX VALUE, AND OTHER FAIR VALUE
ADJUSTMENTS.
(2) NET EXPENDITURES FOR THE HORIZON PROJECT ALSO INCLUDE CAPITALIZED INTEREST
AND STOCK-BASED COMPENSATION.
30
SEGMENTED ASSETS
2007 2006
=================================================================================================================================
Conventional crude oil and natural gas
North America $ 23,617 $ 23,670
North Sea 1,957 2,248
Offshore West Africa 1,354 1,323
Other 41 46
Horizon Project 8,740 5,444
Midstream 333 355
Head office 72 74
---------------------------------------------------------------------------------------------------------------------------------
$ 36,114 $ 33,160
=================================================================================================================================
17. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED
ACCOUNTING PRINCIPLES
The Company's consolidated financial statements have been prepared in
accordance with Canadian GAAP. These principles conform in all material
respects with US GAAP except for those noted below. Certain differences arising
from US GAAP disclosure requirements are not addressed.
The application of US GAAP would have the following effects on consolidated net
earnings as reported:
(millions of Canadian dollars, except per common share amounts) Notes 2007 2006 2005
=================================================================================================================================
Net earnings - Canadian GAAP $ 2,608 $ 2,524 $ 1,050
Adjustments
Depletion, net of taxes of $1 million
(2006 - $1 million, 2005 - $3 million) (A,D) (10) 2 4
Stock-based compensation, net of taxes of $3
million (2006 - $18 million, 2005 - $nil) (B) (22) (40) -
Future income taxes (H) (234) - -
Derivative financial instruments and hedging
activities, net of taxes of $nil
(2006 - $15 million, 2005 - $11 million) (C,D) - 117 (19)
---------------------------------------------------------------------------------------------------------------------------------
Net earnings before cumulative effect of change in
accounting policy - US GAAP 2,342 2,603 1,035
Cumulative effect of change in accounting policy,
net of taxes of $nil (2006 - $3 million, 2005 -
$nil) (B) - (8) -
---------------------------------------------------------------------------------------------------------------------------------
Net earnings - US GAAP $ 2,342 $ 2,595 $ 1,035
=================================================================================================================================
Net earnings before cumulative effect of change in
accounting policy - US GAAP per common share
Basic $ 4.34 $ 4.84 $ 1.93
Diluted (F) $ 4.32 $ 4.77 $ 1.88
=================================================================================================================================
Net earnings - US GAAP per common share
Basic $ 4.34 $ 4.83 $ 1.93
Diluted (F) $ 4.32 $ 4.75 $ 1.88
=================================================================================================================================
Comprehensive income under US GAAP would be as follows:
(millions of Canadian dollars) Notes 2007 2006 2005
================================================================================================================================
Comprehensive income - Canadian GAAP $ 2,534 $ 2,520 $ 1,047
US GAAP earnings adjustments (266) 71 (15)
Derivative financial instruments and hedging
activities, net of taxes of $nil (2006 - $394
million; 2005 - $312 million) (C,D) - 805 (635)
--------------------------------------------------------------------------------------------------------------------------------
Comprehensive income - US GAAP $ 2,268 $ 3,396 $ 397
================================================================================================================================
31
The components of accumulated other comprehensive income under US GAAP, net of
taxes, would be as follows:
2007 2006
=================================================================================================================================
Derivative financial instruments designated as cash flow hedges 101 159
Foreign currency translation adjustment (29) (13)
---------------------------------------------------------------------------------------------------------------------------------
Accumulated other comprehensive income 72 146
=================================================================================================================================
The application of US GAAP would have the following effects on the consolidated
balance sheets as reported:
2007
(millions of Canadian dollars) Notes CANADIAN GAAP INCREASE (DECREASE) US GAAP
==================================================================================================================================
Current assets 2,181 - 2,181
Property, plant and equipment (A,B,D,E) 33,902 91 33,993
Other long-term assets (I) 31 51 82
----------------------------------------------------------------------------------------------------------------------------------
36,114 142 36,256
----------------------------------------------------------------------------------------------------------------------------------
Current liabilities (B) 3,563 66 3,629
Long-term debt (I) 10,940 51 10,991
Other long-term liabilities (B) 1,561 20 1,581
Future income tax (A,B,D,E,H) 6,729 236 6,965
Share capital 2,674 - 2,674
Retained earnings 10,575 (231) 10,344
Accumulated other comprehensive income 72 - 72
----------------------------------------------------------------------------------------------------------------------------------
36,114 142 36,256
==================================================================================================================================
2006
(millions of Canadian dollars) Notes Canadian GAAP Increase (Decrease) US GAAP
==================================================================================================================================
Current assets (C) 2,239 131 2,370
Property, plant and equipment (A,B,D,E) 30,767 89 30,856
Other long-term assets (C) 154 29 183
----------------------------------------------------------------------------------------------------------------------------------
33,160 249 33,409
----------------------------------------------------------------------------------------------------------------------------------
Current liabilities (B) 3,071 30 3,101
Long-term debt (C) 11,043 (26) 11,017
Other long-term liabilities (B) 1,393 20 1,413
Future income tax (A,B,C,D,E) 6,963 21 6,984
Share capital 2,562 - 2,562
Retained earnings 8,141 45 8,186
Accumulated other comprehensive (loss) income (C) (13) 159 146
----------------------------------------------------------------------------------------------------------------------------------
33,160 249 33,409
==================================================================================================================================
32
NOTES:
(A) Under Canadian full cost accounting rules, costs capitalized in each
country cost centre are limited to an amount equal to the undiscounted,
future net revenues from proved reserves using estimated future prices
and costs, plus the carrying amount of unproved properties and major
development projects (the "ceiling test"). Under the full cost method of
accounting as set forth by the US Securities and Exchange Commission, the
ceiling test differs from Canadian GAAP in that future net revenues from
proved reserves are based on prices and costs as at the balance sheet
date ("constant dollar pricing") and are discounted at 10%. Capitalized
costs and future net revenues are determined on a net of tax basis. These
differences in applying the ceiling test to prior years resulted in the
recognition of a ceiling test impairment under US GAAP, decreasing
property, plant and equipment.
For the year ended December 31, 2007, US GAAP net earnings would have
decreased by $4 million (2006 - increased by $3 million, 2005 - increased
by $4 million), net of income taxes of $8 million (2006 - $2 million,
2005 - $3 million) to reflect the impact of lower depletion charges. The
2007 income tax effect includes the effect of enacted Canadian income tax
rate changes on this item.
(B) The Company accounts for its stock-based compensation liability under
Canadian GAAP using the intrinsic value method, as described in note
1(P). Under US GAAP, effective January 1, 2006, the Company would have
adopted Financial Accounting Standards Board Statement ("FAS") 123(R),
which requires companies to account for all stock-based compensation
liabilities using the fair value method, where fair value is measured
using an option pricing model. The Company uses the Black Scholes option
pricing model to determine the fair value of its stock-based compensation
liability for US GAAP purposes. The previous US GAAP standard, FAS 123,
required companies to account for cash settled stock-based compensation
liabilities using the intrinsic value method. For the year ended December
31, 2007, US GAAP net earnings would have decreased by $22 million (2006
- $48 million), net of income taxes of $3 million (2006 - $21 million,
including the cumulative effect of the change in accounting policy of $8
million, net of income taxes of $3 million). The 2007 income tax effect
includes the effect of enacted Canadian income tax rate changes on this
item. There was no difference from Canadian GAAP prior to 2006.
(C) Effective January 1, 2007, the Company adopted new accounting standards
for financial instruments as described in note 2. The Company's
accounting policies for financial instruments under Canadian GAAP are
described in notes 1(Q) and 1(R). After adopting the new standards,
Canadian GAAP is substantially harmonized with US GAAP as prescribed by
FAS 133, "Accounting for Derivative Financial Instruments and Hedging
Activities," as amended by FAS 138 and FAS 149. Prior to adoption of the
new accounting policies, for the year ended December 31, 2006, assets
would have increased by $160 million, liabilities would have decreased by
$9 million, and accumulated other comprehensive income would have
increased by $159 million as a result of recording all derivative
financial instruments at fair value in accordance with US GAAP.
The net earnings associated with realized and unrealized hedge
ineffectiveness on derivative contracts designated as cash flow hedges
during the year ended December 31, 2006 would have been $29 million, net
of income taxes of $15 million (2005 - loss of $19 million, net of income
taxes of $11 million).
(D) During 2006, under Canadian GAAP, the Company hedged the foreign currency
component of the US dollar purchase price of ACC using derivative
financial instruments formally designated as cash flow hedges. Under US
GAAP, the foreign currency component of a business combination is not
eligible for cash flow hedging, and therefore, for the year ended
December 31, 2006, the $88 million after-tax gain on the derivative
financial instruments would have been included in net earnings. For the
year ended December 31, 2007, US GAAP net earnings would have been
decreased by $6 million (2006 - $1 million), net of income taxes of $7
million (2006 - $1 million), to reflect the impact of higher depletion
charges. The 2007 income tax effect includes the effect of enacted
Canadian income tax rate changes on this item.
(E) Under Canadian GAAP, the Company began capitalizing interest on the
Horizon Project when the Board of Directors approval was received in
2005. For US GAAP, capitalization of interest on projects constructed
over time is mandatory and interest would have been capitalized to the
costs of construction beginning in 2004. As a result of applying US GAAP,
an additional $27 million would have been capitalized to property, plant
and equipment in 2004.
33
(F) Under Canadian GAAP, the Company is not required to include potential
common shares related to stock options in the calculation of diluted
earnings per share as the Company has recorded the potential settlement
of the stock options as a liability. Under US GAAP FAS 128 "Earnings per
Share", the Company would have included potential common shares related
to stock options in the calculation of diluted earnings per share. For
the year ended December 31, 2007, an additional 3,376,000 shares would
have been included in the calculation of diluted earnings per share for
US GAAP (2006 - 8,762,000 additional shares, 2005 - 13,593,000 additional
shares).
(G) In July 2006, the FASB issued Interpretation ("FIN") No. 48 "Accounting
for Uncertainty in Tax Positions - an Interpretation of FASB Statement
No. 109", effective for fiscal years beginning after December 15, 2006.
FIN 48 prescribes thresholds for recognizing the benefits of uncertain
tax positions in the financial statements. It also provides guidance on
derecognition, classification, interest and penalties, disclosure and
transition. The adoption of this standard did not result in a reconciling
item under US GAAP.
(H) Under Canadian GAAP, the effects of income tax changes are recognized
when the changes are considered substantively enacted. Under US GAAP, the
income tax changes would not be recognized until the changes are enacted
into law. For the year ended December 31, 2007, the differences between
substantively enacted and enacted tax legislation results in a difference
in timing of the recognition of a $234 million future tax recovery.
(I) Effective January 1, 2007, under Canadian GAAP, debt issue costs on
long-term debt must be included in the carrying value of the related
debt. Under US GAAP, these items must be recorded as a deferred charge.
Application of US GAAP would have resulted in the balance sheet
reclassification of $51 million of debt issue costs from long-term debt
to deferred charges in 2007. There were no GAAP differences prior to
2007.
(J) US GAAP - RECENTLY ISSUED ACCOUNTING STANDARDS
In September 2006, the FASB issued FAS 157 "Fair Value Measurements"
effective for fiscal years beginning after November 15, 2007. The
implementation date was subsequently delayed until years beginning on or
after November 15, 2008 except for non financial assets and non financial
liabilities that are recognized or disclosed at fair value in the
financial statements on a recurring basis (at least annually). FAS 157
standardizes the meaning of "Fair Value" in all FASB statements that
refer to fair value and expands disclosures about fair value
measurements. The Company is currently assessing the impact this standard
has on its consolidated financial statements.
In February 2007, the FASB issued FAS 159 "The Fair Value Option for
Financial Assets and Financial Liabilities" effective for fiscal years
beginning after November 15, 2007. FAS 159 allows entities to carry most
financial instruments at fair value, even if existing standards would not
require this. The Company is currently assessing the impact this standard
has on its consolidated financial statements.
In December 2007, the FASB issued FAS 141(R) "Business Combinations",
which replaces FAS 141 effective for fiscal years beginning after
December 15, 2008. FAS 141(R) retains the purchase method of accounting
and requires assets acquired and liabilities assumed in a business
combination to be measured at fair value at the date of acquisition. The
standard also requires acquisition-related costs and restructuring costs
to be recognized separately from the business combination. This standard
is to be applied prospectively to all business combinations subsequent to
the effective date and does not require restatement of previously
completed business combinations.
34
MANAGEMENT'S DISCUSSION AND ANALYSIS
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements in this document or documents incorporated herein by
reference constitute forward-looking statements or information (collectively
referred to herein as "forward-looking statements") within the meaning of
applicable securities legislation. Forward-looking statements can be identified
by the words "believe", "anticipate", "expect", "plan", "estimate", "target",
"continue", "could", "intend", "may", "potential", "predict", "should", "will",
"objective", "project", "forecast", "goal", "guidance", "outlook", "effort",
"seeks", "schedule" or expressions of a similar nature suggesting future
outcome or statements regarding an outlook. Disclosure related to expected
future commodity pricing, production volumes, royalties, operating costs,
capital expenditures and other 2008 guidance provided throughout this
Management's Discussion and Analysis ("MD&A"), including the information
provided in the "Outlook" section, constitutes forward-looking statements. 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 crude oil and natural gas reserves and in projecting future rates of
production and the timing of development expenditures. The total amount or
timing of actual future production may vary significantly from reserve and
production estimates.
These statements are not guarantees of future performance and are subject to
certain risks and the reader should not place undue reliance on these
forward-looking statements as there can be no assurance that the plans,
initiatives or expectations upon which they are based will occur.
The forward-looking statements are based on current expectations, estimates and
projections about Canadian Natural Resources Limited (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, uncertainties and
other factors 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
factors include, among others: general economic and business conditions which
will, among other things, impact demand for and market prices of the Company's
products; volatility of and assumptions regarding crude oil and natural gas
prices; fluctuations in currency and interest rates; assumptions on which the
Company's current guidance is based; economic conditions in the countries and
regions in which the Company conducts business; political uncertainty,
including actions of or against terrorists, insurgent groups or other conflict
including conflict between states; industry capacity; ability of the Company to
implement its business strategy, including exploration and development
activities; impact of competition; the Company's defense of lawsuits;
availability and cost of seismic, drilling and other equipment; ability of the
Company and its subsidiaries to complete its capital programs; the Company's
and its subsidiaries' ability to secure adequate transportation for its
products; unexpected difficulties in mining, extracting or upgrading the
Company's bitumen products; potential delays or changes in plans with respect
to exploration or development projects or capital expenditures; ability of the
Company to attract the necessary labour required to build its thermal and oil
sands mining projects; operating hazards and other difficulties inherent in the
exploration for and production and sale of crude oil and natural gas;
availability and cost of financing; the Company's and its subsidiaries' success
of exploration and development activities and their ability to replace and
expand crude oil and natural gas reserves; timing and success of integrating
the business and operations of acquired companies; production levels;
imprecision of reserve estimates and estimates of recoverable quantities of
crude oil, bitumen, natural gas and liquids not currently classified as proved;
actions by governmental authorities; government regulations and the
expenditures required to comply with them (especially safety and environmental
laws and regulations and the impact of climate change initiatives on capital
and operating costs); asset retirement obligations; the adequacy of the
Company's provision for taxes; and other circumstances affecting revenues and
expenses. The Company's operations have been, and at times in the future may
be, affected by political developments and by federal, provincial and local
laws and regulations such as restrictions on production, changes in taxes,
royalties and other amounts payable to governments or governmental agencies,
price or gathering rate controls and environmental protection regulations.
Should one or more of these risks or uncertainties materialize, or should any
of the Company's assumptions prove incorrect, actual results may vary in
material respects from those projected in the forward-looking statements. The
impact of any one factor on a particular forward-looking statement is not
determinable with certainty as such factors are interdependent 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 and Uncertainties" section of this MD&A.
Readers are cautioned that the foregoing list of important factors is not
exhaustive. Unpredictable or unknown factors not discussed in this report could
also have material adverse effects on forward-looking statements. Although the
Company believes that the expectations conveyed by the forward-looking
statements are reasonable based on information available to it on the date such
forward-looking statements are made, no assurances can be given as to future
1
results, levels of activity and achievements. All subsequent forward-looking
statements, whether written or oral, attributable to the Company or persons
acting on its behalf are expressly qualified in their entirety by these
cautionary statements. Except as required by law, the Company assumes no
obligation to update forward-looking statements should circumstances or
Management's estimates or opinions change.
SPECIAL NOTE REGARDING NON-GAAP FINANCIAL MEASURES
Management's Discussion and Analysis includes references to financial measures
commonly used in the crude oil and natural gas industry, such as cash flow from
operations, adjusted net earnings from operations and net asset value. These
financial measures are not defined by Canadian generally accepted accounting
principles ("GAAP") and therefore are referred to as non-GAAP measures. The
non-GAAP measures used by the Company may not be comparable to similar measures
presented by other companies. The Company uses these non-GAAP measures to
evaluate its performance. The non-GAAP measures should not be considered an
alternative to or more meaningful than net earnings, as determined in
accordance with Canadian GAAP, as an indication of the Company's performance.
2
MANAGEMENT'S DISCUSSION AND ANALYSIS
Management's Discussion and Analysis of the financial condition and results of
operations of the Company should be read in conjunction with the Company's
audited consolidated financial statements and related notes for the year ended
December 31, 2007. The consolidated financial statements have been prepared in
accordance with Canadian GAAP. A reconciliation of Canadian GAAP to United
States GAAP is included in note 17 to the consolidated financial statements.
All dollar amounts are referenced in Canadian dollars, except where otherwise
noted. The calculation of barrels of oil equivalent ("boe") is based on a
conversion ratio of six thousand cubic feet ("mcf") of natural gas to one
barrel ("bbl") of crude oil to estimate relative energy content. This
conversion may be misleading, particularly when used in isolation, since the 6
mcf:1 bbl ratio is based on an energy equivalency at the burner tip and does
not represent the value equivalency at the wellhead. Production volumes are the
Company's interest before royalties, and realized prices exclude the effect of
risk management activities and transportation and blending costs, except where
otherwise noted. The following discussion and analysis refers primarily to the
Company's 2007 financial results compared to 2006 and 2005, unless otherwise
indicated. In addition, this MD&A details the Company's capital program and
outlook for 2008.
Additional information relating to the Company, including its quarterly MD&A
for the year and three months ended December 31, 2007 and its Annual
Information Form for the year ended December 31, 2007, is available on SEDAR at
www.sedar.com.
This MD&A is dated February 26, 2008.
ABBREVIATIONS
ACC Anadarko Canada Corporation
AECO Alberta natural gas reference location
API Specific gravity measured in degrees on the American
Petroleum Institute scale
ARO Asset retirement obligations
BBL barrel
BBL/D barrels per day
BOE barrels of oil equivalent
BOE/D barrels of oil equivalent per day
BRENT Dated Brent
C$ Canadian dollars
CO2 Carbon dioxide
CO2e Carbon dioxide equivalents
CICA Canadian Institute of Chartered Accountants
FPSO Floating Production, Storage and Offtake Vessel
GAAP Generally accepted accounting principles
GHG Greenhouse gas
GJ gigajoule
HEAVY DIFFERENTIAL Heavy crude oil differential from WTI
HORIZON PROJECT Horizon Oil Sands Project LLB Lloyd Blend
MCF thousand cubic feet
MMBTU million British thermal units
MMCF/D million cubic feet per day
NGLS Natural gas liquids
NYMEX New York Mercantile Exchange
NYSE New York Stock Exchange
SCO Synthetic light crude oil
SEC United States Securities and Exchange Commission
TSX Toronto Stock Exchange
UK United Kingdom
US United States
US$ United States dollars
WTI West Texas Intermediate
3
OBJECTIVE AND STRATEGY
The Company's objectives are to increase crude oil and natural gas production,
reserves, cash flow and net asset value (1) 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 strives
to meet the objectives by having a defined growth and value enhancement plan
for each of its products and segments. The Company takes a balanced approach to
growth and investments and focuses on creating long-term shareholder value. The
Company allocates its capital by maintaining:
o Balance among its products, namely natural gas, light/medium crude oil,
Pelican Lake crude oil (2), primary heavy crude oil and thermal heavy
crude oil;
o Balance among near-, mid- and long-term projects;
o Balance among acquisitions, exploitation and exploration; and
o Balance between sources and terms of debt financing and maintenance of a
strong balance sheet.
(1) DISCOUNTED VALUE OF CONVENTIONAL CRUDE OIL AND NATURAL GAS RESERVES PLUS
VALUE OF UNDEVELOPED LAND, LESS NET DEBT.
(2) PELICAN LAKE CRUDE OIL IS 14-17(0) API OIL, WHICH RECEIVES MEDIUM QUALITY
CRUDE NETBACKS DUE TO LOWER PRODUCTION COSTS AND LOWER ROYALTY RATES.
The Company's three-phase crude oil marketing strategy includes:
o Blending various crude oil streams with diluents to create more attractive
feedstock;
o Supporting and participating in pipeline expansions and/or new additions;
and
o Supporting and participating in projects that will increase the downstream
conversion capacity for heavy crude oil.
Operational discipline and cost control are central to the Company. By
consistently controlling costs throughout all cycles of the industry, the
Company believes that it will achieve continued growth. Cost control is
attained by developing area knowledge, by dominating core areas and by
maintaining high working interests and operator status in its properties.
The Company is committed to maintaining its strong financial position. The
Company believes that it has built the necessary financial capacity to complete
the Horizon Project while at the same time not compromising the delivery of its
conventional crude oil and natural gas growth opportunities. Additionally, the
Company's risk management hedge program reduces the risk of volatility in
commodity price markets and supports the Company's cash flow for its capital
expenditures program throughout the Horizon Project construction period.
Strategic accretive acquisitions like the acquisition of ACC in 2006 are a key
component of the Company's strategy. The Company has used a combination of
internally generated cash flows and debt financing to selectively acquire
properties generating future cash flows in its core regions.
Highlights for the year ended December 31, 2007 are as follows:
o Achieved record levels of net earnings, adjusted net earnings from
operations and cash flow;
o Achieved record natural gas production;
o Achieved its annual production guidance for crude oil and NGLs and natural
gas;
o Completed 90% of Phase 1 work progress of the Horizon Project; and
o Increased dividends per common share.
4
NET EARNINGS AND CASH FLOW FROM OPERATIONS
FINANCIAL HIGHLIGHTS
($ millions, except per common share amounts) 2007 2006 2005
============================================================================================
Revenue, before royalties $ 12,543 $ 11,643 $ 11,130
Net earnings $ 2,608 $ 2,524 $ 1,050
Per common share - basic $ 4.84 $ 4.70 $ 1.96
- diluted $ 4.84 $ 4.70 $ 1.95
Adjusted net earnings from operations (1) $ 2,406 $ 1,664 $ 2,034
Per common share - basic $ 4.46 $ 3.10 $ 3.79
- diluted $ 4.46 $ 3.10 $ 3.78
Cash flow from operations (2) $ 6,198 $ 4,932 $ 5,021
Per common share - basic $ 11.49 $ 9.18 $ 9.36
- diluted $ 11.49 $ 9.18 $ 9.33
Dividends declared per common share $ 0.34 $ 0.30 $ 0.236
Total assets $ 36,114 $ 33,160 $ 21,852
Total long-term liabilities $ 19,230 $ 19,399 $ 9,790
Capital expenditures, net of dispositions $ 6,425 $ 12,025 $ 4,932
============================================================================================
(1) ADJUSTED NET EARNINGS FROM OPERATIONS IS A NON-GAAP MEASURE THAT
REPRESENTS NET EARNINGS ADJUSTED FOR CERTAIN ITEMS OF A NON-OPERATIONAL
NATURE. THE COMPANY EVALUATES ITS PERFORMANCE BASED ON ADJUSTED NET
EARNINGS FROM OPERATIONS. THE RECONCILIATION "ADJUSTED NET EARNINGS FROM
OPERATIONS" BELOW LISTS THE AFTER-TAX EFFECTS OF CERTAIN ITEMS OF A
NON-OPERATIONAL NATURE THAT ARE INCLUDED IN THE COMPANY'S FINANCIAL
RESULTS. ADJUSTED NET EARNINGS FROM OPERATIONS MAY NOT BE COMPARABLE TO
SIMILAR MEASURES PRESENTED BY OTHER COMPANIES.
(2) CASH FLOW FROM OPERATIONS IS A NON-GAAP MEASURE THAT REPRESENTS NET
EARNINGS ADJUSTED FOR NON-CASH ITEMS BEFORE WORKING CAPITAL ADJUSTMENTS.
THE COMPANY EVALUATES ITS PERFORMANCE BASED ON CASH FLOW FROM OPERATIONS.
THE COMPANY CONSIDERS CASH FLOW FROM OPERATIONS A KEY MEASURE AS IT
DEMONSTRATES THE COMPANY'S ABILITY TO GENERATE THE CASH FLOW NECESSARY TO
FUND FUTURE GROWTH THROUGH CAPITAL INVESTMENT AND TO REPAY DEBT. THE
RECONCILIATION "CASH FLOW FROM OPERATIONS" BELOW LISTS THE EFFECTS OF
CERTAIN NON-CASH ITEMS THAT ARE INCLUDED IN THE COMPANY'S FINANCIAL
RESULTS. CASH FLOW FROM OPERATIONS MAY NOT BE COMPARABLE TO SIMILAR
MEASURES PRESENTED BY OTHER COMPANIES.
ADJUSTED NET EARNINGS FROM OPERATIONS
($ MILLIONS) 2007 2006 2005
==========================================================================================================
NET EARNINGS AS REPORTED $ 2,608 $ 2,524 $ 1,050
STOCK-BASED COMPENSATION EXPENSE, NET OF TAX (a) 134 95 481
UNREALIZED RISK MANAGEMENT LOSS (GAIN), NET OF TAX (b) 977 (674) 607
UNREALIZED FOREIGN EXCHANGE (GAIN) LOSS, NET OF TAX (c) (449) 114 (85)
EFFECT OF STATUTORY TAX RATE AND OTHER LEGISLATIVE CHANGES
ON FUTURE INCOME TAX LIABILITIES (d) (864) (395) (19)
----------------------------------------------------------------------------------------------------------
ADJUSTED NET EARNINGS FROM OPERATIONS $ 2,406 $ 1,664 $ 2,034
==========================================================================================================
(a) THE COMPANY'S EMPLOYEE STOCK OPTION PLAN PROVIDES FOR A CASH PAYMENT
OPTION. ACCORDINGLY, THE INTRINSIC VALUE OF THE OUTSTANDING VESTED
OPTIONS IS RECORDED AS A LIABILITY ON THE COMPANY'S BALANCE SHEET AND
PERIODIC CHANGES IN THE INTRINSIC VALUE ARE RECOGNIZED IN NET EARNINGS
OR ARE CAPITALIZED AS PART OF THE HORIZON PROJECT DURING THE
CONSTRUCTION PERIOD.
(b) DERIVATIVE FINANCIAL INSTRUMENTS ARE RECORDED AT FAIR VALUE ON THE
BALANCE SHEET, WITH CHANGES IN FAIR VALUE OF NON-DESIGNATED HEDGES
FLOWING THROUGH NET EARNINGS. THE AMOUNTS ULTIMATELY REALIZED MAY BE
MATERIALLY DIFFERENT THAN REFLECTED IN THE FINANCIAL STATEMENTS DUE TO
CHANGES IN PRICES OF THE UNDERLYING ITEMS HEDGED, PRIMARILY CRUDE OIL
AND NATURAL GAS.
(c) UNREALIZED FOREIGN EXCHANGE GAINS AND LOSSES RESULT PRIMARILY FROM THE
TRANSLATION OF US DOLLAR DENOMINATED LONG-TERM DEBT TO PERIOD-END
EXCHANGE RATES, OFFSET BY THE IMPACT OF CROSS CURRENCY SWAPS, AND ARE
IMMEDIATELY RECOGNIZED IN NET EARNINGS.
(d) ALL SUBSTANTIVELY ENACTED ADJUSTMENTS IN APPLICABLE INCOME TAX RATES
AND OTHER LEGISLATIVE CHANGES ARE APPLIED TO UNDERLYING ASSETS AND
LIABILITIES ON THE COMPANY'S CONSOLIDATED BALANCE SHEET IN DETERMINING
FUTURE INCOME TAX ASSETS AND LIABILITIES. THE IMPACT OF THESE TAX RATE
CHANGES IS RECORDED IN NET EARNINGS DURING THE PERIOD THE LEGISLATION
IS SUBSTANTIVELY ENACTED. INCOME TAX RATE AND OTHER LEGISLATIVE
CHANGES DURING 2007 RESULTED IN A REDUCTION OF FUTURE INCOME TAX
LIABILITIES OF APPROXIMATELY $864 MILLION IN NORTH AMERICA. INCOME TAX
RATE CHANGES DURING 2006 RESULTED IN AN INCREASE OF FUTURE INCOME TAX
LIABILITIES OF APPROXIMATELY $110 MILLION IN THE NORTH SEA, A
REDUCTION OF APPROXIMATELY $438 MILLION IN NORTH AMERICA, AND A
REDUCTION OF APPROXIMATELY $67 MILLION IN OFFSHORE WEST AFRICA. INCOME
TAX RATE CHANGES DURING 2005 RESULTED IN A REDUCTION OF FUTURE INCOME
TAX LIABILITIES OF APPROXIMATELY $19 MILLION IN NORTH AMERICA.
5
CASH FLOW FROM OPERATIONS
($ MILLIONS) 2007 2006 2005
===================================================================================================
NET EARNINGS $ 2,608 $ 2,524 $ 1,050
NON-CASH ITEMS:
DEPLETION, DEPRECIATION AND AMORTIZATION 2,863 2,391 2,013
ASSET RETIREMENT OBLIGATION ACCRETION 70 68 69
STOCK-BASED COMPENSATION EXPENSE 193 139 723
UNREALIZED RISK MANAGEMENT LOSS (GAIN) 1,400 (1,013) 925
UNREALIZED FOREIGN EXCHANGE (GAIN) LOSS (524) 134 (103)
DEFERRED PETROLEUM REVENUE TAX EXPENSE (RECOVERY) 44 37 (9)
FUTURE INCOME TAX (RECOVERY) EXPENSE (456) 652 353
---------------------------------------------------------------------------------------------------
CASH FLOW FROM OPERATIONS $ 6,198 $ 4,932 $ 5,021
===================================================================================================
For 2007, the Company reported net earnings of $2,608 million compared to net
earnings of $2,524 million for 2006 (2005 - $1,050 million). Net earnings for
the year ended December 31, 2007 included net unrealized after-tax income of
$202 million related to the effects of risk management activities, fluctuations
in foreign exchange rates, stock-based compensation expense and the impact of
statutory tax rate and other legislative changes on future income tax
liabilities (2006 - net unrealized after-tax income of $860 million; 2005 - net
unrealized after-tax expenses of $984 million). Excluding these items, adjusted
net earnings from operations for the year ended December 31, 2007 increased to
$2,406 million from $1,664 million for 2006 (2005 - $2,034 million) primarily
due to higher realized pricing, lower realized risk management losses, higher
North America crude oil and NGLs and natural gas sales volumes, and lower
income tax expense. These factors were partially offset by higher production
expense, higher depletion, depreciation and amortization expense, higher
interest expense, and the impact of the stronger Canadian dollar relative to
the US dollar.
The Company expects that consolidated net earnings will continue to reflect
significant volatility due to the impact of risk management activities,
stock-based compensation expense and fluctuations in foreign exchange rates.
The Company's commodity hedging program reduces the risk of volatility in
commodity price markets and supports the Company's cash flow for its capital
expenditures throughout the Horizon Project construction period. This program
allows for the hedging of up to 75% of the near 12 months budgeted production,
up to 50% of the following 13 to 24 months estimated production and up to 25%
of production expected in months 25 to 48. For the purpose of this program, the
purchase of crude oil put options is in addition to the above parameters. In
accordance with the policy, approximately 65% of budgeted crude oil volumes are
hedged for 2008 and approximately 53% of budgeted natural gas volumes are
hedged for the first quarter of 2008. Subsequent to December 31, 2007, the
Company hedged 25,000 bbl/d of crude oil volumes for 2009 using WTI collars
with a US$70.00 floor.
The Company's outstanding commodity related financial derivatives as at
December 31, 2007 are detailed in the "Liquidity and Capital Resources" section
of this MD&A.
As disclosed in note 2 to the Company's consolidated financial statements,
commencing January 1, 2007 all derivative financial instruments are recognized
at fair value on the consolidated balance sheet at each reporting date. As
effective as the Company's hedges are against reference commodity prices, a
substantial portion of the derivative financial instruments entered into by the
Company have not been formally designated as hedges for accounting purposes or
do not meet the requirements for hedge accounting under GAAP due to currency,
product quality and location differentials (the "non-designated hedges"). The
change in the fair value of the non-designated hedges is based on prevailing
forward commodity prices in effect at the end of each reporting period and is
reflected in risk management activities in consolidated net earnings. The cash
settlement amount of the risk management derivative financial instruments may
vary materially depending upon the underlying crude oil and natural gas prices
at the time of final settlement of the derivative financial instruments, as
compared to their mark-to-market value at December 31, 2007.
Due to the changes in crude oil and natural gas forward pricing and the
reversal of prior-year unrealized gains and losses, the Company recorded a net
unrealized loss of $1,400 million ($977 million after-tax) on its commodity
risk management activities for the year ended December 31, 2007 (2006 - $1,013
million unrealized gain, $674 million after-tax; 2005 - $925 million unrealized
loss, $607 million after-tax). Mark-to-market unrealized gains and losses do
not impact the Company's current cash flow or its ability to finance ongoing
capital programs. The Company continues to believe that its risk management
program meets its objective of securing funding for its capital projects and
does not intend to alter its current strategy of obtaining price certainty for
its crude oil and natural gas sales. For further details, refer to the "Risk
Management Activities" section of this MD&A.
6
The Company also recorded a $193 million ($134 million after-tax) stock-based
compensation expense as a result of the 17% increase in the Company's share
price for the year ended December 31, 2007 (Company's share price as at:
December 31, 2007 - $72.58; December 31, 2006 - $62.15; December 31, 2005 -
$57.63; December 31, 2004 - $25.63). As required by GAAP, the Company records a
liability for potential cash payments to settle its outstanding employee stock
options each reporting period based on the difference between the exercise
price of the stock options and the market price of the Company's common shares,
pursuant to a graded vesting schedule. The liability is revalued at each
reporting date to reflect the changes in the market price of the Company's
common shares and the options exercised or surrendered in the year, with the
net change recognized in net earnings, or capitalized as part of the Horizon
Project during the construction period. The stock-based compensation liability
at December 31, 2007 reflected the Company's potential cash liability should
all the vested options be surrendered for a cash payout at the market price on
December 31, 2007. In years when substantial share price changes occur, the
Company's net earnings are subject to significant volatility. The Company
utilizes its stock-based compensation plan to attract and retain employees in a
competitive environment. All employees participate in this plan.
Cash flow from operations for the year ended December 31, 2007 increased to
$6,198 million ($11.49 per common share) from $4,932 million ($9.18 per common
share) for 2006 (2005 - $5,021 million; $9.36 per common share). The increase
was primarily due to higher North America crude oil and NGLs and natural gas
sales volumes, higher realized pricing, and lower realized risk management
losses. These factors were partially offset by higher production expense,
higher interest costs, higher current taxes, and the impact of the
strengthening of the Canadian dollar relative to the US dollar.
For 2007, the Company's average sales price per bbl of crude oil and NGLs
increased to $55.45 per bbl from $53.65 per bbl in 2006 (2005 - $46.86 per
bbl). The Company's average natural gas price increased to $6.85 per mcf from
$6.72 per mcf for 2006 (2005 - $8.57 per mcf).
Total production of crude oil and NGLs before royalties decreased marginally to
331,232 bbl/d from 331,998 bbl/d for 2006 (2005 - 313,168 bbl/d). The decrease
in crude oil and NGLs production primarily reflected lower production in the
North Sea due to the timing of planned maintenance activities and lower
production from the Baobab Field in Offshore West Africa, offset by increased
production in North America including increased production from the Company's
Primrose thermal projects, the results from the Pelican Lake waterflood
project, and the acquisition of ACC in 2006.
Total natural gas production before royalties increased to 1,668 mmcf/d from
1,492 mmcf/d for 2006 (2005 - 1,439 mmcf/d). The increase in natural gas
production primarily reflected additional natural gas production from the ACC
acquisition. The increase was partially offset by the production declines in
2007 due to the Company's strategic reduction in natural gas drilling activity.
Total crude oil and NGLs and natural gas production volumes before royalties
increased to 609,206 boe/d from 580,724 boe/d for 2006 (2005 - 552,960 boe/d).
OPERATING HIGHLIGHTS
2007 2006 2005
================================================================================
CRUDE OIL AND NGLS ($/BBL) (1)
Sales price (2) $ 55.45 $ 53.65 $ 46.86
Royalties 5.94 4.48 3.97
Production expense 13.34 12.29 11.17
-------------------------------------------------------------------------------
Netback $ 36.17 $ 36.88 $ 31.72
-------------------------------------------------------------------------------
NATURAL GAS ($/MCF) (1)
Sales price (2) $ 6.85 $ 6.72 $ 8.57
Royalties 1.11 1.29 1.75
Production expense 0.91 0.82 0.73
-------------------------------------------------------------------------------
Netback $ 4.83 $ 4.61 $ 6.09
-------------------------------------------------------------------------------
BARRELS OF OIL EQUIVALENT ($/BOE) (1)
Sales price (2) $ 49.05 $ 47.92 $ 48.77
Royalties 6.26 5.89 6.82
Production expense 9.75 9.14 8.21
-------------------------------------------------------------------------------
Netback $ 33.04 $ 32.89 $ 33.74
===============================================================================
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
(2) NET OF TRANSPORTATION AND BLENDING COSTS AND EXCLUDING RISK MANAGEMENT
ACTIVITIES.
7
SUMMARY OF QUARTERLY RESULTS
The following is a summary of the Company's quarterly results for the eight
most recently completed quarters:
($ millions, except per common share amounts)
2007 TOTAL DEC 31 SEP 30 JUN 30 MAR 31
=========================================================================================
Revenue, before royalties $12,543 $ 3,200 $ 3,073 $ 3,152 $ 3,118
Net earnings $ 2,608 $ 798 $ 700 $ 841 $ 269
Net earnings per common share
- basic and diluted $ 4.84 $ 1.48 $ 1.30 $ 1.56 $ 0.50
-----------------------------------------------------------------------------------------
2006 Total Dec 31 Sep 30 Jun 30 Mar 31
-----------------------------------------------------------------------------------------
Revenue, before royalties $11,643 $ 2,826 $ 3,108 $ 3,041 $ 2,668
Net earnings $ 2,524 $ 313 $ 1,116 $ 1,038 $ 57
Net earnings per common share
- basic and diluted $ 4.70 $ 0.58 $ 2.08 $ 1.93 $ 0.11
=========================================================================================
The Company's quarterly consolidated revenues increased 20% to $3,200 million
for the fourth quarter of 2007 from $2,668 million for the first quarter of
2006. Net earnings fluctuated from $57 million for the first quarter of 2006 to
$798 million for the fourth quarter of 2007. Net earnings over the eight most
recently completed quarters generally reflected fluctuations in realized crude
oil and natural gas prices, fluctuations in sales volumes, the impact of
mark-to-market accounting of financial instruments, higher depletion,
depreciation and amortization charges, and adjustments to future income tax
liabilities due to statutory tax rate and other legislative changes. More
specifically, volatility in quarterly net earnings was primarily due to:
o Crude oil pricing
Crude oil prices reflected demand growth, continued geopolitical
uncertainties and fluctuations in the Heavy Differential in North America.
The Company's realized crude oil and NGLs price increased to $58.03 per
bbl for the fourth quarter of 2007 from $43.79 per bbl for the first
quarter of 2006. The Heavy Differential averaged 38% for the fourth
quarter of 2007 compared to 45% for the first quarter of 2006.
o Natural gas pricing
Natural gas prices primarily reflected fluctuations in demand for natural
gas and high inventory storage levels as a result of seasonality, milder
overall weather experienced during 2007 and 2006, and increased liquefied
natural gas imports into the US during the first half of 2007. The
Company's realized natural gas price decreased to $6.28 per mcf for the
fourth quarter of 2007 from $8.30 per mcf for the first quarter of 2006.
o Crude oil and NGLs sales volumes
Crude oil and NGLs sales volumes primarily reflected increased production
from the Company's Primrose thermal projects, the results from the Pelican
Lake water and polymer flood projects, development of West and East
Espoir, and additional sales volumes from the ACC acquisition completed in
the fourth quarter of 2006. Total crude oil and NGLs production increased
to 337,240 bbl/d for the fourth quarter of 2007 from 323,662 bbl/d for the
first quarter of 2006.
o Natural gas sales volumes
Natural gas sales volumes primarily reflected additional natural gas
volumes as a result of the ACC acquisition and internally generated
growth. The increases were partially offset by production declines due to
the Company's strategic reduction in natural gas drilling activity. Total
natural gas production increased to 1,589 mmcf/d for the fourth quarter of
2007 from 1,436 mmcf/d for the first quarter of 2006.
o Foreign exchange rates
A general strengthening of the Canadian dollar relative to the US dollar
has decreased the realized price the Company received for its crude oil
and natural gas sales, as sales prices are based predominately on US
dollar denominated benchmarks. Similarly, unrealized foreign exchange
gains and losses were recorded with respect to US dollar denominated debt
balances and the re-measurement of North Sea future income tax liabilities
denominated in UK pounds sterling to US dollars, offset by the impact of
cross currency swaps. The US / Canadian dollar average exchange rate
increased to US$1.0193 for the fourth quarter of 2007 from US$0.8660 for
the first quarter of 2006. The US dollar / UK pound sterling average
exchange rate increased to US$2.0451 for the fourth quarter of 2007 from
US$1.7532 for the first quarter of 2006.
8
o Risk management
Net earnings have fluctuated due to the recognition of realized and
unrealized gains and losses from the mark-to-market of the Company's risk
management activities.
o Changes in income tax expense
Income tax expense and recovery fluctuations include statutory tax rate
and other legislative changes enacted or substantively enacted in the
various periods. Income tax rate and other legislative changes reduced
future income tax liabilities by $864 million for 2007 and $395 million
for 2006.
o Stock-based compensation
Net earnings have fluctuated due to the recognition of realized and
unrealized expenses and recoveries from the mark-to-market of the
Company's stock-based compensation liability. Stock-based compensation
expense reflected fluctuations in the Company's share price over the eight
most recently completed quarters. The Company's share price increased 26%
to $72.58 per share at December 31, 2007 from $57.63 per share at December
31, 2005.
o Production expense
Production expense has fluctuated company wide primarily due to production
growth and industry-wide inflationary cost pressures in all segments.
o Depletion, depreciation and amortization
Depletion, depreciation and amortization expense has increased primarily
due to overall increases in finding and development costs associated with
crude oil and natural gas exploration, increased estimated future costs to
develop the Company's proved undeveloped reserves, and a higher depletion
base in North America related to the ACC acquisition, together with the
impact of higher sales volumes.
BUSINESS ENVIRONMENT
(Yearly average) 2007 2006 2005
=================================================================================================
WTI benchmark price (US$/bbl) $ 72.40 $ 66.25 $ 56.61
Dated Brent benchmark price (US$/bbl) $ 72.59 $ 65.18 $ 54.45
Differential to LLB blend (US$/bbl) $ 23.05 $ 21.69 $ 20.83
LLB blend differential from WTI (%) 32% 33% 37%
Condensate benchmark price (US$/bbl) $ 72.88 $ 66.24 $ 57.25
NYMEX benchmark price (US$/mmbtu) $ 6.92 $ 7.26 $ 8.56
AECO benchmark price (C$/GJ) $ 6.26 $ 6.62 $ 8.05
US / Canadian dollar average exchange rate $ 0.9304 $ 0.8818 $ 0.8253
US / Canadian dollar year end exchange rate $ 1.0120 $ 0.8581 $ 0.8577
=================================================================================================
COMMODITY PRICES
Substantially all of the Company's crude oil and natural gas production is sold
based directly or indirectly on US dollar benchmark pricing. Specifically,
crude oil is marketed based on WTI and Brent indices. Canadian natural gas
pricing is primarily based on NYMEX and AECO reference pricing. As pricing is
based on US dollar benchmarks, the price the Company ultimately receives in
Canadian dollars fluctuates with changes in the US / Canadian dollar exchange
rate. Accordingly, an increase in the value of the Canadian dollar in relation
to the US dollar results in decreased revenue from the sale of the Company's
production. Conversely a decrease in the value of the Canadian dollar in
relation to the US dollar results in increased revenue from the sale of the
Company's production. The average value of the Canadian dollar strengthened 6%
in 2007 compared to 2006.
Increases in WTI pricing in 2007 reflected continued strong demand for crude
oil and continued geopolitical events resulting in increased market uncertainty
and price volatility. In December 2007, WTI averaged US$91.74 per bbl, down 8%
from the record high of US$99.29 per bbl reached in November 2007. WTI averaged
US$72.40 per bbl for 2007, an increase of 9% compared to US$66.25 per bbl for
2006 (2005 - US$56.61 per bbl).
Brent averaged US$72.59 per bbl for 2007, an increase of 11% compared to
US$65.18 per bbl for 2006 (2005 - US$54.45 per bbl). Crude oil sales contracts
for the Company's North Sea and Offshore West Africa segments are typically
based on Brent pricing, which continued to benefit from strong European and
Asian demand in 2007.
9
The Company's realized crude oil price increased from 2006 as a result of the
increased WTI and Brent pricing and the narrower Heavy Differential, offset by
the impact of a strengthening Canadian dollar. The Heavy Differential averaged
32% for 2007, which was comparable to 33% for 2006 (2005 - 37%). Realized
prices continued to be adversely impacted by the stronger Canadian dollar.
The Company anticipates continued volatility in the crude oil pricing
benchmarks due to the unpredictable nature of geopolitical events and potential
unplanned refinery outages. The Heavy Differential is expected to continue to
reflect seasonal demand fluctuations and refinery cracking margins.
NYMEX natural gas prices averaged US$6.92 per mmbtu for 2007, a decrease of 5%
from US$7.26 per mmbtu for 2006 (2005 - US$8.56 per mmbtu). AECO natural gas
pricing for 2007 decreased 5% to average $6.26 per GJ from $6.62 per GJ in 2006
(2005 - $8.05 per GJ). Fluctuations in natural gas prices from 2006 were
primarily related to lower overall demand resulting from the milder weather,
reduced economic activity in the US, and higher liquefied natural gas imports
into the US during the first half of 2007. Natural gas inventory levels in
North America during 2007 continued to remain high due to stable annual
production levels in the US that more than offset production declines in Canada
from reduced drilling activity.
OPERATING, ROYALTY AND CAPITAL COSTS
Strong commodity prices in recent years have resulted in increased demand and
costs for oilfield services worldwide. This has led to inflationary operating
and capital cost pressures throughout the North America crude oil and natural
gas industry, particularly related to drilling activities and oil sands
developments. The strong commodity price environment has also impacted costs in
international basins, due in large part to the high demand for offshore
drilling rigs.
The crude oil and natural gas industry is also experiencing cost pressures
related to environmental regulations, both in North America and
internationally. In Canada, the Federal government has indicated its intent to
develop regulations that would be in effect in 2010 to address industrial GHG
emissions. The Federal Government has also outlined national and sectoral
reduction targets for several categories of air pollutants. In Alberta, GHG
regulations came into effect July 1, 2007, affecting facilities emitting more
than 100 kilotonnes of CO2 annually. In the UK, GHG regulations have been in
effect since 2005. The Company has strategies in place to ensure compliance
with any requirements currently in effect. The additional requirements of
enacted and proposed GHG legislation will add to the cost of executing projects
company wide. For additional details, refer to the "Greenhouse Gas and Other
Air Emissions" section of this MD&A.
In 2007, the Province of Alberta issued certain details of its proposed changes
to the Alberta crude oil and natural gas royalty regime, effective January 1,
2009. These proposed changes include:
o The implementation of a sliding scale for oil sands royalties 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; and
o New royalty formulas for conventional crude oil and natural gas that are
to operate on sliding scales ranging up to 50% determined by commodity
prices and well productivity.
The Company is currently awaiting finalization of the royalty implementation
regulations, however it expects that its 2009 and future Alberta royalty
payments will increase as a result of the proposed royalty changes and that its
level of activity in Alberta in aggregate will be reduced from what it
otherwise would have been in the absence of such royalty changes.
10
ANALYSIS OF CHANGES IN REVENUE, BEFORE ROYALTIES AND RISK MANAGEMENT ACTIVITIES
Changes CHANGES
due to DUE TO
($ millions) 2005 Volumes Prices Other 2006 VOLUMES PRICES OTHER 2007
============================================================================================================================
NORTH AMERICA
Crude Oil and
NGLs $ 4,317 $ 198 $ 747 $ - $ 5,262 $ 298 $ 287 $ - $ 5,847
Natural Gas 4,638 168 (1,002) - 3,804 452 46 - 4,302
----------------------------------------------------------------------------------------------------------------------------
8,955 366 (255) - 9,066 750 333 - 10,149
----------------------------------------------------------------------------------------------------------------------------
NORTH SEA
Crude oil and
NGLs 1,636 (168) 132 - 1,600 (107) 82 - 1,575
Natural gas 23 (4) (3) - 16 (2) 8 - 22
----------------------------------------------------------------------------------------------------------------------------
1,659 (172) 129 - 1,616 (109) 90 - 1,597
----------------------------------------------------------------------------------------------------------------------------
OFFSHORE WEST
AFRICA
Crude oil and
NGLs 476 344 111 - 931 (216) 36 - 751
Natural gas 9 12 (2) - 19 5 1 - 25
----------------------------------------------------------------------------------------------------------------------------
485 356 109 - 950 (211) 37 - 776
----------------------------------------------------------------------------------------------------------------------------
SUBTOTAL
Crude oil and
NGLs 6,429 374 990 - 7,793 (25) 405 - 8,173
Natural gas 4,670 176 (1,007) - 3,839 455 55 - 4,349
----------------------------------------------------------------------------------------------------------------------------
11,099 550 (17) - 11,632 430 460 - 12,522
MIDSTREAM 77 - - (5) 72 - - 2 74
INTERSEGMENT
ELIMINATIONS
AND OTHER (1) (46) - - (15) (61) - - 8 (53)
----------------------------------------------------------------------------------------------------------------------------
TOTAL $ 11,130 $ 550 $ (17) $ (20) $ 11,643 $ 430 $ 460 $ 10 $ 12,543
============================================================================================================================
(1) ELIMINATES PRIMARILY INTERNAL TRANSPORTATION AND ELECTRICITY CHARGES.
Revenue increased 8% to $12,543 million for 2007 from $11,643 million for 2006
(2005 - $11,130 million). The increase was primarily due to increased crude oil
and NGLs and natural gas sales volumes in North America and increased realized
crude oil and NGLs and natural gas prices company wide.
For 2007, 19% of the Company's crude oil and natural gas revenue was generated
outside of North America (2006 - 22%; 2005 - 19%). North Sea accounted for 13%
of crude oil and natural gas revenue for 2007 (2006 - 14%; 2005 - 15%), and
Offshore West Africa accounted for 6% of crude oil and natural gas revenue for
2007 (2006 - 8%; 2005 - 4%).
11
ANALYSIS OF PRODUCT PRICES
2007 2006 2005
======================================================================================================
CRUDE OIL AND NGLS ($/bbl) (1) (2)
North America $ 49.16 $ 46.52 $ 39.62
North Sea $ 74.99 $ 72.62 $ 66.57
Offshore West Africa $ 71.68 $ 67.99 $ 59.91
Company average $ 55.45 $ 53.65 $ 46.86
NATURAL GAS ($/mcf) (1) (2)
North America $ 6.87 $ 6.77 $ 8.65
North Sea $ 4.26 $ 2.66 $ 3.17
Offshore West Africa $ 5.68 $ 5.37 $ 5.91
Company average $ 6.85 $ 6.72 $ 8.57
COMPANY AVERAGE ($/boe) (1) (2) $ 49.05 $ 47.92 $ 48.77
PERCENTAGE OF GROSS REVENUE (2) (excluding midstream revenue)
Crude oil and NGLs 62% 64% 54%
Natural gas 38% 36% 46%
======================================================================================================
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
(2) NET OF TRANSPORTATION AND BLENDING COSTS AND EXCLUDING RISK MANAGEMENT
ACTIVITIES.
Realized crude oil and NGLs prices increased 3% to average $55.45 per bbl for
2007 from $53.65 per bbl for 2006 (2005 - $46.86 per bbl). The increase from
2006 was due to increased benchmark crude oil prices and a slightly narrower
Heavy Differential, largely offset by the impact of the stronger Canadian
dollar.
The Company's realized natural gas price increased 2% to average $6.85 per mcf
for 2007 from $6.72 per mcf for 2006 (2005 - $8.57 per mcf). Fluctuations in
natural gas prices from 2006 were primarily related to the impact of both
weather and storage levels.
NORTH AMERICA
North America realized crude oil prices increased 6% to average $49.16 per bbl
for 2007 from $46.52 per bbl for 2006 (2005 - $39.62 per bbl). The increase
from 2006 was due to increased benchmark crude oil prices and a slightly
narrower Heavy Differential, largely offset by the impact of the stronger
Canadian dollar.
In North America, the Company continues to focus on its crude oil marketing
strategy, including the development of a blending strategy that expands markets
within current pipeline infrastructure, supporting pipeline projects that will
provide capacity to transport crude oil to new markets, and working with
refiners to add incremental heavy crude oil conversion capacity. During 2007,
the Company contributed approximately 140,000 bbl/d of heavy crude oil blends
to the Western Canadian Select stream.
North America realized natural gas prices increased slightly to average $6.87
per mcf for 2007 from $6.77 per mcf for 2006 (2005 - $8.65 per mcf), primarily
related to the impact of weather and storage levels.
Comparisons of the prices received for the Company's North America production
by product type were as follows:
2007 2006 2005
=================================================================================================
Wellhead Price (1) (2)
Light / medium crude oil and NGLs (C$/bbl) $ 66.24 $ 63.09 $ 58.41
Pelican Lake crude oil (C$/bbl) $ 46.29 $ 45.02 $ 38.39
Primary heavy crude oil (C$/bbl) $ 43.77 $ 41.35 $ 33.53
Thermal heavy crude oil (C$/bbl) $ 43.49 $ 40.98 $ 32.29
Natural gas (C$/mcf) $ 6.87 $ 6.77 $ 8.65
=================================================================================================
(1) NET OF TRANSPORTATION AND BLENDING COSTS AND EXCLUDING RISK MANAGEMENT
ACTIVITIES.
(2) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES. NORTH
SEA
12
North Sea realized crude oil prices increased 3% to average $74.99 per bbl for
2007 from $72.62 per bbl for 2006 (2005 - $66.57 per bbl). Realized crude oil
prices in the North Sea during 2007 continued to benefit from the impact of
strong European and Asian demand, partially offset by the impact of the
stronger Canadian dollar.
OFFSHORE WEST AFRICA
Offshore West Africa realized crude oil prices increased 5% to average $71.68
per bbl for 2007 from $67.99 per bbl for 2006 (2005 - $59.91 per bbl). As all
revenue in Offshore West Africa is currently recognized on a liftings basis,
realized crude oil prices per barrel in any particular period are dependant on
the frequency and timing of liftings of each field, as well as the terms of the
related sales contracts. Realized crude oil prices in Offshore West Africa
during 2007 continued to benefit from the impact of strong European and Asian
demand, partially offset by the impact of the stronger Canadian dollar.
CRUDE OIL INVENTORY VOLUMES
The Company recognizes revenue on its crude oil production when title transfers
to the customer and delivery has taken place. The related crude oil inventory
volumes by segment, which have not been recognized in revenue, were as follows:
(bbl) 2007 2006 2005
============================================================================================
North America, related to pipeline fill 1,097,526 1,097,526 484,157
North Sea, related to timing of liftings 1,032,723 910,796 747,141
Offshore West Africa, related to timing of liftings 8,578 113,774 412,841
--------------------------------------------------------------------------------------------
2,138,827 2,122,096 1,644,139
============================================================================================
In 2007, net production of approximately 17,000 barrels of crude oil produced
in the Company's international operations was deferred and included in
inventory at December 31, 2007, reducing cash flow from operations by
approximately $9 million.
ANALYSIS OF DAILY PRODUCTION, BEFORE ROYALTIES
2007 2006 2005
============================================================================================
CRUDE OIL AND NGLS (bbl/d)
North America 246,779 235,253 221,669
North Sea 55,933 60,056 68,593
Offshore West Africa 28,520 36,689 22,906
--------------------------------------------------------------------------------------------
331,232 331,998 313,168
--------------------------------------------------------------------------------------------
NATURAL GAS (mmcf/d)
North America 1,643 1,468 1,416
North Sea 13 15 19
Offshore West Africa 12 9 4
--------------------------------------------------------------------------------------------
1,668 1,492 1,439
--------------------------------------------------------------------------------------------
TOTAL BARRELS OF OIL EQUIVALENT (boe/d) 609,206 580,724 552,960
--------------------------------------------------------------------------------------------
PRODUCT MIX
Light crude oil and NGLs 23% 26% 26%
Pelican Lake crude oil 6% 5% 4%
Primary heavy crude oil 15% 16% 17%
Thermal heavy crude oil 11% 11% 10%
Natural gas 45% 42% 43%
============================================================================================
13
DAILY PRODUCTION, NET OF ROYALTIES
2007 2006 2005
============================================================================================
CRUDE OIL AND NGLS (bbl/d)
North America 210,769 205,382 191,751
North Sea 55,825 59,940 68,487
Offshore West Africa 26,012 35,212 22,293
--------------------------------------------------------------------------------------------
292,606 300,534 282,531
--------------------------------------------------------------------------------------------
NATURAL GAS (mmcf/d)
North America 1,378 1,185 1,125
North Sea 13 15 18
Offshore West Africa 11 9 4
--------------------------------------------------------------------------------------------
1,402 1,209 1,147
--------------------------------------------------------------------------------------------
TOTAL BARRELS OF OIL EQUIVALENT (boe/d) 526,193 502,024 473,742
============================================================================================
Daily production and per barrel statistics are presented throughout this MD&A
on a "before royalty" or "gross" basis. Production on an "after royalty" or
"net" basis is also presented.
The Company's business approach is to maintain large project inventories and
production diversification among each of the commodities it produces; namely
natural gas, light/medium crude oil and NGLs, Pelican Lake crude oil, primary
heavy crude oil and thermal heavy crude oil.
Total production of crude oil and NGLs before royalties decreased marginally to
331,232 bbl/d for 2007 from 331,998 bbl/d for 2006 (2005 - 313,168 bbl/d). The
decrease in crude oil and NGLs production from 2006 primarily reflected lower
production in the North Sea due to the timing of planned maintenance activities
and reduced production from the Baobab Field in Offshore West Africa, offset by
increased production in North America. Crude oil and NGLs production for 2007
was within the Company's guidance.
Natural gas production continues to represent the Company's largest product
offering, accounting for 45% of the Company's total production. Total natural
gas production before royalties increased 12% to 1,668 mmcf/d for 2007 from
1,492 mmcf/d for 2006 (2005 - 1,439 mmcf/d). The increase in natural gas
production from 2006 primarily reflected additional natural gas production from
the ACC acquisition, partially offset by production declines due to the
Company's strategic reduction in natural gas drilling activity. Natural gas
production for 2007 was within the Company's guidance.
For 2008, annual production is forecasted to average between 316,000 and
366,000 bbl/d of crude oil and NGLs and between 1,429 and 1,513 mmcf/d of
natural gas.
NORTH AMERICA
North America crude oil and NGLs production for 2007 increased 5% to average
246,779 bbl/d from 235,253 bbl/d for 2006 (2005 - 221,669 bbl/d). The increase
in production from 2006 was primarily due to the results from the Pelican Lake
project, the cyclic nature of the Company's thermal production, and the ACC
acquisition.
North America natural gas production for 2007 increased 12% to average 1,643
mmcf/d from 1,468 mmcf/d for 2006 (2005 - 1,416 mmcf/d). The increase in
natural gas production from 2006 reflected the impact of the ACC acquisition,
partially offset by production declines in 2007 due to the Company's strategic
decision to reduce natural gas drilling activity.
NORTH SEA
North Sea crude oil production for 2007 was 55,933 bbl/d, a decrease of 7% from
60,056 bbl/d for 2006 (2005 - 68,593 bbl/d) due to the timing of planned
maintenance activities, lower than anticipated production from the Lyell Field
development and water injection problems experienced during the year at the
Ninian Field. The Ninian water injection issues were resolved in the fourth
quarter of 2007.
14
OFFSHORE WEST AFRICA
Offshore West Africa crude oil production for 2007 decreased 22% to 28,520
bbl/d from 36,689 bbl/d for 2006 (2005 - 22,906 bbl/d). Production decreased
from 2006 due to continued challenges with sand production at the Baobab Field
where 5 of 10 production wells remain shut in. The Company has secured a
deepwater rig, expected in mid-year 2008, that should enable the Company to
execute its plan to return certain of the shut-in wells to production over the
course of 2008 and 2009. At the Espoir Fields, production delivered in 2007 was
in line with expectations, reflecting the successful execution of the drilling
campaign at the West Espoir Field.
ROYALTIES
2007 2006 2005
======================================================================================
CRUDE OIL AND NGLS ($/bbl) (1)
North America $ 7.19 $ 5.86 $ 5.37
North Sea $ 0.14 $ 0.13 $ 0.10
Offshore West Africa $ 6.40 $ 2.81 $ 1.62
Company average $ 5.94 $ 4.48 $ 3.97
--------------------------------------------------------------------------------------
NATURAL GAS ($/mcf) (1)
North America $ 1.12 $ 1.31 $ 1.78
North Sea $ - $ - $ -
Offshore West Africa $ 0.51 $ 0.22 $ 0.16
Company average $ 1.11 $ 1.29 $ 1.75
--------------------------------------------------------------------------------------
COMPANY AVERAGE ($/boe) (1) $ 6.26 $ 5.89 $ 6.82
--------------------------------------------------------------------------------------
PERCENTAGE OF REVENUE (2)
Crude oil and NGLs 11% 8% 8%
Natural gas 16% 19% 20%
Boe 13% 12% 14%
======================================================================================
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
(2) NET OF TRANSPORTATION AND BLENDING COSTS AND EXCLUDING RISK MANAGEMENT
ACTIVITIES.
NORTH AMERICA
Crown royalties on a significant portion of North America crude oil and NGLs
production fall under the oil sands royalty regime and are calculated on a
project by project basis as a percentage of gross revenue less operating,
capital and abandonment costs ("net profit"). For 2008 and prior years,
royalties are calculated as 1% of gross revenues until the Company's capital
investments in the applicable project are fully recovered, at which time the
royalty increases to 25% of net profit. Effective January 1, 2009, proposed
changes to the Alberta royalty regime include the implementation of a sliding
scale for oil sands royalties 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.
Crude oil and NGLs royalties for 2007 continued to reflect strong realized
crude oil prices and the impact of the full recovery of the Company's capital
investments in the Primrose North and South Fields in 2006. Upon full recovery,
Crown royalty rates on the Primrose North and South Fields increased from 1% of
gross revenue to 25% of revenue less operating, capital and abandonment costs.
North America crude oil and NGLs royalties per bbl are anticipated to average
14% to 16% of gross revenue for 2008, comparable to 15% for 2007 (2006 - 13%;
2005 - 14%).
Natural gas royalties per mcf generally fluctuate with natural gas prices and
well productivity. Natural gas royalties per mcf decreased from 2006 primarily
due to decreased benchmark natural gas prices and the impact of certain other
adjustments. North America natural gas royalties per mcf are anticipated to
average 17% to 20% of gross revenue for 2008, an increase from 16% for 2007
(2006 - 19%; 2005 - 21%).
Effective January 1, 2009, proposed new royalty formulas for conventional crude
oil and natural gas are to operate on sliding scales ranging up to 50%
determined by commodity prices and well productivity.
NORTH SEA
North Sea government royalties on crude oil were eliminated effective January
1, 2003. The remaining royalty is a gross overriding royalty on the Ninian
Field.
15
OFFSHORE WEST AFRICA
Offshore West Africa production is governed by the terms of the various
Production Sharing Contracts ("PSCs"). Under the PSCs, revenues are divided
into cost recovery oil and profit oil. Cost recovery oil allows the Company to
recover its capital and production costs and the costs carried by the Company
on behalf of the Government State Oil Company. Profit oil is allocated to the
joint venture partners in accordance with their respective equity interests,
after a portion has been allocated to the Government. The Government's share of
profit oil attributable to the Company's equity interest is allocated between
royalty expense and current income tax expense in accordance with the PSCs. The
Company's capital investments in the Espoir Fields were fully recovered in
early 2007, increasing royalty rates and current income taxes in accordance
with the terms of the PSCs.
Royalty rates as a percentage of revenue averaged approximately 9% for 2007
compared to 4% for 2006 (2005 - 3%). The increase in royalty rates from 2006
was due to the Company's full recovery of its capital investment in the Espoir
Fields in 2007 and the resulting increase in profit oil on which the
Government's entitlement is based. Offshore West Africa royalty rates are
anticipated to average 12% to 17% of gross revenue for 2008.
PRODUCTION EXPENSE
2007 2006 2005
============================================================================================
CRUDE OIL AND NGLS ($/bbl) (1)
North America $ 12.26 $ 11.73 $ 10.49
North Sea $ 20.78 $ 17.57 $ 14.94
Offshore West Africa $ 8.32 $ 7.45 $ 6.50
Company average $ 13.34 $ 12.29 $ 11.17
--------------------------------------------------------------------------------------------
NATURAL GAS ($/mcf) (1)
North America $ 0.90 $ 0.81 $ 0.71
North Sea $ 2.17 $ 1.40 $ 2.44
Offshore West Africa $ 1.48 $ 1.19 $ 1.05
Company average $ 0.91 $ 0.82 $ 0.73
--------------------------------------------------------------------------------------------
COMPANY AVERAGE ($/boe) (1) $ 9.75 $ 9.14 $ 8.21
============================================================================================
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
NORTH AMERICA
North America crude oil and NGLs production expense for 2007 increased 5% to
$12.26 per bbl from $11.73 per bbl for 2006 (2005 - $10.49 per bbl). The
increase in production expense from 2006 was primarily due to increased
industry-wide cost pressures and a continuing upward trend in property taxes
and lease rentals. During the second half of 2007, costs decreased as a result
of the timing of primary steam cycles, lower cost of natural gas fuel for the
Company's thermal operations, and higher production volumes in both Pelican
Lake and Primrose production areas, where a large portion of costs are fixed in
nature.
North America natural gas production expense for 2007 increased 11% to $0.90
per mcf from $0.81 per mcf for 2006 (2005 - $0.71 per mcf). This increase was
primarily due to industry-wide cost pressures in 2006 and early 2007, a
continuing upward trend in property taxes and lease rentals, as well as the
Company's strategic reduction in natural gas drilling activity, decreasing
natural gas sales throughout 2007 and increasing production expense per mcf on
the fixed cost portion of production costs.
Production expense per boe for 2008 is anticipated to increase as a result of
an overall reduction in budgeted volumes for 2008, while fixed costs, such as
property taxes and lease rentals, continue to escalate.
NORTH SEA
North Sea crude oil production expense increased on a per barrel basis from
2006 due to planned maintenance shutdowns, varying production volumes on a
relatively fixed cost base, the timing of liftings from various fields, and the
impact of the stronger Canadian dollar.
17
OFFSHORE WEST AFRICA
Offshore West Africa crude oil production expense on a per barrel basis
increased from 2006 primarily due to the impact of continuing operating
challenges with sand production at the Baobab Field, resulting in decreased
production volumes on a relatively fixed operating cost base. Production
expense was positively impacted by the impact of the stronger Canadian dollar.
MIDSTREAM
($ millions) 2007 2006 2005
================================================================================
Revenue $ 74 $ 72 $ 77
Production expense 22 23 24
--------------------------------------------------------------------------------
Midstream cash flow 52 49 53
Depreciation 8 8 8
--------------------------------------------------------------------------------
Segment earnings before taxes $ 44 $ 41 $ 45
================================================================================
The Company's midstream assets consist of three crude oil pipeline systems and
a 50% working interest in an 84-megawatt cogeneration plant at Primrose.
Approximately 80% of the Company's heavy crude oil production is transported to
international mainline liquid pipelines via the 100% owned and operated ECHO
Pipeline, the 62% owned and operated Pelican Lake Pipeline and the 15% owned
Cold Lake Pipeline. The midstream pipeline assets allow the Company to control
the transport of its own production volumes as well as earn third party
revenue. This transportation control enhances the Company's ability to manage
the full range of costs associated with the development and marketing of its
heavier crude oil.
DEPLETION, DEPRECIATION AND AMORTIZATION (1)
($ millions, except per boe amounts) (2) 2007 2006 2005
================================================================================
North America $ 2,350 $ 1,897 $ 1,595
North Sea $ 340 $ 297 $ 306
Offshore West Africa $ 165 $ 189 $ 104
--------------------------------------------------------------------------------
Expense $ 2,855 $ 2,383 $ 2,005
$/boe $ 12.84 $ 11.27 $ 10.02
================================================================================
(1) DD&A EXCLUDES DEPRECIATION ON MIDSTREAM ASSETS.
(2) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
Depletion, Depreciation and Amortization ("DD&A") expense for 2007 increased
20% to $2,855 million from $2,383 million for 2006 (2005 - $2,005 million). The
increase in DD&A expense in total and on a boe basis in 2007 from 2006 was
primarily due to overall increases in finding and development costs associated
with crude oil and natural gas exploration, increased estimated future costs to
develop the Company's proved undeveloped reserves, and a higher depletion base
in North America related to the ACC acquisition, together with the impact of
higher sales volumes. The increase in DD&A expense in 2007 was partially offset
in the North Sea and Offshore West Africa by the impact of the stronger
Canadian dollar relative to the US dollar.
ASSET RETIREMENT OBLIGATION ACCRETION
($ millions, except per boe amounts) (1) 2007 2006 2005
================================================================================
North America $ 38 $ 35 $ 34
North Sea $ 30 $ 31 $ 34
Offshore West Africa $ 2 $ 2 $ 1
--------------------------------------------------------------------------------
Expense ($ millions) $ 70 $ 68 $ 69
$/boe $ 0.32 $ 0.32 $ 0.34
================================================================================
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
Asset retirement obligation accretion expense represents the increase in the
carrying amount of the asset retirement obligation due to the passage of time.
Accretion expense was comparable to 2006.
17
ADMINISTRATION EXPENSE
($ millions, except per boe amounts) (1) 2007 2006 2005
================================================================================
Net expense ($ millions) $ 208 $ 180 $ 151
$/boe $ 0.93 $ 0.85 $ 0.75
================================================================================
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
Net administration expense for 2007 increased in total and on a boe basis from
2006 primarily due to increased staffing and administrative costs and overall
inflationary cost pressures.
STOCK-BASED COMPENSATION
($ millions) 2007 2006 2005
================================================================================
Stock-based compensation expense $ 193 $ 139 $ 723
================================================================================
The Company's Stock Option Plan (the "Option Plan") provides current employees
(the "option holders") with the right to elect to receive common shares or a
direct cash payment in exchange for options surrendered. The design of the
Option Plan balances the need for a long-term compensation program to retain
employees with the benefits of reducing the impact of dilution on current
Shareholders and the reporting of the obligations associated with stock
options. Transparency of the cost of the Option Plan is increased since changes
in the intrinsic value of outstanding stock options are recognized each period.
The cash payment feature provides option holders with substantially the same
benefits and allows them to realize the value of their options through a
simplified administration process.
The Company recorded a $193 million ($134 million after-tax) stock-based
compensation expense during 2007 in connection with the 17% appreciation in the
Company's share price (December 31, 2007 - C$72.58; December 31, 2006 -
C$62.15; December 31, 2005 - C$57.63; December 31, 2004 - C$25.63). As required
by GAAP, the Company's outstanding stock options are valued based on the
difference between the exercise price of the stock options and the market price
of the Company's common shares, pursuant to a graded vesting schedule. The
liability is revalued at each reporting date to reflect changes in the market
price of the Company's common shares and the options exercised or surrendered
in the period, with the net change recognized in net earnings, or capitalized
during the construction period in the case of the Horizon Project. For the year
ended December 31, 2007, the Company capitalized $58 million in stock-based
compensation as part of the Horizon Project (2006 - $79 million; 2005 - $101
million). The stock-based compensation liability at December 31, 2007 reflected
the Company's potential cash liability should all the vested options be
surrendered for a cash payout at the market price on December 31, 2007. In
periods when substantial stock price changes occur, the Company is subject to
significant earnings volatility.
For the year ended December 31, 2007, the Company paid $375 million for stock
options surrendered for cash settlement (2006 - $264 million; 2005 - $227
million).
INTEREST EXPENSE
($ millions, except per boe amounts and interest rates) (1) 2007 2006 2005
==============================================================================================
Interest expense, gross $ 632 $ 336 $ 221
Less: capitalized interest, Horizon Project 356 196 72
----------------------------------------------------------------------------------------------
Interest expense, net $ 276 $ 140 $ 149
$/boe $ 1.24 $ 0.66 $ 0.74
Average effective interest rate 5.5% 5.7% 5.6%
==============================================================================================
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
Gross interest expense increased from 2006 primarily due to increased debt
levels associated with the ACC acquisition and the on-going financing of
Horizon Project capital expenditures.
The Company's average effective interest rate for 2007 reflected the impact of
the stronger Canadian dollar, offset by higher cost US dollar denominated debt
issued in March 2007 and the impact of higher short-term lending rates on the
Company's floating rate debt due to credit market uncertainty.
In 2008, upon commencement of operations of Phase 1 of the Horizon Project,
interest capitalization will cease on this Phase, increasing interest expense
accordingly.
18
RISK MANAGEMENT ACTIVITIES
The Company utilizes various derivative financial instruments to manage its
commodity price, foreign currency and interest rate exposures. These derivative
financial instruments are entered into solely for hedging purposes and are not
intended for trading or other speculative purposes.
Commencing January 1, 2007, the Company adopted new accounting standards issued
by the CICA relating to the accounting for and disclosure of financial
instruments and comprehensive income.
Adoption of these standards required the Company to record all of its
derivative financial instruments on the balance sheet at estimated fair value
as at January 1, 2007, including those designated as hedges. Designated hedges,
other than cross currency swaps, were previously not recognized on the balance
sheet but were disclosed in the notes to the financial statements. The
adjustment to recognize the designated hedges on the balance sheet was recorded
as an adjustment to the opening balance of retained earnings or accumulated
other comprehensive income, as appropriate.
With the exception of the foreign currency translation adjustment, these
standards were adopted prospectively; accordingly, comparative amounts for
prior periods have not been restated. The reclassification of the foreign
currency translation adjustment to other comprehensive income was applied
retroactively with prior period restatement.
The effects of adopting these standards on the opening balance sheet were as
follows:
($ millions) JANUARY 1, 2007
======================================================================================
Increased current portion of other long-term assets (1) $ 193
Decreased other long-term assets (2) $ (16)
Decreased long-term debt (3) $ (72)
Increased retained earnings (4) $ 10
Increased foreign currency translation adjustment (5) $ 13
Increased accumulated other comprehensive income (6) $ 146
Decreased current portion of future income tax asset (7) $ (62)
Increased future income tax liability (7) $ 18
======================================================================================
(1) RELATES TO THE RECOGNITION OF THE CURRENT PORTION OF THE FAIR VALUE OF
DERIVATIVE FINANCIAL INSTRUMENTS DESIGNATED AS CASH FLOW HEDGES.
(2) RELATES TO THE RECOGNITION OF THE LONG-TERM PORTION OF THE FAIR VALUE OF
DERIVATIVE FINANCIAL INSTRUMENTS DESIGNATED AS CASH FLOW AND FAIR VALUE
HEDGES, AS WELL AS THE RECLASSIFICATION OF TRANSACTION COSTS AND ORIGINAL
ISSUE DISCOUNTS FROM DEFERRED CHARGES TO LONG-TERM DEBT.
(3) RELATES TO THE FAIR VALUE IMPACT OF DERIVATIVE FINANCIAL INSTRUMENTS
DESIGNATED AS FAIR VALUE HEDGES, AS WELL AS THE RECLASSIFICATION OF
TRANSACTION COSTS AND ORIGINAL ISSUE DISCOUNTS.
(4) RELATES TO THE IMPACT ON ADOPTION OF THE MEASUREMENT OF INEFFECTIVENESS ON
DERIVATIVE FINANCIAL INSTRUMENTS DESIGNATED AS CASH FLOW HEDGES.
(5) RELATES TO THE RETROACTIVE RESTATEMENT OF FOREIGN CURRENCY TRANSLATION
ADJUSTMENT TO ACCUMULATED OTHER COMPREHENSIVE INCOME.
(6) RELATES TO THE RECOGNITION OF ACCUMULATED OTHER COMPREHENSIVE INCOME
ARISING FROM THE MEASUREMENT OF EFFECTIVENESS ON DERIVATIVE FINANCIAL
INSTRUMENTS DESIGNATED AS CASH FLOW HEDGES.
(7) RELATES TO THE FUTURE INCOME TAX IMPACTS OF THE ABOVE NOTED ADJUSTMENTS.
Effective January 1, 2007, all derivative financial instruments are recognized
at estimated fair value on the consolidated balance sheet at each balance sheet
date. The estimated fair value of derivative financial instruments has been
determined based on appropriate internal valuation methodologies and/or third
party indications. However, these estimates may not necessarily be indicative
of the amounts that could be realized or settled in a current market
transaction and these differences may be material.
The Company formally documents all derivative financial instruments that are
designated as hedging transactions at the inception of the hedging
relationship, in accordance with the Company's risk management policies. The
effectiveness of the hedging relationship is evaluated, both at inception of
the hedge and on an ongoing basis.
The Company periodically enters into commodity price contracts to manage
anticipated sales of crude oil and natural gas production in order to protect
cash flow for capital expenditure programs. The effective portion of changes in
the fair value of derivative commodity price contracts designated as cash flow
hedges is initially recognized in other comprehensive income and is
reclassified to risk management activities in consolidated net earnings in the
same period or periods in which the crude oil or natural gas is sold. The
ineffective portion of changes in the fair value of these designated contracts
19
is immediately recognized in risk management activities in consolidated net
earnings. All changes in the fair value of non-designated crude oil and natural
gas commodity price contracts are recognized in risk management activities in
consolidated net earnings.
The Company enters into interest rate swap contracts to manage its fixed to
floating interest rate mix on certain of its long-term debt. The interest rate
swap contracts require the periodic exchange of payments without the exchange
of the notional principal amounts on which the payments are based. Changes in
the fair value of interest rate swap contracts designated as fair value hedges
and corresponding changes in the fair value of the hedged long-term debt are
included in interest expense in consolidated net earnings. Changes in the fair
value of non-designated interest rate swap contracts are included in risk
management activities in consolidated net earnings.
Cross currency swap contracts are periodically used to manage currency exposure
on US dollar denominated long-term debt. The cross currency swap contracts
require the periodic exchange of payments with the exchange at maturity of
notional principal amounts on which the payments are based. Changes in the fair
value of the foreign exchange component of cross currency swap contracts
designated as cash flow hedges are included in foreign exchange in consolidated
net earnings. The effective portion of changes in the fair value of the
interest rate component of cross currency swap contracts designated as cash
flow hedges is initially included in other comprehensive income and is
reclassified to interest expense when realized, with the ineffective portion
immediately recognized in risk management activities in consolidated net
earnings. Changes in the fair value of non-designated cross currency swap
contracts are included in risk management activities in consolidated net
earnings.
Gains or losses on the termination of financial instruments that have been
designated as cash flow hedges are deferred under accumulated other
comprehensive income on the consolidated balance sheets and amortized into
consolidated net earnings in the period in which the underlying hedged item is
recognized. In the event a designated hedged item is sold, extinguished or
matures prior to the termination of the related derivative instrument, any
unrealized derivative gain or loss is recognized immediately in consolidated
net earnings. Gains or losses on the termination of financial instruments that
have not been designated as hedges are recognized in consolidated net earnings
immediately.
Embedded derivatives are derivatives that are included in a non-derivative host
contract. Embedded derivatives are recorded at fair value separately from the
host contract when their economic characteristics and risks are not clearly and
closely related to the host contract.
Transaction costs that are directly attributable to the acquisition or issue of
a financial asset or financial liability and original issue discounts on
long-term debt have been included in the carrying value of the related
financial asset or liability and are amortized to consolidated net earnings
over the life of the financial instrument using the effective interest method.
RISK MANAGEMENT ACTIVITIES
($ millions) 2007 2006 2005
===========================================================================================
REALIZED LOSS (GAIN)
Crude oil and NGLs financial instruments $ 505 $ 1,395 $ 753
Natural gas financial instruments (343) (70) 283
Interest rate swaps - - (9)
-------------------------------------------------------------------------------------------
$ 162 $ 1,325 $ 1,027
-------------------------------------------------------------------------------------------
UNREALIZED LOSS (GAIN)
Crude oil and NGLs financial instruments $ 1,244 $ (736) $ 847
Natural gas financial instruments 156 (260) 77
Interest rate and cross-currency swaps - (17) 1
-------------------------------------------------------------------------------------------
$ 1,400 $ (1,013) $ 925
-------------------------------------------------------------------------------------------
TOTAL $ 1,562 $ 312 $ 1,952
===========================================================================================
The realized losses (gains) from crude oil and NGLs and natural gas financial
instruments would have decreased (increased) the Company's average realized
prices as follows:
2007 2006 2005
-------------------------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1) $ 4.18 $ 11.57 $ 6.68
Natural gas ($/mcf) (1) $ (0.56) $ (0.13) $ 0.54
===========================================================================================
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
20
Complete details related to outstanding derivative financial instruments at
December 31, 2007 are disclosed in note 12 to the Company's consolidated
financial statements. As at December 31, 2006, the net unrecognized asset
related to the estimated fair values of derivative financial instruments
designated as hedges was $222 million (December 31, 2005 - net unrecognized
liability of $990 million).
As effective as the Company's hedges are against reference commodity prices, a
substantial portion of the commodity derivative financial instruments entered
into by the Company have not been formally designated as hedges for accounting
purposes or do not meet the requirements for hedge accounting under GAAP due to
currency, product quality and location differentials (the "non-designated
hedges"). The change in the fair value of the non-designated hedges is based on
prevailing forward commodity prices in effect at the end of each reporting
period and is reflected in risk management activities in consolidated net
earnings. The cash settlement amount of the risk management derivative
financial instruments may vary materially depending upon the underlying crude
oil and natural gas prices at the time of final settlement of the derivative
financial instruments, as compared to their mark-to-market value at December
31, 2007. Due to changes in the crude oil and natural gas forward pricing, and
the reversal of prior period unrealized gains and losses, the Company recorded
a net unrealized loss of $1,400 million ($977 million after-tax) on its
commodity risk management activities for the year ended December 31, 2007 (2006
- $1,013 million unrealized gain, $674 million after-tax; 2005 - $925 million
unrealized loss, $607 million after-tax).
FOREIGN EXCHANGE
($ millions) 2007 2006 2005
================================================================================
Realized foreign exchange loss (gain) $ 53 $ (12) $ (29)
Unrealized foreign exchange (gain) loss (524) 134 (103)
--------------------------------------------------------------------------------
Total $ (471) $ 122 $ (132)
================================================================================
The Company's North Sea operations are classified as self-sustaining for the
purposes of foreign currency translation. The North Sea operations are
initially measured in US dollars and then translated to Canadian dollars using
the current rate method, whereby assets and liabilities are translated into
Canadian dollars using the exchange rate in effect at the balance sheet date,
while revenue and expenses are translated into Canadian dollars using the
monthly average exchange rate. Foreign currency gains or losses arising on the
translation of non-US dollar monetary assets and liabilities are included in
net earnings while subsequent gains or losses arising on translation to
Canadian dollars are deferred and included in accumulated other comprehensive
income.
The Company's Offshore West Africa foreign operations are classified as
integrated for the purposes of foreign currency translation. Offshore West
Africa foreign operations and foreign currency transactions and balances held
in North America are directly translated into Canadian dollars using the
temporal method, whereby monetary assets and liabilities are translated to
Canadian dollars at the exchange rate in effect at the consolidated balance
sheet date. Non-monetary assets and liabilities are translated at the exchange
rate in effect when the assets were acquired or obligations incurred. Revenue
and expenses are translated to Canadian dollars at the monthly average exchange
rates. All related foreign exchange gains or losses are included in net
earnings.
As a result of foreign currency translation, the Company's operating results
are affected by the fluctuations in the exchange rates between the Canadian
dollar, US dollar, and UK pound sterling. A majority of the Company's revenue
is based on reference to US dollar benchmark prices. An increase in the value
of the Canadian dollar in relation to the US dollar results in decreased
revenue from the sale of the Company's production. Conversely a decrease in the
value of the Canadian dollar in relation to the US dollar results in increased
revenue from the sale of the Company's production. Production expenses in the
North Sea are subject to foreign currency fluctuations due to changes in the
exchange rate of the UK pound sterling to the US dollar, while production
expenses in Offshore West Africa are subject to foreign currency fluctuations
due to changes in the exchange rate of the Canadian dollar to the US dollar.
The value of the Company's US dollar denominated debt is also impacted by the
value of the Canadian dollar in relation to the US dollar.
The net unrealized foreign exchange gain in 2007 was primarily related to the
strengthening of the Canadian dollar in relation to the US dollar with respect
to the US dollar debt, partially offset by an unrealized loss of $350 million
related to the impact of the cross currency swaps. The net realized foreign
exchange loss for 2007 was primarily due to the result of foreign exchange rate
fluctuations on settlement of working capital items denominated in US dollars
or UK pounds sterling. The Canadian dollar ended the year above parity, at
US$1.0120 compared to US$0.8581 at December 31, 2006 (December 31, 2005 -
US$0.8577).
During 2007, the Company de-designated the portion of the US dollar denominated
debt previously hedged against its net investment in US dollar based
self-sustaining foreign operations. Accordingly, all foreign exchange (gains)
losses arising each period on US dollar denominated long-term debt are now
recognized in the consolidated statement of earnings.
21
TAXES
($ millions, except income tax rates) 2007 2006 2005
======================================================================================================
TAXES OTHER THAN INCOME TAX
Current $ 121 $ 219 $ 203
Deferred 44 37 (9)
------------------------------------------------------------------------------------------------------
$ 165 $ 256 $ 194
------------------------------------------------------------------------------------------------------
CURRENT INCOME TAX
North America $ 96 $ 143 $ 99
North Sea 210 30 155
Offshore West Africa 74 49 32
------------------------------------------------------------------------------------------------------
380 222 286
FUTURE INCOME TAX (456) 652 353
------------------------------------------------------------------------------------------------------
(76) 874 639
Income tax and other legislative changes (1) (2) (3) 864 395 19
------------------------------------------------------------------------------------------------------
$ 788 $ 1,269 $ 658
------------------------------------------------------------------------------------------------------
EFFECTIVE INCOME TAX RATE BEFORE INCOME TAX RATE AND OTHER
LEGISLATIVE CHANGES 31.1% 37.3% 39.0%
======================================================================================================
(1) INCLUDES THE EFFECT OF ONE TIME RECOVERIES OF $864 MILLION DUE TO CANADIAN
FEDERAL INCOME TAX RATE REDUCTIONS AND OTHER LEGISLATIVE CHANGES ENACTED
OR SUBSTANTIVELY ENACTED DURING 2007.
(2) INCLUDES THE EFFECT OF THE FOLLOWING:
o A ONE TIME EXPENSE OF $110 MILLION RELATED TO THE INCREASED
SUPPLEMENTARY CHARGE ON OIL AND GAS PROFITS IN THE UK NORTH SEA,
ENACTED IN 2006.
o A ONE TIME RECOVERY OF $438 MILLION DUE TO CANADIAN FEDERAL, ALBERTA
AND SASKATCHEWAN CORPORATE INCOME TAX RATE REDUCTIONS ENACTED IN 2006.
o A ONE TIME RECOVERY OF $67 MILLION DUE TO OFFSHORE WEST AFRICA
CORPORATE INCOME TAX RATE REDUCTIONS ENACTED IN 2006.
(3) INCLUDES THE EFFECT OF A ONE TIME RECOVERY OF $19 MILLION DUE TO A BRITISH
COLUMBIA CORPORATE INCOME TAX RATE REDUCTION ENACTED IN 2005.
Taxes other than income tax primarily includes current and deferred petroleum
revenue tax ("PRT"). PRT is charged on certain fields in the North Sea at the
rate of 50% of net operating income, after allowing for certain deductions
including abandonment expenditures.
Taxable income from the conventional crude oil and natural gas business in
Canada is primarily generated through partnerships, with the related income
taxes payable in a future period. North America current income taxes have been
provided on the basis of the corporate structure and available income tax
deductions and will vary depending upon the nature, timing and amount of
capital expenditures incurred in Canada in any particular year. In particular,
current taxes in a specific year are sensitive to the timing of when the
Horizon Project capital expenditures are deductible for Canadian income tax
purposes.
During 2007, the Canadian Federal Government enacted or substantively enacted
income tax rate and other legislative changes, resulting in a reduction of
future income tax liabilities of approximately $864 million. As a result of the
enacted income tax rate changes, the federal corporate income tax rate will be
reduced over the next five years from 21% in 2007 to 15% in 2012.
During 2006, enacted income tax rate changes resulted in a reduction of future
income tax liabilities of approximately $438 million in North America, an
increase of future income tax liabilities of approximately $110 million in the
UK North Sea and a reduction of future income tax liabilities of approximately
$67 million in Cote d'Ivoire.
During 2005, enacted income tax rate changes in North America resulted in a
reduction of future income tax liabilities of approximately $19 million.
During 2003, the Canadian Federal Government enacted legislation to change the
taxation of resource income. The legislation reduced the corporate income tax
rate on resource income from 28% to 21% over five years beginning January 1,
2003. Over the same period, the deduction for resource allowance was phased out
and a deduction for actual crown royalties paid was phased in. As a result, in
2007 crown royalties were fully deductible and the Company is no longer
eligible for the resource allowance.
22
The Company's consolidated effective income tax rate for 2007 was reduced
primarily due to income tax rate reductions enacted in Canada during the year,
the effects of the non-taxable portion of unrealized foreign exchange gains on
US dollar debt, net of unrealized losses on cross currency swaps, and
adjustments to future tax expense in Canada related to the final phase-in of
deductibility of crown royalties and the elimination of the resource allowance
deduction in 2007. For 2008, based on budgeted prices and the current
availability of tax pools, the Company expects to be cash taxable in Canada in
the amount of $75 million to $150 million.
NET CAPITAL EXPENDITURES (1)
($ millions) 2007 2006 2005
============================================================================================
EXPENDITURES ON PROPERTY, PLANT AND EQUIPMENT
Net property (dispositions) acquisitions (2) $ (39) $ 4,733 $ (320)
Land acquisition and retention 95 210 254
Seismic evaluations 124 130 132
Well drilling, completion and equipping 1,642 2,340 2,000
Production and related facilities 1,205 1,314 1,295
--------------------------------------------------------------------------------------------
TOTAL NET RESERVE REPLACEMENT EXPENDITURES 3,027 8,727 3,361
--------------------------------------------------------------------------------------------
Horizon Project:
Phase 1 construction costs 2,740 2,768 1,249
Phases 2/3 costs 124 79 -
Capitalized interest, stock-based compensation and
other 437 338 250
--------------------------------------------------------------------------------------------
Total Horizon Project 3,301 3,185 1,499
--------------------------------------------------------------------------------------------
Midstream 6 12 4
Abandonments (3) 71 75 46
Head office 20 26 22
--------------------------------------------------------------------------------------------
TOTAL NET CAPITAL EXPENDITURES $ 6,425 $ 12,025 $ 4,932
--------------------------------------------------------------------------------------------
BY SEGMENT
North America $ 2,428 $ 7,936 $ 2,530
North Sea 439 646 387
Offshore West Africa 159 134 439
Other 1 11 5
Horizon Project 3,301 3,185 1,499
Midstream 6 12 4
Abandonments (3) 71 75 46
Head office 20 26 22
--------------------------------------------------------------------------------------------
Total $ 6,425 $ 12,025 $ 4,932
============================================================================================
(1) NET CAPITAL EXPENDITURES EXCLUDE ADJUSTMENTS RELATED TO DIFFERENCES
BETWEEN CARRYING VALUE AND TAX VALUE.
(2) INCLUDES BUSINESS COMBINATIONS.
(3) ABANDONMENTS REPRESENT EXPENDITURES TO SETTLE ARO AND HAVE BEEN REFLECTED
AS CAPITAL EXPENDITURES IN THIS TABLE.
23
The Company's strategy is focused on building a diversified asset base that is
balanced among various products. In order to facilitate efficient operations,
the Company concentrates its activities in core regions where it can dominate
the land base and infrastructure. The Company focuses on maintaining its land
inventories to enable the continuous exploitation of play types and geological
trends, reducing overall exploration risk. By dominating infrastructure, the
Company is able to maximize utilization of its production facilities, thereby
increasing control over production costs.
Net capital expenditures for 2007 were $6,425 million compared to $12,025
million for 2006 (2005 - $4,932 million). Excluding the ACC acquisition, net
capital expenditures were $7,270 million for 2006. Capital expenditures in 2007
reflected the continued progress on the Company's larger, future growth
projects, most notably the Horizon Project, as well as continued industry-wide
inflationary pressures, offset by the effects of an overall strategic reduction
in the North America natural gas drilling program.
During 2007, the Company drilled a total of 1,322 net wells consisting of 383
natural gas wells, 592 crude oil wells, 254 stratigraphic test and service
wells, and 93 wells that were dry. This compared to 1,738 net wells drilled for
2006 (2005 - 1,882 net wells). The Company achieved an overall success rate of
91% for 2007, excluding the stratigraphic test and service wells (2006 - 91%;
2005 - 93%).
NORTH AMERICA
North America, including the Horizon Project, accounted for approximately 91%
of the total capital expenditures for the year ended December 31, 2007 compared
to approximately 93% for 2006 (2005 - 83%).
During 2007, the Company targeted 450 net natural gas wells, including 58 wells
in Northeast British Columbia, 133 wells in the Northern Plains region, 110
wells in Northwest Alberta, and 149 wells in the Southern Plains region. The
Company also targeted 610 net crude oil wells during the year. The majority of
these wells were concentrated in the Company's crude oil Northern Plains region
where 362 primary heavy crude oil wells, 127 Pelican Lake crude oil wells, 55
thermal crude oil wells and 6 light crude oil wells were drilled. In addition,
60 wells targeting light crude oil were drilled outside the Northern Plains
region.
Due to significant changes in relative commodity prices between crude oil and
natural gas, the Company has continued to access its large crude oil drilling
inventory to maximize value in both the short and long term. As a result of the
Company's focus on drilling crude oil wells in 2007, natural gas drilling
activities were reduced to manage overall capital spending. Deferred natural
gas well locations have been retained in the Company's prospect inventory.
Drilling on ACC acquired lands was optimized as part of the overall capital
program.
In November of 2005, the Company announced a phased expansion of its In-Situ
Oil Sands Assets. As part of the development, the Company is continuing to
develop its Primrose thermal projects. During 2007, the Company drilled 135
stratigraphic test wells and observation wells, 2 water source wells and 55
thermal oil wells. Overall Primrose thermal production for 2007 was
approximately 64,000 bbl/d (2006 - 64,000 bbl/d).
The Primrose East Expansion, a new facility located 15 kilometers from the
existing Primrose South steam plant and 25 kilometers from the Wolf Lake
central processing facility, is anticipated to add approximately 40,000 bbl/d
when complete. The Primrose East Expansion received Board of Directors'
sanction in 2006 and the Alberta Energy and Utilities Board regulatory approval
in early 2007. Drilling and construction are currently underway, and production
is targeted to commence in 2009.
The next phase of the Company's In-Situ Oil Sands Assets expansion is the Kirby
project located 120 kilometers north of the existing Primrose facilities. The
Kirby project is anticipated to add an additional 45,000 bbl/d of production
growth. During 2007, the Company filed a combined application and Environmental
Impact Assessment for this project with Alberta Environment and the Alberta
Energy and Utilities Board. Final corporate sanction and project scope will be
impacted by environmental regulations and their associated costs.
Development of new pads and secondary recovery conversion projects at Pelican
Lake continued as expected throughout 2007. Drilling consisted of 125
horizontal crude oil wells, with plans to drill 105 additional horizontal crude
oil wells in 2008. The response from the water and polymer flood projects
continues to be positive. Pelican Lake production averaged approximately 34,000
bbl/d in 2007 (2006 - 30,000 bbl/d).
Due to growing concerns relating to increased environmental costs for upgraders
located in Canada, inflationary capital cost pressures and narrowing heavy oil
differentials in North America, the Company has, at this point in time,
deferred the Design Basis memorandum and Engineering Design Specification of
24
the Canadian Natural Upgrader, outside of the Horizon Project, pending
clarification on the cost of future environmental legislation and a more stable
cost environment.
For 2008, the Company's overall drilling activity in North America is expected
to comprise approximately 314 natural gas wells and 526 crude oil wells,
excluding stratigraphic and service wells.
HORIZON PROJECT
The Horizon Project is designed as a phased development and includes two
components: the mining of bitumen and an onsite upgrader. Phase 1 production is
targeted to commence in the third quarter of 2008 ramping up to 110,000 bbl/d
of 34(degree) API SCO.
Work progress on the Horizon Project was 90% complete at year end. The project
status as at December 31, 2007 was as follows:
o Overall detailed engineering 98.5% complete and substantially complete in
most areas;
o Overall procurement 99% complete with over $5.6 billion in purchase orders
and contracts awarded;
o Commenced receipt and site assembly of Mine Operations equipment (Shovels
and Heavy Haul Trucks);
o Overall construction progress 85% complete;
o Mine overburden removal approximately 72% complete and 0.6 million bank
cubic meters ahead of schedule;
o Main Control Room Distributed Control Systems equipment powered and
tested;
o Commissioned 260kV Transmission Line and turned over to operations;
o Commissioned Raw Water Pumphouse and turned over to operations;
o Completed reformer erection in Hydrogen Plant;
o Completed installation and pre-commissioning of CPI Separator Building;
o Completed the closure of Dyke 10 (external tailings pond) in Mining;
o Completed erection of Crushing Plants and conveyors in Ore Preparation
Area;
o Completed Primary Separation Cells in Extraction; and
o Completed construction of Main Laboratory.
The Company has budgeted construction costs of approximately $1.7 billion to
$1.9 billion for 2008 related to the planned completion of Phase 1 of the
Horizon Project.
NORTH SEA
In 2007, the Company continued with its planned program of infill drilling,
recompletions, workovers and waterflood optimizations, and the execution of its
long-term facilities strategy. During 2007, 7.2 net wells were drilled,
including 3.5 net water injectors, with an additional 1.6 net wells drilling at
year end.
Commissioning of the Columba E Raw Water Injection project was successfully
completed on time and on budget during 2007 and 2 water injection wells were
delivered, allowing water injection into the reservoir to commence. Injection
rates delivered were below expectation due to lower reservoir quality. A
detailed technical evaluation has been carried out and is being executed to
deliver required injection rates under sustained fracture conditions.
During 2007, the subsea project to bring gas lift to the Kyle Field was
successfully completed, delivering above expectation production at the Banff /
Kyle hub.
The development of the Lyell Field continued during the year with 2 production
wells coming on stream through the existing infrastructure. Production from
these initial Lyell wells was below expectation and future development plans
are being re-evaluated as a result. The Company remains committed to unlocking
the remaining development potential at the Lyell Field with a phased approach.
At the Ninian Field, the Company continued to execute its long-term facilities
strategy, with investment in the Ninian South platform infrastructure in
particular. In addition, infill locations were successfully developed, with
production delivery from these wells in line with expectations, and water
injection capacity was successfully increased.
25
In December 2007, the Company completed the sale of its working interest in the
B-Block, comprising the Balmoral, Stirling, and Glamis Fields.
OFFSHORE WEST AFRICA
During 2007, 4.7 net wells were drilled with 0.6 wells drilling at year end.
Development drilling on West Espoir continued during 2007 with 5 additional
production wells and 2 additional injector wells added. West Espoir development
drilling was completed in early 2008, on budget and on time.
During 2007, the Company awarded a contract for the upgrade of the Espoir FPSO
in order to increase the throughput handling capability of the vessel. Design
and procurement work commenced during the year. Production volumes will not be
significantly impacted during the installation work, scheduled to complete in
late 2009. Gross fluids processing capacity will increase from 50,000 bbl/d to
70,000 bbl/d, with natural gas handling capacity increasing from 55 mmcf/d to
75 mmcf/d upon completion of the project.
At the 90% owned and operated Olowi Field in offshore Gabon, all major
construction contracts have been awarded, and construction of the wellhead
towers and the FPSO is ongoing. The project is on schedule with drilling
targeted to commence in the second quarter of 2008 and first crude oil targeted
in late 2008. Olowi production is targeted to plateau at approximately 20,000
bbl/d, net to the Company.
LIQUIDITY AND CAPITAL RESOURCES
($ millions, except ratios) 2007 2006 2005
=======================================================================================================
Working capital deficit (1) $ 1,382 $ 832 $ 1,774
Long-term debt (2) $ 10,940 $ 11,043 $ 3,321
-------------------------------------------------------------------------------------------------------
Shareholders' equity
Share capital $ 2,674 $ 2,562 $ 2,442
Retained earnings 10,575 8,141 5,804
Accumulated other comprehensive income (loss) 72 (13) (9)
-------------------------------------------------------------------------------------------------------
Total $ 13,321 $ 10,690 $ 8,237
-------------------------------------------------------------------------------------------------------
Debt to book capitalization (2) (3) 45% 51% 29%
Debt to market capitalization (2) (4) 22% 25% 10%
After tax return on average common shareholders'
equity (5) 22% 27% 14%
After tax return on average capital employed (2) (6) 12% 17% 10%
=======================================================================================================
(1) CALCULATED AS CURRENT ASSETS LESS CURRENT LIABILITIES.
(2) LONG-TERM DEBT AT DECEMBER 31, 2007 IS STATED AT ITS CARRYING VALUE, NET
OF FAIR VALUE ADJUSTMENTS, ORIGINAL ISSUE DISCOUNTS AND TRANSACTION COSTS.
AMOUNTS FOR PERIODS PRIOR TO JANUARY 1, 2007 WERE NOT ADJUSTED FOR THESE
ITEMS.
(3) CALCULATED AS LONG-TERM DEBT; DIVIDED BY THE BOOK VALUE OF COMMON
SHAREHOLDERS' EQUITY PLUS LONG-TERM DEBT.
(4) CALCULATED AS LONG-TERM DEBT; DIVIDED BY THE MARKET VALUE OF COMMON
SHAREHOLDERS' EQUITY PLUS LONG-TERM DEBT.
(5) CALCULATED AS NET EARNINGS FOR THE YEAR; AS A PERCENTAGE OF AVERAGE COMMON
SHAREHOLDERS' EQUITY FOR THE YEAR.
(6) CALCULATED AS NET EARNINGS PLUS AFTER-TAX INTEREST EXPENSE FOR THE YEAR;
AS A PERCENTAGE OF AVERAGE CAPITAL EMPLOYED. AVERAGE CAPITAL EMPLOYED IS
THE AVERAGE SHAREHOLDERS' EQUITY AND LONG-TERM DEBT FOR THE YEAR,
INCLUDING $7,001 MILLION IN AVERAGE CAPITAL EMPLOYED RELATED TO THE
HORIZON PROJECT (2006 - $3,760 MILLION; 2005 - $1,421 MILLION).
The Company's capital resources at December 31, 2007 consisted primarily of
cash flow from operations, available credit facilities and access to debt
capital markets. Cash flow from operations is dependent on factors discussed in
the Risks and Uncertainties section of this MD&A. The Company's ability to
renew existing credit facilities and raise new debt is also dependent upon
these factors, as well as maintaining an investment grade debt rating and the
condition of capital and credit markets. Management believes internally
generated cash flows supported by the implementation of the Company's hedge
policy, the flexibility of its capital expenditure programs supported by its
multi-year financial plans, the Company's existing credit facilities and the
Company's ability to raise new debt on commercially acceptable terms, will be
sufficient to sustain its operations and support its growth strategy. The
Company's current debt ratings are BBB (high) with a negative trend by DBRS
Limited, Baa2 with a stable outlook by Moody's Investors Service and BBB with a
stable outlook by Standard & Poor's. The Company does not have any direct
exposure to asset-backed commercial paper.
26
At December 31, 2007, the Company had undrawn bank lines of credit of $1,442
million. Details related to the Company's long-term debt at December 31, 2007
are disclosed in note 5 to the Company's audited annual consolidated financial
statements. Subsequent to December 31, 2007, the Company issued an aggregate
US$1,200 million of unsecured notes. Proceeds from the securities issued were
used to repay bankers' acceptances under the Company's bank credit facilities.
At December 31, 2007, the Company's working capital deficit was $1,382 million
and included the current portion of the stock-based compensation liability of
$390 million and the current portion of the net mark-to-market liability for
risk management derivative financial instruments of $1,227 million. The
settlement of the stock-based compensation liability is dependant upon both the
surrender of vested stock options for cash settlement by employees and the
value of the Company's share price at the time of surrender. The cash
settlement amount of the risk management derivative financial instruments may
vary materially depending upon the underlying crude oil and natural gas prices
at the time of final settlement of the derivative financial instruments, as
compared to their mark-to-market value at December 31, 2007.
The Company believes it has the necessary financial capacity to complete the
Horizon Project, while at the same time not compromising conventional crude oil
and natural gas growth opportunities. The financing of Phase 1 of the Horizon
Project development is guided by the competing principles of retaining as much
direct ownership interest as possible while maintaining a strong balance sheet.
Long-term debt was $10,940 million at December 31, 2007, resulting in a debt to
book capitalization level of 45% as at December 31, 2007 (December 31, 2006 -
51%). While this ratio is at the high end of the 35% to 45% range targeted by
management, the Company remains committed to maintaining a strong balance sheet
and flexible capital structure, and expects its debt to book capitalization
ratio to be near the midpoint of the range in late 2008. While the Company
believes that it has the balance sheet strength and flexibility to complete
Phase 1 of the Horizon Project, as well as its other planned capital
expenditure programs, the Company has hedged a significant portion of its crude
oil and natural gas production for 2008 at prices that protect investment
returns. In the future, the Company may also consider the divestiture of
certain non-strategic and non-core properties to gain additional balance sheet
flexibility.
The Company's commodity hedging program reduces the risk of volatility in
commodity price markets and supports the Company's cash flow for its capital
expenditures throughout the Horizon Project construction period. This program
allows for the hedging of up to 75% of the near 12 months budgeted production,
up to 50% of the following 13 to 24 months estimated production and up to 25%
of production expected in months 25 to 48. For the purpose of this program, the
purchase of crude oil put options is in addition to the above parameters. In
accordance with the policy, approximately 65% of expected crude oil volumes are
hedged for 2008 and approximately 53% of expected natural gas volumes are
hedged for the first quarter of 2008. Subsequent to December 31, 2007, the
Company hedged 25,000 bbl/d of crude oil volumes for 2009 using WTI collars
with a US$70.00 floor.
27
The Company has the following commodity related net financial derivatives
outstanding as at December 31, 2007:
REMAINING TERM VOLUME WEIGHTED AVERAGE PRICE INDEX
=====================================================================================================================
CRUDE OIL
Crude oil price collars (1) Jan 2008 - Mar 2008 50,000 bbl/d US$60.00 - US$80.06 WTI
Jan 2008 - Jun 2008 25,000 bbl/d US$60.00 - US$80.44 WTI
Apr 2008 - Sep 2008 25,000 bbl/d US$60.00 - US$80.46 WTI
Jul 2008 - Sep 2008 25,000 bbl/d US$70.00 - US$123.75 WTI
Oct 2008 - Dec 2008 25,000 bbl/d US$70.00 - US$112.63 WTI
Jan 2008 - Dec 2008 20,000 bbl/d US$50.00 - US$65.53 Mayan Heavy
Jan 2008 - Dec 2008 50,000 bbl/d US$60.00 - US$75.22 WTI
Jan 2008 - Dec 2008 50,000 bbl/d US$60.00 - US$76.05 WTI
Jan 2008 - Dec 2008 50,000 bbl/d US$60.00 - US$76.98 WTI
Crude oil puts Jan 2008 - Dec 2008 50,000 bbl/d US$55.00 WTI
NATURAL GAS
AECO price collars Jan 2008 - Mar 2008 400,000 GJ/d C$7.00 - C$14.08 AECO
Jan 2008 - Mar 2008 500,000 GJ/d C$7.50 - C$10.81 AECO
=====================================================================================================================
(1) SUBSEQUENT TO DECEMBER 31, 2007, THE COMPANY ENTERED INTO 25,000 BBL/D OF
US$70.00 - US$111.56 WTI COLLARS FOR THE PERIOD JANUARY TO DECEMBER 2009.
The Company's outstanding commodity financial derivatives are expected to be
settled monthly based on the applicable index pricing for the respective
contract month.
LONG-TERM DEBT
The Company's long-term debt of $10,940 million at December 31, 2007 was
comprised of drawings under its bank credit facilities and debt issuances under
medium and long-term unsecured notes.
BANK CREDIT FACILITIES
As at December 31, 2007, the Company had in place unsecured bank credit
facilities of $6,209 million, comprised of:
o a $100 million demand credit facility;
o a non-revolving syndicated credit facility of $2,350 million maturing
October 2009;
o a revolving syndicated credit facility of $2,230 million maturing June
2012;
o a revolving syndicated credit facility of $1,500 million maturing June
2012; and
o a (pound)15 million demand credit facility related to the Company's North
Sea operations.
During 2007, one of the revolving syndicated credit facilities was increased
from $1,825 million to $2,230 million and a $500 million demand credit facility
was terminated. The revolving syndicated credit facilities were also extended
and now mature June 2012. Both facilities are extendible annually for one year
periods at the mutual agreement of the Company and the lenders. If the
facilities are not extended, the full amount of the outstanding principal would
be repayable on the maturity date.
In conjunction with the closing of the acquisition of ACC in November 2006, the
Company executed a $3,850 million, non-revolving syndicated credit facility
maturing in October 2009. In March 2007, $1,500 million was repaid, reducing
the facility to $2,350 million.
In addition to the outstanding debt, letters of credit and financial guarantees
aggregating $345 million, including $300 million related to the Horizon
Project, were outstanding at December 31, 2007.
MEDIUM-TERM NOTES
In December 2007, the Company issued $400 million of unsecured notes maturing
December 2010, bearing interest at 5.50%. Proceeds from the securities issued
were used to repay bankers' acceptances under the Company's bank credit
facilities. After issuing these securities, the Company has $2,600 million
remaining on its outstanding $3,000 million base shelf prospectus filed in
September 2007 that allows for the issue of medium-term notes in Canada until
October 2009. If issued, these securities will bear interest as determined at
the date of issuance.
During 2007, $125 million of the 7.40% unsecured debentures due March 1, 2007
were repaid.
28
In 2006, the Company issued $400 million of debt securities maturing January
2013, bearing interest at 4.50%. Proceeds from the securities issued were used
to repay bankers' acceptances under the Company's bank credit facilities.
SENIOR UNSECURED NOTES
The adjustable rate senior unsecured notes bear interest at 6.54%, with annual
principal repayments of US$31 million due in May 2008 and May 2009. During
2007, US$31 million of the senior unsecured notes were repaid.
US DOLLAR DEBT SECURITIES
In March 2007, the Company issued US$2,200 million of unsecured notes,
comprised of US$1,100 million of unsecured notes maturing May 2017 and US$1,100
million of unsecured notes maturing March 2038, bearing interest at 5.70% and
6.25%, respectively. Concurrently, the Company entered into cross currency
swaps to fix the Canadian dollar interest and principal repayment amounts on
the entire US$1,100 million of unsecured notes due May 2017 at 5.10% and
C$1,287 million. The Company also entered into a cross currency swap to fix the
Canadian dollar interest and principal repayment amounts on US$550 million of
unsecured notes due March 2038 at 5.76% and C$644 million. Proceeds from the
securities issued were used to repay bankers' acceptances under the Company's
bank credit facilities.
During 2007, the Company de-designated the portion of its US dollar denominated
debt previously hedged against its net investment in US dollar based
self-sustaining foreign operations. Accordingly, all foreign exchange (gains)
losses arising each period on US dollar denominated long-term debt are now
recognized in the consolidated statement of earnings.
In 2006, the Company issued US$250 million of unsecured notes maturing August
2016 and US$450 million of unsecured notes maturing February 2037, bearing
interest at 6.00% and 6.50%, respectively. Concurrently, the Company entered
into cross currency swaps to fix the Canadian dollar interest and principal
repayment amounts on the US$250 million notes at 5.40% and C$279 million.
Proceeds from the securities issued were used to repay bankers' acceptances
under the Company's bank credit facilities.
In September 2007, the Company filed a base shelf prospectus that allows for
the issue of up to US$3,000 million of debt securities in the United States
until October 2009.
Subsequent to December 31, 2007, the Company issued US$1,200 million of
unsecured notes under this US base shelf prospectus, comprised of US$400
million of 5.15% unsecured notes due February 2013, US$400 million of 5.90%
unsecured notes due February 2018, and US$400 million of 6.75% unsecured notes
due February 2039. Proceeds from the securities issued were used to repay
bankers' acceptances under the Company's bank credit facilities. After issuing
these securities, the Company has US$1,800 million remaining on its outstanding
US$3,000 million base shelf prospectus. If issued, these securities will bear
interest as determined at the date of issuance.
SHARE CAPITAL
As at December 31, 2007, there were 539,729,000 common shares outstanding and
30,659,000 stock options outstanding. As at February 26, 2008, the Company had
540,252,000 common shares outstanding and 29,173,000 stock options outstanding.
During 2007, the Company did not purchase any common shares for cancellation
pursuant to the Normal Course Issuer Bid previously filed for the 12-month
period beginning January 24, 2007 and ending January 23, 2008 (2006 - 485,000
common shares were purchased at an average price of $57.33 per common share for
a total cost of $28 million; 2005 - 850,000 common shares were purchased at an
average price of $53.29 per common share for a total cost of $45 million). The
Company has decided not to renew the Normal Course Issuer Bid until subsequent
to the completion of Phase 1 of the Horizon Project.
In February 2008, the Company's Board of Directors approved an increase in the
annual dividend paid by the Company to $0.40 per common share for 2008. The
increase represents an 18% increase from the prior year, recognizes the
stability of the Company's cash flow, and provides a return to Shareholders.
This is the eighth consecutive year in which the Company has paid dividends and
the seventh consecutive year of an increase in the distribution paid to its
Shareholders. The dividend policy undergoes a periodic review by the Board of
Directors and is subject to change. In March 2007, an increase in the annual
dividend paid by the Company was approved to $0.34 per common share for 2007.
The increase represented a 13% increase from 2006.
29
COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS
In the normal course of business, the Company has entered into various
commitments that will have an impact on the Company's future operations. These
commitments primarily relate to debt repayments; operating leases relating to
offshore FPSOs, drilling rigs and office space; and firm commitments for
gathering, processing and transmission services; as well as expenditures
relating to ARO. As at December 31, 2007, no entities were consolidated under
CICA Handbook Accounting Guideline 15, "Consolidation of Variable Interest
Entities". The following table summarizes the Company's commitments as at
December 31, 2007:
($ millions) 2008 2009 2010 2011 2012 Thereafter
===============================================================================================================
Product transportation and pipeline $ 232 $ 151 $ 137 $ 109 $ 91 $ 972
Offshore equipment operating lease (1) $ 114 $ 129 $ 113 $ 111 $ 90 $ 387
Offshore drilling (2) (3) $ 267 $ 185 $ 39 $ - $ - $ -
Asset retirement obligations (4) $ 33 $ 4 $ 5 $ 4 $ 4 $ 4,376
Long-term debt (5) $ 39 $ 2,361 $ 400 $ 395 $ 346 $ 5,098
Interest expense (6) $ 612 $ 590 $ 487 $ 465 $ 374 $ 4,338
Office lease $ 26 $ 28 $ 28 $ 22 $ 3 $ -
Electricity and other $ 166 $ 173 $ 25 $ 4 $ - $ -
===============================================================================================================
(1) OFFSHORE EQUIPMENT OPERATING LEASES ARE PRIMARILY COMPRISED OF OBLIGATIONS
RELATED TO FPSOS. DURING 2006, THE COMPANY ENTERED INTO AN AGREEMENT TO
LEASE AN ADDITIONAL FPSO COMMENCING IN 2008, IN CONNECTION WITH THE
PLANNED OFFSHORE DEVELOPMENT IN GABON, OFFSHORE WEST AFRICA. DURING THE
INITIAL TERM, THE TOTAL ANNUAL PAYMENTS FOR THE GABON FPSO ARE ESTIMATED
TO BE US$50 MILLION.
(2) DURING 2007, THE COMPANY ENTERED INTO A ONE-YEAR AGREEMENT FOR OFFSHORE
DRILLING SERVICES RELATED TO THE BAOBAB FIELD IN COTE D'IVOIRE, OFFSHORE
WEST AFRICA. THE AGREEMENT IS SCHEDULED TO COMMENCE IN 2008, SUBJECT TO
RIG AVAILABILITY. ESTIMATED TOTAL PAYMENTS OF US$100 MILLION, AFTER JOINT
VENTURE RECOVERIES, HAVE BEEN INCLUDED IN THIS TABLE FOR THE PERIOD 2008 -
2009.
(3) DURING 2007, THE COMPANY AWARDED CONTRACTS FOR A DRILLING RIG AND FOR THE
CONSTRUCTION OF WELLHEAD TOWERS IN CONNECTION WITH THE PLANNED OFFSHORE
DEVELOPMENT IN GABON, OFFSHORE WEST AFRICA. ESTIMATED TOTAL PAYMENTS OF
US$393 MILLION HAVE BEEN INCLUDED IN THIS TABLE FOR THE PERIOD 2008 -
2010.
(4) AMOUNTS REPRESENT MANAGEMENT'S ESTIMATE OF THE FUTURE UNDISCOUNTED
PAYMENTS TO SETTLE ARO RELATED TO RESOURCE PROPERTIES, FACILITIES, AND
PRODUCTION PLATFORMS, BASED ON CURRENT LEGISLATION AND INDUSTRY OPERATING
PRACTICES. AMOUNTS DISCLOSED FOR THE PERIOD 2008 - 2012 REPRESENT THE
MINIMUM REQUIRED EXPENDITURES TO MEET THESE OBLIGATIONS. ACTUAL
EXPENDITURES IN ANY PARTICULAR YEAR MAY EXCEED THESE MINIMUM AMOUNTS.
(5) THE LONG-TERM DEBT REPRESENTS PRINCIPAL REPAYMENTS ONLY AND DOES NOT
REFLECT FAIR VALUE ADJUSTMENTS, ORIGINAL ISSUE DISCOUNTS OR TRANSACTION
COSTS. NO DEBT REPAYMENTS ARE REFLECTED FOR $2,366 MILLION OF REVOLVING
BANK CREDIT FACILITIES DUE TO THE EXTENDABLE NATURE OF THE FACILITIES.
(6) INTEREST EXPENSE AMOUNTS REPRESENT THE SCHEDULED FIXED-RATE AND
VARIABLE-RATE CASH PAYMENTS RELATED TO LONG-TERM DEBT. INTEREST ON
VARIABLE-RATE LONG-TERM DEBT WAS ESTIMATED BASED UPON PREVAILING INTEREST
RATES AS OF DECEMBER 31, 2007.
In addition to the amounts disclosed above, the Company has budgeted
construction costs of approximately $1.7 billion to $1.9 billion for 2008
related to the planned completion of Phase 1 of the Horizon Project.
LEGAL PROCEEDINGS
The Company is defendant and plaintiff in a number of legal actions that arise
in the normal course of business. In addition, the Company is subject to
certain contractor construction claims related to the Horizon Project. The
Company believes that any liabilities that might arise pertaining to any such
matters would not have a material effect on its consolidated financial
position.
30
RESERVES
For the year ended December 31, 2007, the Company retained qualified
independent reserve evaluators, Sproule Associates Limited ("Sproule") and
Ryder Scott Company ("Ryder Scott") to evaluate 100% of the Company's
conventional proved, as well as proved and probable crude oil, NGLs and natural
gas reserves(1) (3) and prepare Evaluation Reports on these reserves. Sproule
evaluated the Company's North America conventional assets and Ryder Scott
evaluated the international conventional assets. The Company has been granted
an exemption from National Instrument 51-101 - "Standards of Disclosure for Oil
and Gas Activities" ("NI 51-101"), which prescribes the standards for the
preparation and disclosure of reserves and related information for companies
listed in Canada. This exemption allows the Company to substitute SEC
requirements for certain disclosures required under NI 51-101. There are three
principal differences between the two standards. The first is the requirement
under NI 51-101 to disclose both proved and proved and probable reserves, as
well as the related net present value of future net revenues using forecast
prices and costs. The second is in the definition of proved reserves; however,
as discussed in the Canadian Oil and Gas Evaluation Handbook ("COGEH"), the
standards that NI 51-101 employs, the difference in estimated proved reserves
based on constant pricing and costs between the two standards is not material.
The third is the requirement to disclose a gross reserve reconciliation (before
the consideration of royalties). The Company discloses its reserve
reconciliation net of royalties in adherence to SEC requirements.
The Company annually discloses proved conventional reserves and the
Standardized Measure of discounted future net cash flows using year end
constant prices and costs as mandated by the SEC in the supplementary oil and
gas information section of its Annual Report. The Company has elected to
provide the net present value(2) of these same conventional proved reserves as
well as its conventional proved and probable reserves and the net present value
of these reserves under the same parameters as additional voluntary
information. The Company has also elected to provide both proved and proved and
probable conventional reserves and the net present value of these reserves
using forecast prices and costs as voluntary additional information, which is
disclosed in the Company's Annual Information Form.
For the year ended December 31, 2007, the Company retained a qualified
independent reserves evaluator, GLJ Petroleum Consultants ("GLJ"), to evaluate
100% of Phases 1 through 3 of the Company's Horizon Project and prepare an
Evaluation Report on the Company's proved, as well as proved and probable oil
sands mining reserves incorporating both the mining and upgrading projects.
These reserves were evaluated adhering to the requirements of SEC Industry
Guide 7 using year end constant pricing and have been disclosed separately from
the Company's conventional proved and proved and probable crude oil, NGL and
natural gas reserves.
The Reserves Committee of the Company's Board of Directors has met with and
carried out independent due diligence procedures with each of Sproule, Ryder
Scott and GLJ to review the qualifications of and procedures used by each
evaluator in determining the estimate of the Company's quantities and net
present value of remaining conventional crude oil, NGLs and natural gas
reserves as well as the Company's quantity of oil sands mining reserves.
Additional reserves disclosure is annually disclosed in the supplementary oil
and gas information of the Company's Annual Report.
(1) CONVENTIONAL CRUDE OIL, NGLS AND NATURAL GAS INCLUDES ALL OF THE COMPANY'S
LIGHT/MEDIUM, PRIMARY HEAVY, AND THERMAL CRUDE OIL, NATURAL GAS, COAL BED
METHANE AND NGLS ACTIVITIES. IT DOES NOT INCLUDE THE COMPANY'S OIL SANDS
MINING ASSETS.
(2) NET PRESENT VALUES OF CONVENTIONAL RESERVES ARE BASED UPON DISCOUNTED CASH
FLOWS PRIOR TO THE CONSIDERATION OF INCOME TAXES AND EXISTING ASSET
ABANDONMENT LIABILITIES. ONLY FUTURE DEVELOPMENT COSTS AND ASSOCIATED
MATERIAL WELL ABANDONMENT LIABILITIES HAVE BEEN APPLIED.
(3) CONVENTIONAL CRUDE OIL, NGLS, AND NATURAL GAS RESERVES, NET OF ROYALTIES,
ARE ESTIMATED USING ROYALTY REGULATIONS IN EFFECT AS OF DECEMBER 31, 2007.
SIMILARLY, BITUMEN AND SYNTHETIC CRUDE OIL RESERVES, NET OF ROYALTIES,
RELATING TO SURFACE MINEABLE OIL SAND PROJECTS ARE ESTIMATED USING ROYALTY
REGULATIONS IN EFFECT AS OF DECEMBER 31, 2007. ROYALTY CHANGES PROPOSED BY
THE GOVERNMENT OF ALBERTA WILL BE INCORPORATED IN THE RESERVES EVALUATION
SHOULD THEY BE ENACTED.
31
RISKS AND UNCERTAINTIES
The Company is exposed to various operational risks inherent in exploring,
developing, producing and marketing crude oil and natural gas and the mining
and upgrading of bitumen into synthetic crude oil. These inherent risks
include, but are not limited to, the following items:
o Economic risk of finding, producing and replacing reserves at a reasonable
cost, including the risk of reserve revisions due to economic and technical
factors. Reserve revisions can have a positive or negative impact on asset
valuations, ARO and depletion rates;
o Prevailing prices of crude oil and natural gas;
o Regulatory risk related to approval for exploration and development
activities, which can add to costs or cause delays in projects;
o Labour risk associated with securing the manpower necessary to complete
capital projects in a timely and cost effective manner;
o Operating hazards and other difficulties inherent in the exploration for
and production and sale of crude oil and natural gas;
o Success of exploration and development activities;
o Timing and success of integrating the business and operations of acquired
companies;
o Credit risk related to non-payment for sales contracts or non-performance
by counterparties to contracts;
o Interest rate risk associated with the Company's ability to secure
financing on commercially acceptable terms;
o Foreign exchange risk due to fluctuating exchange rates on the Company's US
dollar denominated debt and as the majority of sales are based in US
dollars;
o Environmental impact risk associated with exploration and development
activities, including GHG;
o Risk of catastrophic loss due to fire, explosion or acts of nature;
o Geopolitical risks associated with changing governmental policies, social
instability and other political, economic or diplomatic developments in the
Company's operations; and
o Other circumstances affecting revenue and expenses.
The Company uses a variety of means to help mitigate and/or minimize these
risks. The Company maintains a comprehensive insurance program to reduce risk
to an acceptable level and to protect it against significant losses.
Operational control is enhanced by focusing efforts on large core areas with
high working interests and by assuming operatorship of key facilities. Product
mix is diversified, consisting of the production of natural gas and the
production of crude oil of various grades. The Company believes this
diversification reduces price risk when compared with over-leverage to one
commodity. Accounts receivable from the sale of crude oil and natural gas are
mainly with customers in the crude oil and natural gas industry and are subject
to normal industry credit risks. The Company reviews its exposure to individual
companies on a regular basis and where appropriate, ensures that parental
guarantees or letters of credit are in place to minimize the impact in the
event of default. Derivative financial instruments are utilized to help ensure
targets are met and to manage commodity prices, foreign currency rates and
interest rate exposure. The Company minimizes credit risk by entering into
financial derivatives with entities which are substantially all investment
grade. The arrangements and policies concerning the Company's financial
instruments are under constant review and may change depending upon the
prevailing market conditions.
The Company's capital structure mix is also monitored on a continual basis to
ensure that it optimizes flexibility, minimizes cost and offers the greatest
opportunity for growth. This includes the determination of a reasonable level
of debt and any interest rate exposure risk that may exist.
For additional detail regarding the Company's risks and uncertainties, refer to
the Company's Annual Information Form.
ENVIRONMENT
The crude oil and natural gas industry is experiencing incremental increases in
costs related to environmental regulation, particularly in North America and
the North Sea. Existing and expected legislation and regulations will require
the Company to address and mitigate the effect of its activities on the
environment. Increasingly stringent laws and regulations may have an adverse
effect on the Company's future net earnings and cash flow from operations.
The Company's associated risk management strategies focus on working with
legislators and regulators to ensure that any new or revised policies,
legislation or regulations properly reflect a balanced approach to sustainable
development. Specific measures in response to existing or new legislation
include a focus on the Company's energy efficiency, air emissions management,
released water quality, reduced fresh water use and the minimization of the
impact on the landscape. The Company's strategy employs an Environmental
Management Plan (the "Plan"). Details of the Plan and the results are presented
to, and reviewed by, the Board of Directors quarterly.
32
The Company's Plan and operating guidelines focus on minimizing the impact of
operations while meeting regulatory requirements, regional management
frameworks, industry operating standards and guidelines, and internal corporate
standards. The Company, as part of this Plan, has implemented a proactive
program that includes:
o An internal environmental compliance audit and inspection program of the
Company's operating facilities;
o A suspended well inspection program to support future development or
eventual abandonment;
o Appropriate reclamation and decommissioning standards for wells and
facilities ready for abandonment;
o An effective surface reclamation program;
o A due diligence program related to groundwater monitoring;
o An active program related to preventing and reclaiming spill sites;
o A solution gas reduction and conservation program;
o A program to replace the majority of fresh water for steaming with brackish
water;
o Environmental planning for all projects to assess impacts and to implement
avoidance, and mitigation programs;
o Reporting for environmental liabilities;
o A program to optimize efficiencies at the Company's operating facilities;
and
o Continued evaluation of new technologies to reduce environmental impacts.
The Company has also established stringent operating standards in four areas:
o Using water-based, environmentally friendly drilling muds whenever
possible;
o Implementing cost effective ways of reducing GHG emissions per unit of
production;
o Exercising care with respect to all waste produced through effective waste
management plans; and
o Minimizing produced water volumes onshore and offshore through
cost-effective measures.
For 2007, the Company's capital expenditures included $71 million for
abandonment expenditures (2006 - $75 million; 2005 - $46 million).
The Company's estimated undiscounted ARO at December 31, 2007 was as follows:
Estimated ARO, undiscounted ($ millions) 2007 2006
================================================================================
North America $ 3,038 $ 2,826
North Sea 1,286 1,543
Offshore West Africa 102 128
--------------------------------------------------------------------------------
4,426 4,497
North Sea PRT recovery (555) (625)
--------------------------------------------------------------------------------
$ 3,871 $ 3,872
================================================================================
The estimate of ARO is based on estimates of future costs to abandon and
restore the wells, production facilities and offshore production platforms.
Factors that affect costs include number of wells drilled, well depth and the
specific environmental legislation. The estimated costs are based on
engineering estimates using current costs in accordance with present
legislation and industry operating practice. The Company's strategy in the
North Sea consists of developing commercial hubs around its core operated
properties with the goal of increasing production, lowering costs and extending
the economic lives of its production facilities, thereby delaying the eventual
abandonment dates. The future abandonment costs incurred in the North Sea are
expected to result in an estimated PRT recovery of $555 million (2006 - $625
million; 2005 - $370 million), as abandonment costs are an allowable deduction
in determining PRT and may be carried back to reclaim PRT previously paid. The
expected PRT recovery reduces the Company's net undiscounted abandonment
liability to $3,871 million (2006 - $3,872 million).
GREENHOUSE GAS AND OTHER AIR EMISSIONS
The Company is concurrently working with legislators and regulators as they
develop and implement new GHG emission laws and regulations. Internally, the
Company is pursuing an integrated emissions reduction strategy, to ensure that
it is able to comply with existing and future emission reductions requirements.
The Company continues to develop strategies that will enable it to deal with
the risks and opportunities associated with new GHG and air emissions policies.
In addition, the Company is working with relevant parties to ensure that new
policies encourage innovation, energy efficiency, targeted research and
development while not impacting competitiveness.
In Canada, the Federal government has indicated its intent to develop
regulations that would be in effect in 2010 to address industrial GHG
emissions. The Federal Government has also outlined national and sectoral
reduction targets for several categories of air pollutants. In Alberta, GHG
regulations came into effect July 1, 2007, affecting facilities emitting more
33
than 100 kilotonnes of CO2e annually. In the UK, GHG regulations have been in
effect since 2005. The Company has strategies in place to ensure compliance
with any requirements currently in effect.
There are a number of unresolved issues in relation to Canadian Federal and
Provincial GHG regulatory requirements. Key among them is an appropriate
facility emission threshold, availability and duration of compliance
mechanisms, and resolution of federal/provincial harmonization agreements. The
Company continues to pursue GHG emission reduction initiatives including
solution gas conservation, CO2 capture and sequestration in oil sands tailings,
CO2 capture and storage in association with enhanced oil recovery, and
participation in an industry initiative to promote an integrated CO2 capture
and storage network.
The additional requirements of enacted or proposed GHG legislation on the
Company's operations will increase capital expenditures and operating expenses,
especially those related to the Horizon Project and the Company's other
existing and planned large oil sands projects. This may have an adverse effect
on the Company's net earnings and cash flow from operations.
Air pollutant standards and guidelines are being developed federally and
provincially and the Company is participating in these discussions. Ambient air
quality and sector based reductions in air emissions are being reviewed.
Through participation of the Company and the industry with stakeholders,
guidelines have been developed that adopt a structured process to emission
reductions that is commensurate with technological development and operational
requirements.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements requires the Company to make
judgements, assumptions and estimates in the application of GAAP that have a
significant impact on the financial results of the Company. Actual results
could differ from those estimates, and those differences could be material.
Critical accounting estimates are reviewed by the Company's Audit Committee
annually. The Company believes the following are the most critical accounting
estimates in preparing its consolidated financial statements.
PROPERTY, PLANT AND EQUIPMENT / DEPLETION, DEPRECIATION AND AMORTIZATION
The Company follows the full cost method of accounting for its conventional
crude oil and natural gas properties and equipment. Accordingly, all costs
relating to the exploration for and development of conventional crude oil and
natural gas reserves, whether successful or not, are capitalized and
accumulated in country-by-country cost centres. Proceeds on disposal of
properties are ordinarily deducted from such costs without recognition of a
gain or loss except where such dispositions result in a change in the depletion
rate of the specific cost centre of 20% or more. Under Canadian GAAP,
substantially all of the capitalized costs and future capital costs related to
each cost centre from which there is production are depleted on the
unit-of-production method based on the estimated proved reserves of that
country using estimated future prices and costs, rather than constant dollar
pricing as required by the SEC. The carrying amount of crude oil and natural
gas properties in each cost centre may not exceed their recoverable amount
("the ceiling test"). The recoverable amount is calculated as the undiscounted
cash flow using proved reserves and estimated future prices and costs. If the
carrying amount of a cost centre exceeds its recoverable amount, an impairment
loss equal to the amount by which the carrying amount of the properties exceeds
their estimated fair value is charged against net earnings. Fair value is
calculated as the cash flow from those properties using proved and probable
reserves and estimated future prices and costs, discounted at a risk-free
interest rate.
The alternate acceptable method of accounting for crude oil and natural gas
properties and equipment is the successful efforts method. A major difference
in applying the successful efforts method is that exploratory dry holes and
geological and geophysical exploration costs would be charged against net
earnings in the year incurred rather than being capitalized to property, plant
and equipment. In addition, under this method cost centres are defined based on
reserve pools rather than by country. The use of the full cost method usually
results in higher capitalized costs and increased DD&A rates compared to the
successful efforts method.
34
CRUDE OIL AND NATURAL GAS RESERVES
The Company retains qualified independent reserves evaluators to evaluate the
Company's proved, and proved and probable crude oil and natural gas reserves.
In 2007, 100% of the Company's reserves were evaluated by qualified independent
reserves evaluators.
The estimation of reserves involves the exercise of judgement. Forecasts are
based on engineering data, estimated future prices, expected future rates of
production and the timing of future capital expenditures, all of which are
subject to many uncertainties and interpretations. The Company expects that
over time its reserve estimates will be revised either upward or downward based
on updated information such as the results of future drilling, testing and
production levels. Reserve estimates can have a significant impact on net
earnings, as they are a key component in the calculation of depletion,
depreciation and amortization and for determining potential asset impairment.
For example, a revision to the proved reserve estimates would result in a
higher or lower DD&A charge to net earnings. Downward revisions to reserve
estimates could also result in a write-down of crude oil and natural gas
property, plant and equipment carrying amounts under the ceiling test.
ASSET RETIREMENT OBLIGATIONS
Under CICA Handbook Section 3110, "Asset Retirement Obligations", the Company
is required to recognize a liability for the future retirement obligations
associated with its property, plant and equipment. An ARO is recognized to the
extent of a legal obligation associated with the retirement of a tangible
long-lived asset the Company is required to settle as a result of an existing
or enacted law, statute, ordinance or written or oral contract, or by legal
construction of a contract under the doctrine of promissory estoppel. The ARO
is based on estimated costs, taking into account the anticipated method and
extent of restoration consistent with legal requirements, technological
advances and the possible use of the site. Since these estimates are specific
to the sites involved, there are many individual assumptions underlying the
Company's total ARO amount. These individual assumptions can be subject to
change.
The estimated fair values of ARO related to long-term assets are recognized as
a liability in the period in which they are incurred. Retirement costs equal to
the estimated fair value of the ARO are capitalized as part of the cost of
associated capital assets and are amortized to expense through depletion over
the life of the asset. The fair value of the ARO is estimated by discounting
the expected future cash flows to settle the ARO at the Company's average
credit-adjusted risk-free interest rate, which is currently 6.6%. In subsequent
periods, the ARO is adjusted for the passage of time and for any changes in the
amount or timing of the underlying future cash flows. The estimates described
impact earnings by way of depletion on the capital cost and accretion on the
asset retirement liability. In addition, differences between actual and
estimated costs to settle the ARO, timing of cash flows to settle the
obligation and future inflation rates could result in gains or losses on the
final settlement of the ARO.
An ARO is not recognized for assets with an indeterminate useful life (e.g.
pipeline assets and the Horizon Project upgrader and related infrastructure)
because an amount cannot be reasonably determined. An ARO for these assets will
be recorded in the first period in which the lives of these assets are
determinable.
INCOME TAXES
The Company follows the liability method of accounting for income taxes. Under
this method, future income tax assets and liabilities are recognized based on
the estimated tax effects of temporary differences between the carrying value
of assets and liabilities in the consolidated financial statements and their
respective tax bases, using income tax rates substantively enacted as of the
consolidated balance sheet date. Accounting for income taxes is a complex
process that requires management to interpret frequently changing laws and
regulations (e.g. changing income tax rates) and make certain judgements with
respect to the application of tax law, estimating the timing of temporary
difference reversals, and estimating the realizability of tax assets. These
interpretations and judgements impact the current and future income tax
provisions, future income tax assets and liabilities and net earnings.
35
RISK MANAGEMENT ACTIVITIES
The Company utilizes various derivative financial instruments to manage its
commodity price, currency and interest rate exposures. These derivative
financial instruments are not intended for trading or speculative purposes.
Effective January 1, 2007, the Company adopted the new accounting standards
relating to the accounting for and disclosure of financial instruments. The
effects of adopting these standards on the Company's opening balance sheet are
discussed in further detail in the "Risk Management Activities" section of this
MD&A. All derivative financial instruments are recognized at estimated fair
value on the consolidated balance sheet at each balance sheet date. The
estimated fair value of derivative instruments has been determined based on
appropriate internal valuation methodologies and/or third party indications.
However, these estimates may not necessarily be indicative of the amounts that
could be realized or settled in a current market transaction and these
differences may be material.
PURCHASE PRICE ALLOCATIONS
The purchase prices of business combinations and asset acquisitions are
allocated to the underlying acquired assets and liabilities based on their
estimated fair value at the time of acquisition. The determination of fair
value requires the Company to make assumptions and estimates regarding future
events. The allocation process is inherently subjective and impacts the amounts
assigned to individually identifiable assets and liabilities. As a result, the
purchase price allocation impacts the Company's reported assets and liabilities
and future net earnings due to the impact on future DD&A expense and impairment
tests.
The Company has made various assumptions in determining the fair values of the
acquired assets and liabilities. The most significant assumptions and judgments
relate to the estimation of the fair value of the crude oil and natural gas
properties. To determine the fair value of these properties, the Company
estimates (a) crude oil and natural gas reserves, and (b) future prices of
crude oil and natural gas. Reserve estimates are based on the work performed by
the Company's engineers and outside consultants. The judgments associated with
these estimated reserves are described above in "Crude Oil and Natural Gas
Reserves". Estimates of future prices are based on prices derived from price
forecasts among industry analysts and internal assessments. The Company applies
estimated future prices to the estimated reserves quantities acquired, and
estimates future operating and development costs, to arrive at estimated future
net revenues for the properties acquired.
CONTROL ENVIRONMENT
The Company's management, including the President and Chief Operating Officer
and the Chief Financial Officer and Senior Vice-President, Finance, evaluated
the effectiveness of disclosure controls and procedures as at December 31,
2007, and concluded that disclosure controls and procedures are effective to
ensure that information required to be disclosed by the Company in its annual
filings and other reports filed with securities regulatory authorities in
Canada and the United States is recorded, processed, summarized and reported
within the time periods specified and such information is accumulated and
communicated to allow timely decisions regarding required disclosures.
The President and Chief Operating Officer and the Chief Financial Officer and
Senior Vice-President, Finance also performed an assessment of internal control
over financial reporting as at December 31, 2007, and concluded that internal
control over financial reporting is effective. Further, there were no changes
in the Company's internal control over financial reporting during 2007 that
have materially affected, or are reasonably likely to materially affect,
internal controls over financial reporting.
While the Company believes that its disclosure controls and procedures and
internal controls over financial reporting provide a reasonable level of
assurance that they are effective, it recognizes that all internal control
systems have inherent limitations. Because of its inherent limitations, the
Company's internal control system may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in
conditions, or that the degree of compliance with the policies or procedures
may deteriorate.
36
NEW ACCOUNTING STANDARDS
Effective January 1, 2008, the Company will adopt the following three new
accounting standards issued by the CICA:
CAPITAL DISCLOSURES
o Section 1535 - "Capital Disclosures" requires entities to disclose
their objectives, policies and processes for managing capital, as well
as quantitative data about capital. The section also requires the
disclosure of any externally-imposed capital requirements and
compliance with those requirements. The section does not define
capital. The section affects disclosures only and will not impact the
Company's accounting for capital.
INVENTORIES
o Section 3031 - "Inventories" replaces Section 3030 - "Inventories" and
establishes new standards for the measurement of cost of inventories
and expands disclosure requirements for inventories. Adoption of this
standard is not anticipated to have a material impact on the Company's
financial statements.
FINANCIAL INSTRUMENTS
o Section 3862 - "Financial Instruments - Disclosure" and Section 3863
"Financial Instruments - Presentation" replace Section 3861 -
"Financial Instruments - Disclosure and Presentation". Section 3862
enhances disclosure requirements concerning risks and requires
disclosures of quantitative and qualitative disclosures about exposures
to risks arising from financial instruments. Section 3863 carries
forward the presentation requirements from Section 3861 unchanged.
These standards affect disclosures only and will not impact the
Company's accounting for financial instruments.
In addition, the following standard was issued during 2008 and will be
effective for the Company's year beginning on January 1, 2009, with earlier
adoption permitted:
GOODWILL AND INTANGIBLE ASSETS
o Section 3064 - "Goodwill and Intangible Assets" replaces Section 3062 -
"Goodwill and Other Intangible Assets" and Section 3450 - "Research and
Development Costs." In addition, EIC-27 - "Revenue and Expenditures
during the Pre-Operating Period" has been withdrawn. The new standard
addresses when an internally generated intangible asset meets the
definition of an asset. Adoption of the new standard may impact the
Company's capitalization of certain costs during the development and
start-up of large development projects.
INTERNATIONAL FINANCIAL REPORTING STANDARDS
The CICA has confirmed that Canadian GAAP will be replaced in full with
International Financial Reporting Standards as promulgated by the International
Accounting Standards Board effective January 1, 2011.
37
OUTLOOK
The Company continues to implement its strategy of maintaining a large
portfolio of varied projects, which the Company believes will enable it, over
an extended period of time, to provide consistent growth in production and
create shareholder value. Annual budgets are developed, scrutinized throughout
the year and revised if necessary in the context of targeted financial ratios,
project returns, product pricing expectations, and balance in project risk and
time horizons. The Company maintains a high ownership level and operatorship
level in all of its properties and can therefore control the nature, timing and
extent of capital expenditures in each of its project areas. The Company
expects production levels in 2008 to average between 316,000 bbl/d and 366,000
bbl/d of crude oil and NGLs and between 1,429 mmcf/d and 1,513 mmcf/d of
natural gas.
The forecasted capital expenditures in 2008 are currently expected to be as
follows:
($ millions) 2008 Forecast
======================================================================================
CONVENTIONAL CRUDE OIL AND NATURAL GAS
North America natural gas $ 617
North America crude oil and NGLs 1,075
North Sea 231
Offshore West Africa 458
Property acquisitions, dispositions and midstream 390
--------------------------------------------------------------------------------------
$ 2,771
--------------------------------------------------------------------------------------
HORIZON PROJECT
Phase 1 - Construction (1) $ 1,750 - 1,950
Phase 1 - Operating inventory and capital inventory 109
Phase 1 - Commissioning costs 184
Phase 2/3 - Tranche 2 439
Sustaining costs 19
Capitalized interest and other costs 381
--------------------------------------------------------------------------------------
$ 2,882 - 3,082
--------------------------------------------------------------------------------------
TOTAL $ 5,653 - 5,853
======================================================================================
(1) REVISED FORECASTED CAPITAL EXPENDITURES.
NORTH AMERICA NATURAL GAS
The 2008 North America natural gas drilling program is highlighted by the
continued high-grading of the Company's natural gas asset base as follows:
(Number of wells) 2008 Forecast
======================================================================================
Coal bed methane and shallow natural gas 161
Conventional natural gas 104
Cardium natural gas 14
Deep natural gas 32
Foothills natural gas 3
--------------------------------------------------------------------------------------
Total 314
======================================================================================
The Company has reduced 2008 natural gas drilling in Alberta due to the
anticipated future impact of royalty changes effective 2009.
38
NORTH AMERICA CRUDE OIL AND NGLS
The 2008 North America crude oil drilling program is highlighted by continued
development of the Primrose thermal projects, Pelican Lake, and a strong
conventional primary heavy program, as follows:
(Number of wells) 2008 Forecast
======================================================================================
Conventional primary heavy crude oil 311
Thermal heavy crude oil 32
Light crude oil 78
Pelican Lake crude oil 105
--------------------------------------------------------------------------------------
Total 526
======================================================================================
HORIZON PROJECT
The Horizon Project is targeting first crude oil in the third quarter of 2008.
Phase 1 construction capital is budgeted to be approximately $1.7 billion to
$1.9 billion in 2008, representing a cost to completion forecast range of 25%
to 28% over the original $6.8 billion estimate.
NORTH SEA
The 2008 capital forecast for the North Sea includes drilling 4 net platform
wells while continuing the successful workover and recompletion program.
OFFSHORE WEST AFRICA
The 2008 capital forecast for Offshore West Africa includes re-completing 2
wells at Baobab and targeted first oil at Olowi in late 2008.
SENSITIVITY ANALYSIS
The following table is indicative of the annualized sensitivities of cash flow
from operations and net earnings from changes in certain key variables. The
analysis is based on business conditions and sales volumes during the fourth
quarter of 2007, excluding mark-to-market gains (losses) on risk management
activities, and is not necessarily indicative of future results. Each separate
line item in the sensitivity analysis shows the effect of a change in that
variable only; all other variables are held constant.
CASH FLOW
CASH FLOW FROM NET
FROM OPERATIONS NET EARNINGS
OPERATIONS (PER COMMON EARNINGS (PER COMMON
($ MILLIONS) SHARE, BASIC) ($ MILLIONS) SHARE, BASIC)
======================================================================================================
PRICE CHANGES
Crude oil - WTI US$1.00/bbl (1)
Excluding financial derivatives $ 96 $ 0.18 $ 70 $ 0.13
Including financial derivatives $ 21 $ 0.04 $ 17 $ 0.03
Natural gas - AECO C$0.10/mcf (1)
Excluding financial derivatives $ 41 $ 0.08 $ 29 $ 0.05
Including financial derivatives $ 33 $ 0.06 $ 23 $ 0.04
VOLUME CHANGES
Crude oil - 10,000 bbl/d $ 132 $ 0.25 $ 70 $ 0.13
Natural gas - 10 mmcf/d $ 16 $ 0.03 $ 6 $ 0.01
FOREIGN CURRENCY RATE CHANGE
$0.01 change in US$ (1)
Including financial derivatives $ 73 - 74 $ 0.13 - 0.14 $ 31 - 32 $ 0.06
INTEREST RATE CHANGE - 1% $ 38 $ 0.07 $ 38 $ 0.07
======================================================================================================
(1) FOR DETAILS OF FINANCIAL INSTRUMENTS IN PLACE, REFER TO NOTE 12 TO THE
COMPANY'S AUDITED ANNUAL CONSOLIDATED FINANCIAL STATEMENTS AS AT DECEMBER
31, 2007.
39
DAILY PRODUCTION BY SEGMENT, BEFORE ROYALTIES
Q1 Q2 Q3 Q4 2007 2006 2005
============================================================================================================
CRUDE OIL AND NGLS
(BBL/D)
North America 237,489 240,420 252,095 256,843 246,779 235,253 221,669
North Sea 61,869 57,286 52,013 52,709 55,933 60,056 68,593
Offshore West
Africa 27,643 29,788 28,954 27,688 28,520 36,689 22,906
------------------------------------------------------------------------------------------------------------
Total 327,001 327,494 333,062 337,240 331,232 331,998 313,168
------------------------------------------------------------------------------------------------------------
NATURAL GAS (MMCF/D)
North America 1,694 1,696 1,622 1,562 1,643 1,468 1,416
North Sea 15 15 10 13 13 15 19
Offshore West
Africa 8 11 15 14 12 9 4
------------------------------------------------------------------------------------------------------------
Total 1,717 1,722 1,647 1,589 1,668 1,492 1,439
------------------------------------------------------------------------------------------------------------
BARRELS OF OIL
EQUIVALENT (BOE/D)
North America 519,700 523,037 522,427 517,101 520,564 479,891 457,695
North Sea 64,370 59,758 53,597 54,825 58,099 62,558 71,651
Offshore West
Africa 29,044 31,666 31,460 29,982 30,543 38,275 23,614
------------------------------------------------------------------------------------------------------------
Total 613,114 614,461 607,484 601,908 609,206 580,724 552,960
============================================================================================================
PER UNIT RESULTS (1)
Q1 Q2 Q3 Q4 2007 2006 2005
============================================================================================================
CRUDE OIL AND NGLS
($/BBL)
Sales price (2) $ 51.71 $ 53.74 $ 58.10 $ 58.03 $ 55.45 $ 53.65 $ 46.86
Royalties 4.92 5.46 6.65 6.66 5.94 4.48 3.97
Production
expense 13.81 15.01 13.13 11.53 13.34 12.29 11.17
------------------------------------------------------------------------------------------------------------
Netback $ 32.98 $ 33.27 $ 38.32 $ 39.84 $ 36.17 $ 36.88 $ 31.72
------------------------------------------------------------------------------------------------------------
NATURAL GAS ($/MCF)
Sales price (2) $ 7.74 $ 7.44 $ 5.87 $ 6.28 $ 6.85 $ 6.72 $ 8.57
Royalties 1.48 1.10 0.89 0.94 1.11 1.29 1.75
Production
expense 0.97 0.89 0.88 0.91 0.91 0.82 0.73
------------------------------------------------------------------------------------------------------------
Netback $ 5.29 $ 5.45 $ 4.10 $ 4.43 $ 4.83 $ 4.61 $ 6.09
------------------------------------------------------------------------------------------------------------
BARRELS OF OIL
EQUIVALENT ($/BOE)
Sales price (2) $ 49.32 $ 49.70 $ 47.96 $ 49.23 $ 49.05 $ 47.92 $ 48.77
Royalties 6.76 5.99 6.07 6.21 6.26 5.89 6.82
Production
expense 10.10 10.44 9.62 8.85 9.75 9.14 8.21
------------------------------------------------------------------------------------------------------------
Netback $ 32.46 $ 33.27 $ 32.27 $ 34.17 $ 33.04 $ 32.89 $ 33.74
============================================================================================================
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
(2) NET OF TRANSPORTATION AND BLENDING COSTS AND EXCLUDING RISK MANAGEMENT
ACTIVITIES.
40
NETBACK ANALYSIS
($/boe) (1) 2007 2006 2005
=========================================================================================================================
Sales price (2) $ 49.05 $ 47.92 $ 48.77
Royalties 6.26 5.89 6.82
Production expense (3) 9.75 9.14 8.21
-------------------------------------------------------------------------------------------------------------------------
NETBACK 33.04 32.89 33.74
Midstream contribution (3) (0.23) (0.23) (0.26)
Administration 0.93 0.85 0.75
Interest, net 1.24 0.66 0.74
Realized risk management loss 0.73 6.27 5.13
Realized foreign exchange loss (gain) 0.24 (0.06) (0.15)
Taxes other than income tax - current 0.54 1.04 1.01
Current income tax - North America 0.43 0.68 0.50
Current income tax - North Sea 0.95 0.14 0.77
Current income tax - Offshore West Africa 0.33 0.23 0.17
-------------------------------------------------------------------------------------------------------------------------
CASH FLOW $ 27.88 $ 23.31 $ 25.08
=========================================================================================================================
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
(2) NET OF TRANSPORTATION AND BLENDING COSTS AND EXCLUDING RISK MANAGEMENT
ACTIVITIES.
(3) EXCLUDING INTER-SEGMENT ELIMINATIONS.
TRADING AND SHARE STATISTICS
Q1 Q2 Q3 Q4 2007 2006
=========================================================================================================================
TSX - C$
Trading Volume (thousands) 117,164 94,089 100,950 116,831 429,034 508,935
Share Price ($/share)
High $ 65.50 $ 74.99 $ 80.02 $ 79.91 $ 80.02 $ 73.91
Low $ 52.45 $ 63.71 $ 65.43 $ 64.24 $ 52.45 $ 45.49
Close $ 63.75 $ 70.78 $ 75.56 $ 72.58 $ 72.58 $ 62.15
Market capitalization as at
December 31 ($ millions) $ 39,174 $ 33,431
Shares outstanding
(thousands) 539,729 537,903
-------------------------------------------------------------------------------------------------------------------------
NYSE - US$
Trading Volume (thousands) 128,543 93,086 118,315 146,322 486,266 401,909
Share Price ($/share)
High $ 56.62 $ 69.97 $ 78.90 $ 87.17 $ 87.17 $ 64.38
Low $ 44.56 $ 55.07 $ 60.70 $ 63.52 $ 44.56 $ 40.29
Close $ 55.19 $ 66.35 $ 75.75 $ 73.14 $ 73.14 $ 53.23
Market Capitalization as at
December 31($ millions) $ 39,476 $ 28,633
Shares outstanding
(thousands) 539,729 537,903
=========================================================================================================================
41
ADDITIONAL DISCLOSURE
DISCLOSURE CONTROLS AND PROCEDURES
As of the end of the registrant's fiscal year ended December 31, 2007, an
evaluation of the effectiveness of Canadian Natural's "disclosure controls and
procedures" (as such term is defined in Rules 13a-15(c) and 15d-15(e) of the
Securities Exchange Act of 1934, as amended (the "Exchange Act") was carried out
by Canadian Natural's management with the participation of Canadian Natural's
principal executive officer and principal financial officer. Based upon the
evaluation, Canadian Natural's principal executive officer and principal
financial officer have concluded that as of the end of the fiscal year, Canadian
Natural's disclosure controls and procedures are effective to ensure that
information required to be disclosed by the registrant in reports that it files
or submits under the Exchange Act is (i) recorded, processed, summarized and
reported within the time periods specified in Securities and Exchange Commission
rules and forms and (ii) accumulated and communicated to the registrant's
management, including its principal executive officer and principal financial
officer, to allow timely decisions regarding required disclosure.
It should be noted that while Canadian Natural's principal executive officer and
principal financial officer believe that Canadian Natural's disclosure controls
and procedures provide a reasonable level of assurance that they are effective,
they do not expect Canadian Natural's disclosure controls and procedures or
internal control over financial reporting will prevent all errors and fraud. A
control system, no matter how well conceived or operated, can provide only
reasonable, not absolute, assurance that the objectives of the control system
are met.
MANAGEMENT'S ASSESSMENT OF INTERNAL CONTROL OVER FINANCIAL REPORTING
The required disclosure is included in the "Management's Assessment of Internal
Control Over Financial Reporting" that accompanies Canadian Natural's audited
consolidated financial statements for the fiscal year ended December 31, 2007,
filed as part of this Annual Report on Form 40-F.
ATTESTATION REPORT OF THE REGISTERED PUBLIC ACCOUNTING FIRM
The required disclosure is included in the "Auditors' Report" that accompanies
Canadian Natural's audited consolidated financial statements for the fiscal year
ended December 31, 2007, filed as part of this Annual Report on Form 40-F.
CHANGES IN INTERNAL CONTROLS OVER FINANCIAL REPORTING
During the fiscal year ended December 31, 2007, there were no changes in
Canadian Natural's internal controls over financial reporting that have
materially affected, or are reasonably likely to materially affect, Canadian
Natural's internal controls over financial reporting.
NOTICES PURSUANT TO REGULATION BTR
None
AUDIT COMMITTEE FINANCIAL EXPERT
The Board of Directors of Canadian Natural has determined that Ms. C.M. Best
qualifies as an "audit committee financial expert" (as defined in paragraph 8(b)
of General Instruction B to the Form 40-F) serving on its Audit Committee. Ms.
C.M. Best is, as are all members of the Audit Committee of the Board of
Directors of Canadian Natural, "independent" as such term is defined in the
rules of the New York Stock Exchange.
CODE OF ETHICS
Canadian Natural has a long-standing Code of Integrity, Business Ethics and
Conduct (the "Code of Ethics"), which covers such topics as employment
standards, conflict of interest, the treatment of confidential information and
trading in Canadian Natural's shares and is designed to ensure that Canadian
Natural's business is consistently conducted in a legal and ethical manner. Each
director and all employees, including each member of senior management and more
specifically the principal executive officer, the principal financial officer
and the principal accounting officer, are required to abide by the Code of
Ethics. The Nominating and Corporate Governance Committee periodically reviews
the Code of Ethics to ensure it addresses appropriate topics and complies with
regulatory requirements and recommends any appropriate changes to the Board for
approval.
Any waivers of or amendments to the Code of Ethics must be approved by the Board
of Directors and will be appropriately disclosed. In 2007 the Nominating and
Corporate Governance Committee reviewed and recommended to the Board revisions
relating to clarification on insider trading, communication and disclosure,
communication with electronic mediums, Staff participating in government and
political activities, and Canadian Natural's Human Rights Statement which were
subsequently approved by the Board of Directors.
The Code of Ethics is available through the System for Electronic Document and
Analysis and Retrieval (SEDAR) at WWW.SEDAR.COM. Requests for copies can also be
made by contacting: Bruce E. McGrath, Corporate Secretary, Canadian Natural
Resources Limited, 2500-855 2nd Street, S.W., Calgary, Alberta, Canada T2P 4J8.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
PricewaterhouseCoopers LLP ("PwC") has been the auditor of Canadian Natural
since Canadian Natural's inception. The aggregate amounts billed by PwC for each
of the last two fiscal years for audit fees, audit-related fees, tax fees and
all other fees, excluding expenses, are set forth below.
AUDIT FEES
The aggregate fees billed for each of the last two fiscal years of Canadian
Natural ending December 31, 2007 and December 31, 2006, for professional
services rendered by PwC for the audit of its internal controls and annual
consolidated financial statements in connection with statutory and regulatory
filings or engagements for those fiscal years, unaudited reviews of the first,
second and third quarters of its interim consolidated financial statements and
audits of certain of Canadian Natural's subsidiary companies' annual financial
statements were $2,729,315 for 2007 and were $3,126,287 for 2006.
AUDIT-RELATED FEES
The aggregate fees billed for each of the last two fiscal years of Canadian
Natural, ending December 31, 2007 and December 31, 2006, for audit-related
services by PwC including debt covenant compliance and Crown Royalty Statements,
were $164,000 for 2007 and were $121,353 for 2006. Canadian Natural's Audit
Committee approved all of these audit-related services.
TAX FEES
The aggregate fees billed for each of the last two fiscal years of Canadian
Natural, ending December 31, 2007 and December 31, 2006, for professional
services rendered by PwC for tax-related services related to expatriate personal
tax and compliance as well as other corporate tax return matters provided in
2007 were $154,459 for 2007 and were $134,025 for 2006. Canadian Natural's Audit
Committee approved all of these tax-related services.
ALL OTHER FEES
The aggregate fees billed for each of the last two fiscal years of Canadian
Natural, ending December 31, 2007 and December 31, 2006 for other services were
$9,440 for 2007 and were $9,516 for 2006. The fees for other services paid in
2007 related to accessing resource materials through PwC's accounting literature
library. Canadian Natural's Audit Committee approved all of the noted services.
AUDIT COMMITTEE PRE-APPROVAL POLICIES AND PROCEDURES
The Audit Committee's duties and responsibilities include the review and
approval of fees to be paid to the independent auditors, scope and timing of the
audit and other related services rendered by the independent auditors. The Audit
Committee also reviews and approves the independent auditor's annual audit plan,
including scope, staffing, locations and reliance upon management and internal
audit department prior to the commencement of the audit and reviews and approves
proposed non-audit services to be provided by the independent auditors, except
those non-audit services prohibited by legislation. Canadian Natural did not
rely on the de minimis exemption provided by paragraph (c)(7)(i)(c) of Rule 2.01
of Regulation S-X in 2007.
OFF-BALANCE SHEET ARRANGEMENTS
Canadian Natural does not have any off-balance sheet arrangements that have or
are reasonably likely to have an effect on its results of operations or
financial condition. See page 60 of Canadian Natural's Management's Discussion
and Analysis of Financial Condition and Results of Operations for the fiscal
year ended December 31, 2007, filed herewith, under the caption "Commitments and
Off Balance Sheet Arrangements".
CONTRACTUAL OBLIGATIONS
In the normal course of business, Canadian Natural has entered into various
commitments that will have an impact on its future operations. These commitments
primarily relate to debt repayments; operating leases relating to Floating
Production, Storage and Offsite vessels ("FPSOs"), drilling rigs and office
space; and firm commitments for gathering, processing and transmission services;
as well as expenditures relating to asset retirement obligations ("ARO"). As at
December 31, 2007, no entities were consolidated under CICA Handbook Accounting
Guideline 15, "Consolidation of Variable Interest Entities". The following table
summarizes Canadian Natural's commitments as at December 31, 2007:
($ millions) 2008 2009 2010 2011 2012 Thereafter
-----------------------------------------------------------------------------------------------------------------
Product transportation and pipeline $ 232 $ 151 $ 137 $ 109 $ 91 $ 972
Offshore equipment operating lease $ 114 $ 129 $ 113 $ 111 $ 90 $ 387
(1)
Offshore drilling (2) (3) $ 267 $ 185 $ 39 $ - $ - $ -
Asset retirement obligations (4) $ 33 $ 4 $ 5 $ 4 $ 4 $ 4,376
Long-term debt (5) $ 39 $ 2,361 $ 400 $ 395 $ 346 $ 5,098
Interest expense (6) $ 612 $ 590 $ 487 $ 465 $ 374 $ 4,338
Office lease $ 26 $ 28 $ 28 $ 22 $ 3 $ -
$ 166 $ 173 25 $ 4 $ - $ -
Electricity and other
=================================================================================================================
(1) OFFSHORE EQUIPMENT OPERATING LEASES ARE PRIMARILY COMPRISED OF OBLIGATIONS
RELATED TO FPSOS. DURING 2006, CANADIAN NATURAL ENTERED INTO AN AGREEMENT
TO LEASE AN ADDITIONAL FPSO COMMENCING IN 2008, IN CONNECTION WITH THE
PLANNED OFFSHORE DEVELOPMENT IN GABON, OFFSHORE WEST AFRICA. DURING THE
INITIAL TERM, THE TOTAL ANNUAL PAYMENTS FOR THE GABON FPSO ARE ESTIMATED
TO BE US$50 MILLION.
(2) DURING 2007, CANADIAN NATURAL ENTERED INTO A ONE-YEAR AGREEMENT FOR
OFFSHORE DRILLING SERVICES RELATED TO THE BAOBAB FIELD IN COTE D'IVOIRE,
OFFSHORE WEST AFRICA. THE AGREEMENT IS SCHEDULED TO COMMENCE IN 2008,
SUBJECT TO RIG AVAILABILITY. ESTIMATED TOTAL PAYMENTS OF US$100 MILLION,
AFTER JOINT VENTURE RECOVERIES, HAVE BEEN INCLUDED IN THIS TABLE FOR THE
PERIOD 2008 - 2009.
(3) DURING 2007, CANADIAN NATURAL AWARDED CONTRACTS FOR A DRILLING RIG AND FOR
THE CONSTRUCTION OF WELLHEAD TOWERS IN CONNECTION WITH THE PLANNED
OFFSHORE DEVELOPMENT IN GABON, OFFSHORE WEST AFRICA. ESTIMATED TOTAL
PAYMENTS OF US$393 MILLION HAVE BEEN INCLUDED IN THIS TABLE FOR THE PERIOD
2008 - 2010.
(4) AMOUNTS REPRESENT MANAGEMENT'S ESTIMATE OF THE FUTURE UNDISCOUNTED
PAYMENTS TO SETTLE ARO RELATED TO RESOURCE PROPERTIES, FACILITIES, AND
PRODUCTION PLATFORMS, BASED ON CURRENT LEGISLATION AND INDUSTRY OPERATING
PRACTICES. AMOUNTS DISCLOSED FOR THE PERIOD 2008 - 2012 REPRESENT THE
MINIMUM REQUIRED EXPENDITURES TO MEET THESE OBLIGATIONS. ACTUAL
EXPENDITURES IN ANY PARTICULAR YEAR MAY EXCEED THESE MINIMUM AMOUNTS.
(5) THE LONG-TERM DEBT REPRESENTS PRINCIPAL REPAYMENTS ONLY AND DOES NOT
REFLECT FAIR VALUE ADJUSTMENTS, ORIGINAL ISSUE DISCOUNTS OR TRANSACTION
COSTS. NO DEBT REPAYMENTS ARE REFLECTED FOR $2,366 MILLION OF REVOLVING
BANK CREDIT FACILITIES DUE TO THE EXTENDABLE NATURE OF THE FACILITIES.
(6) INTEREST EXPENSE AMOUNTS REPRESENT THE SCHEDULED FIXED-RATE AND
VARIABLE-RATE CASH PAYMENTS RELATED TO LONG-TERM DEBT. INTEREST ON
VARIABLE-RATE LONG-TERM DEBT WAS ESTIMATED BASED UPON PREVAILING INTEREST
RATES AS OF DECEMBER 31, 2007.
In addition to the amounts disclosed above, Canadian Natural has budgeted
construction costs of approximately $1.7 billion to $1.9 billion for 2008
related to the planned completion of Phase 1 of the Horizon Oil Sands Project.
IDENTIFICATION OF THE AUDIT COMMITTEE
Canadian Natural has a separately designated standing audit committee
established in accordance with section 3(a)(58)(A) of the Exchange Act. The
members of the Audit Committee are Messrs. G. A. Filmon, G. D. Giffin, D. A.
Tuer and Ms. C.M. Best, who chairs the Audit Committee.
NEW YORK STOCK EXCHANGE DISCLOSURE
PRESIDING DIRECTOR AT MEETINGS OF NON-MANAGEMENT DIRECTORS
Canadian Natural schedules executive sessions at each regularly scheduled Board
of Directors meeting in which Canadian Natural's "non-management directors" (as
that term is defined in the rules of the New York Stock Exchange) meet without
management participation. Mr. G. D. Giffin serves as the presiding director (the
"Presiding Director") at such sessions and in his absence the non-management
directors appoint a Presiding Director from among the non-management directors.
COMMUNICATION WITH NON-MANAGEMENT DIRECTORS
Shareholders may send communications to Canadian Natural's non-management
directors by writing to the Presiding Director, c/o Bruce E. McGrath, Corporate
Secretary, Canadian Natural Resources Limited, 2500, 855 - 2nd Street S.W.,
Calgary, Alberta, T2P 4J8. Communications will be referred to the Presiding
Director for appropriate action. The status of all outstanding concerns
addressed to the Presiding Director will be reported to the Board of Directors
as appropriate.
CORPORATE GOVERNANCE GUIDELINES
In accordance with Section 303A.09 of the NYSE Listed Company Manual, Canadian
Natural has adopted a set of corporate governance guidelines, which are
available in print at no charge to any shareholder who requests them. Requests
for copies of the corporate governance guidelines should be made by contacting:
Bruce E. McGrath, Corporate Secretary, Canadian Natural Resources Limited,
2500-855 2nd Street, S.W., Calgary, Alberta, Canada T2P 4J8. The corporate
governance guidelines are attached as a schedule to the Information Circular for
the Annual General Meeting of Shareholders which is available through the System
for Electronic Document and Analysis and Retrieval (SEDAR) at WWW.SEDAR.COM.
BOARD COMMITTEE CHARTERS
The charters of Canadian Natural's Audit Committee, Nominating and Corporate
Governance Committee and Compensation Committee are available in print at no
charge to any shareholder who requests them. Requests for copies of these
documents should be made by contacting: Bruce E. McGrath, Corporate Secretary,
Canadian Natural Resources Limited, 2500-855 2nd Street, S.W., Calgary, Alberta,
Canada T2P 4J8. The Charter of Canadian Natural's Audit Committee is also
attached as a schedule to Canadian Natural's Annual Information Form for year
ending December 31, 2007, which forms part of this Form 40-F. The Annual
Information Form is also available through the System for Electronic Document
and Analysis and Retrieval (SEDAR) at WWW.SEDAR.COM.
UNDERTAKING AND CONSENT TO SERVICE OF PROCESS
UNDERTAKING
Canadian Natural undertakes to make available, in person or by telephone,
representatives to respond to inquiries made by the Commission staff, and to
furnish promptly, when requested to do so by the Commission staff, information
relating to: the securities registered pursuant to Form 40-F; the securities in
relation to which the obligation to file an annual report on Form 40-F arises;
or transactions in said securities.
CONSENT TO SERVICE OF PROCESS
Canadian Natural has previously filed a Form F-X in connection with the class of
securities in relation to which the obligation to file this report arises.
Any change to the name or address of the agent for service of process of
Canadian Natural shall be communicated promptly to the Commission by an
amendment to the Form F-X referencing the file number of the relevant
registration statement.
SIGNATURES
Pursuant to the requirements of the Exchange Act, Canadian Natural certifies
that it meets all of the requirements for filing on Form 40-F and has duly
caused this Annual Report to be signed on its behalf by the undersigned, thereto
duly authorized.
Dated this 27th day of March, 2008.
CANADIAN NATURAL RESOURCES LIMITED
By: /S/ STEVE W. LAUT
-------------------------
Name: Steve W. Laut
Title: President and Chief
Operating Officer
Documents filed as part of this report:
EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION
1. Supplementary Oil & Gas Information for the fiscal year ended December 31,
2007.
2. Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or
15d-14 of the Securities Exchange Act of 1934.
3. Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or
15d-14 of the Securities Exchange Act of 1934.
4. Certification of Chief Executive Officer pursuant to Section 1350 of
Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
5. Certification of Chief Financial Officer pursuant to Section 1350 of
Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
6. Consent of PricewaterhouseCoopers LLP, independent chartered accountants.
7. Consent of Sproule Associates Limited, independent petroleum engineering
consultants.
8. Consent of Ryder Scott Company, independent petroleum engineering
consultants.
9. Consent of GLJ Petroleum Consultants Ltd., independent petroleum
engineering consultants.