U.S. SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 40-F
[_] REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES
EXCHANGE ACT OF 1934
OR
[X] ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2002
Commission File No. 1-8795
CANADIAN NATURAL RESOURCES LIMITED
(Exact name of Registrant as specified in its charter)
CANADA 1311 NOT APPLICABLE
Province or other jurisdiction of (Primary Standard Industrial (I.R.S. Employer Identification
incorporation or organization) Classification Code Number) Number)
2500, 855 - 2ND STREET S.W., CALGARY, ALBERTA, CANADA T2P 4J8
(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 of the Registrant 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:
None
Securities for which there is a reporting obligation pursuant to Section 15(d)
of the Act: None
For annual reports, indicate by check mark the information filed with this form:
[X] Annual information form [X] Audited annual financial statements
Indicate the number of outstanding shares of each of the issuer's classes of
capital or common stock as of the close of the period covered by the annual
report.
At December 31, 2002, 133,775,558 Common Shares of Canadian Natural Resources
Limited were issued and outstanding. At December 31, 2002, no Class 1 Preferred
Shares of Canadian Natural Resources Limited were issued and outstanding.
Indicate by check mark whether the Registrant by filing the information
contained in this Form is also thereby furnishing the information to the
Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934
(the "Exchange Act"). If "Yes" is marked, indicate the file number assigned to
the Registrant in connection with such Rule. YES [_] NO [X]
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12
months (or for such shorter period that the Registrant was required to file such
reports), and (2) has been subject to such filing requirements for the past 90
days. YES [X] NO [_]
PRIOR FILINGS MODIFIED AND SUPERSEDED
The Registrant's Annual Report on Form 40-F for the year ended December
31, 2002, at the time of filing with the Securities and Exchange Commission (the
"Commission"), modifies and supersedes all prior documents filed pursuant to
Sections 13, 14 and 15(d) of the Exchange Act for purposes of any offers or
sales of any securities after the date of such filing pursuant to any
Registration Statement under the Securities Act of 1933 of the Registrant which
incorporates by reference such Annual Report. The documents (or portions
thereof) identified under the heading "Documents Filed as Part of This Report"
below as forming part of this Form 40-F are incorporated by reference into the
Registration Statement on Form F-9 No. 333-98063 as exhibits thereto.
CONSOLIDATED AUDITED ANNUAL FINANCIAL STATEMENTS AND
MANAGEMENT'S DISCUSSION AND ANALYSIS
For the purposes of this Annual Report on Form 40-F, only pages 32
through 70 of the Registrant's 2002 Annual Report referred to below shall be
deemed filed, and the balance of such 2002 Annual Report, except as it may be
otherwise specifically incorporated by reference in the Registrant's Annual
Information Form, shall be deemed not filed with the Commission as part of this
Annual Report on Form 40-F under the Exchange Act.
A. Audited Annual Financial Statements
For consolidated audited financial statements, including the report of
independent chartered accountants with respect thereto, see pages 50 through 70
of the Registrant's 2002 Annual Report, which pages are attached hereto and
included herein. For a reconciliation of important differences between Canadian
and United States generally accepted accounting principles, see Note 16 -
Differences Between Canadian and United States Generally Accepted Accounting
Principles on pages 68 through 70 of such 2002 Annual Report.
B. Management's Discussion and Analysis
For management's discussion and analysis, see pages 32 through 49 of
the Registrant's 2002 Annual Report, which pages are attached hereto and
included herein.
CONTROLS AND PROCEDURES
Within the 90-day period prior to the filing of this report, an
evaluation was carried out under the supervision of and with the participation
of the Registrant's management, including the Chief Executive Officer and Chief
Financial Officer, of the effectiveness of the Registrant's disclosure controls
and procedures (as defined in Rule 13a-14(c) under the Exchange Act). Based on
that evaluation, the Chief Executive Officer and Chief Financial Officer
concluded that the design and operation of these disclosure controls and
procedures were effective to ensure that material information required to be
disclosed by the Registrant in the reports that it files or submits under the
Exchange Act is recorded, processed, summarized and reported within the time
periods specified in the Commission's rules and forms.
No significant changes were made in the Registrant's internal controls
or in other factors that could significantly affect these controls subsequent to
the date of their evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
It should be noted that any system of controls, however well designed
and operated, can provide only reasonable, and not absolute, assurance that the
objectives of the system are met. In addition, the design of any control system
is based in part upon certain assumptions about the likelihood of future events.
Because of these and other inherent limitations of control systems, there can be
no assurance that any design will succeed in achieving its stated goals under
all potential future conditions, regardless of how remote.
2
UNDERTAKING AND CONSENT TO SERVICE OF PROCESS
A. Undertaking
The Registrant 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.
B. Consent to Service of Process
The Registrant 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.
3
SIGNATURES
Pursuant to the requirements of the Exchange Act, the Registrant
certifies that it meets all of the requirements for filing on Form 40-F and has
duly caused this Annual Report on Form 40-F to be signed on its behalf by the
undersigned, thereto duly authorized, in the City of Calgary, Province of
Alberta, Canada.
CANADIAN NATURAL RESOURCES LIMITED
(Registrant)
By: /s/ John G. Langille
----------------------------------
Name: John G. Langille
Title: President
Date: April 15, 2003
4
CERTIFICATIONS
I, John G. Langille, President, certify that:
1. I have reviewed this annual report on Form 40-F of Canadian Natural
Resources Limited;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this annual report (the "Evaluation Date");
and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based
on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (and persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and report
financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: April 15, 2003 /s/ John G. Langille
----------------------------------
Name: John G. Langille
Title: President
5
CERTIFICATIONS
I, Douglas A. Proll, Senior Vice President, Finance, certify that:
1. I have reviewed this annual report on Form 40-F of Canadian Natural
Resources Limited;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this annual report (the "Evaluation Date");
and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based
on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (and persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and report
financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: April 15, 2003 /s/ Douglas A. Proll
--------------------------------------
Name: Douglas A. Proll
Title: Senior Vice President, Finance
6
DOCUMENTS FILED AS PART OF THIS REPORT
1. Annual Information Form of the Registrant for the year ended December
31, 2002.
2. Management's Discussion and Analysis of the Registrant for the year
ended December 31, 2002.
3. Audited Consolidated Financial Statements of the Registrant as of
December 31, 2002 and for each of the three years then ended (Note 16
to the Audited Consolidated Financial Statements of the Registrant
relates to differences between Canadian and United States Generally
Accepted Accounting Principles).
EXHIBITS
99.1 Consent of PricewaterhouseCoopers LLP, independent chartered
accountants.
99.2 Consent of Sproule Associates Limited, independent petroleum
consultants.
99.3 Certificate Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
99.4 Certificate Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
7
DOCUMENT 1
----------
CANADIAN NATURAL RESOURCES LIMITED
ANNUAL INFORMATION FORM
APRIL 14, 2003
1
TABLE OF CONTENTS
DEFINITIONS....................................................................2
SPECIAL NOTE REGARDING FORWARD LOOKING STATEMENTS..............................3
THE COMPANY....................................................................4
GENERAL DEVELOPMENT OF THE BUSINESS............................................5
REGULATORY MATTERS.............................................................6
COMPETITIVE MATTERS............................................................8
ENVIRONMENTAL MATTERS..........................................................8
DESCRIPTION OF THE BUSINESS....................................................9
PRINCIPAL CRUDE OIL AND NATURAL GAS PROPERTIES................................10
NORTHEAST BRITISH COLUMBIA...........................................11
NORTHWEST ALBERTA.............................................................12
NORTH ALBERTA........................................................12
HORIZON OIL SANDS PROJECT............................................14
SOUTH ALBERTA........................................................15
SOUTHEAST SASKATCHEWAN...............................................16
NORTH SEA............................................................16
OFFSHORE WEST AFRICA.................................................17
COTE D'IVOIRE........................................................17
ANGOLA...............................................................18
CRUDE OIL AND NATURAL GAS RESERVES............................................19
RECONCILIATION OF CHANGES IN RESERVES.........................................23
CRUDE OIL AND NATURAL GAS PRODUCTION..........................................24
DRILLING ACTIVITY.............................................................26
CAPITAL EXPENDITURES..........................................................26
NON-RESERVE ACREAGE...........................................................28
SELECTED FINANCIAL INFORMATION................................................29
MARKET FOR CANADIAN NATURAL RESOURCES LIMITED SECURITIES......................30
DIVIDEND HISTORY..............................................................30
DIRECTORS AND OFFICERS........................................................31
ADDITIONAL INFORMATION........................................................33
CURRENCY
Unless otherwise indicated, all dollar figures stated in this Annual Information
Form represent Canadian dollars.
2
DEFINITIONS
The following are definitions of selected abbreviations used in this Annual
Information Form:
"ARTC" means Alberta Royalty Tax Credit.
"BBL" or "BARREL" means 34.972 Imperial gallons or 42 U.S. gallons.
"BCF" means one billion cubic feet.
"BBLS/D" means barrels per day.
"CANADIAN NATURAL RESOURCES LIMITED", "CANADIAN NATURAL", "CNRL" 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.
"FPSO" means floating production, storage and off-take vessel.
"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.
"MBBLS" means one thousand barrels.
"MCF" means one thousand cubic feet.
"MCF/D" means one thousand cubic feet per day.
"MMBBLS" 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.
"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.
"SAGD" means steam-assisted gravity drainage.
"UNDEVELOPED LAND" or "NON-RESERVE 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.
"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.
Natural gas is converted to oil equivalent at the rate of six thousand cubic
feet equals one barrel of oil equivalent.
3
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements in this document or incorporated herein by reference may
constitute "forward-looking statements" within the meaning of the United States
Private Litigation Reform Act of 1995. These forward-looking statements can
generally be identified as such because of the context of the statements
including words such as the Company "believes", "anticipates", "expects",
"plans", "estimates" or words of a similar nature.
The forward-looking statements are based on current expectations and are subject
to known and unknown risks, uncertainties and other factors that may cause the
actual results, performance or achievements of the Company, or industry results,
to be materially different from any future results, performance or achievements
expressed or implied by such forward-looking statements. Such factors include,
among others: the general economic and business conditions which will, among
other things, impact demand for and market prices of the Company's products; the
foreign currency exchange rates; the economic conditions in the countries and
regions in which the Company conducts business; the political uncertainty,
including actions of or against terrorists, insurgent groups or other conflict
including conflict between states; the industry capacity; the ability of the
Company to implement its business strategy, including exploration and
development activities; the impact of competition, availability and cost of
seismic, drilling and other equipment; the ability of the Company to complete
its capital programs; the ability of the Company to transport its products to
market; potential delays or changes in plans with respect to exploration or
development projects or capital expenditures; the operating hazards and other
difficulties inherent in the exploration for and production and sale of oil and
natural gas; the availability and cost of financing; the success of exploration
and development activities; the timing and success of integrating the business
and operations of acquired companies; the production levels; the uncertainty of
reserve estimates; the actions by governmental authorities; the government
regulations and the expenditures required to comply with them (especially safety
and environmental laws and regulations); the site restoration costs; and other
circumstances affecting revenues and expenses. 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 management's course of action
would depend upon its assessment of the future considering all information then
available.
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.
Readers are cautioned that the foregoing list of important factors is not
exhaustive. 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. The Company assumes no obligation to update
forward-looking statements should circumstances or management's estimates or
opinions change.
4
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. CNRL 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.
CNRL 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, including its subsidiaries,
("Ranger") in July 2000. On October 1, 2000 Ranger Oil Limited 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.
The material operating subsidiaries of the Company, each of which is directly or
indirectly wholly-owned, and their jurisdiction of incorporation are as follows:
NAME OF COMPANY JURISDICTION OF INCORPORATION
--------------- -----------------------------
CanNat Resources Inc. Alberta
CNR International (U. K.) Developments Limited England
CNR International (U. K.) Limited England
CNR International Cote d'Ivoire SARL Cote d'Ivoire
Renata Resources Inc. Alberta
CNRL as the managing partner and CanNat are the partners of Canadian Natural
Resources, a general partnership. Canadian Natural Resources as the managing
partner and Renata Resources Inc. are partners of Rio Alto Exploration, a
general partnership. The two partnerships hold the Canadian crude oil and
natural gas properties of CNRL. CNRL also has a 15 per cent interest in Cold
Lake Pipeline Ltd., which is the General Partner of Cold Lake Pipeline Limited
Partnership of which CNRL has a 14.7 per cent interest.
The consolidated financial statements of CNRL include the accounts of the
Company and all of its subsidiaries and partnerships.
5
GENERAL DEVELOPMENT OF THE BUSINESS
CNRL'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 natural gas.
The Company initiates, operates and maintains a large working interest in a
majority of the prospects in which it participates. CNRL's objective is to
increase cash flow and 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, 2002 the Company had 1,448 full time employees in
North America and 174 full time employees in its international operations.
In July 2000, the Company acquired 100 per cent of Ranger for a total purchase
price of $1,687.3 million, comprised of $722.8 million in cash, $358.0 million
attributable to the issue of 7,602,068 common shares of the Company, and the
assumption of $376.6 million of debt, $118.3 million of preferred securities and
$111.6 million of working capital deficiency. Ranger held a portfolio of
producing and non-producing crude oil and natural gas properties in the Western
Canadian Sedimentary Basin, the United States Gulf Coast, the UK sector of the
North Sea, and offshore West Africa. The Offer to Purchase dated June 19, 2000
offered $8.25 cash per common share for each Ranger common share subject to an
aggregate maximum of $650.0 million cash and to proration as described in the
Offer to Purchase; or 0.175 common shares of CNRL, subject to an aggregate
maximum of 10 million common shares and to proration as described in the Offer
to Purchase. Pursuant to the Offer to Purchase, 7,602,068 common shares of CNRL
were issued.
During 2000, the Company completed 170 transactions in the normal course to
acquire additional interests in crude oil and natural gas properties at an
aggregate expenditure of $278.2 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 non-operated Canadian properties owned by Ranger, not located in the
Company's core regions, for proceeds of $128.0 million.
On February 24, 2000, the Company issued $125.0 million 7.40 per cent unsecured
debentures maturing March 1, 2007 pursuant to a short form shelf prospectus
dated February 22, 1999.
In 2001, the Company completed 121 transactions in the normal course to acquire
additional interests in crude oil and natural gas properties at an aggregate
expenditure of $582.2 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
non-operated properties not located in the Company's core regions for proceeds
of $63.0 million, including a large portion of the properties acquired with
Ranger in the United States Gulf Coast.
On July 24, 2001, the Company issued US $400.0 million of 10 year 6.70per cent
unsecured notes maturing July 15, 2011 pursuant to a prospectus supplement dated
July 19, 2001 to the short form shelf prospectus dated July 6, 2001. Pursuant to
a prospectus supplement dated January 15, 2002 to the short form shelf
prospectus dated July 6, 2001, the Company issued on
6
January 23, 2002, US $400.0 million 30 year 7.20per cent unsecured notes
maturing January 15, 2032.
In July 2002, pursuant to the terms of a Plan of Arrangement, the Company
acquired 100 per cent of RAX. The total purchase price was $2,393.2 million,
comprised of $850.0 million in cash, $522.4 million attributable to the issue of
10,008,218 common shares of the Company, and the assumption of $936.3 million of
debt and $84.5 million of working capital deficiency. The acquisition provided
the Company with a new core region for natural gas exploration and exploitation
activities in Northwest Alberta. The RAX properties include approximately 2.9
million net acres of undeveloped lands and will provide additional opportunities
for the Company to increase its production and reserves of natural gas and
natural gas liquids. The acquisition added additional production which averaged
376 million cubic feet per day of natural gas and 11 thousand barrels per day of
crude oil and natural gas liquids during the second half of 2002 and 2-D and 3-D
seismic of 57,820 kilometres and 14,565 square kilometres respectively. Future
exploration and development projects will take advantage of the large
undeveloped land base, high quality seismic database information and excess
capacity within existing facilities. The acquisition solidified the Company as
the second largest producer of natural gas in Canada and the second largest
undeveloped landholder in western Canada.
During 2002, the Company completed 128 transactions in the normal course to
acquire additional interests in crude oil and natural gas properties at an
aggregate expenditure of $516.3 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 non-operated properties not located in the Company's core regions
for proceeds of $76.1 million.
On September 16, 2002, the Company issued US $350.0 million of 10 year 5.45per
cent unsecured notes maturing October 1, 2012 and US $350.0 million of 31 year
6.45per cent unsecured notes maturing June 30, 2033 pursuant to a short form
shelf prospectus dated August 16, 2002.
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 various
government legislation and regulations, which govern exploration, development,
production, refining, marketing, prevention of waste and other activities.
The Company's Canadian properties are located in Alberta, British Columbia,
Saskatchewan, Manitoba and the Northwest 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.
7
Conventional petroleum and natural gas leases issued by 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 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 the approval of a satisfactory 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. 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 natural gas liquids from each
province. Government royalties are payable on crude oil 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.
The Company is subject to federal and provincial income taxes in Canada at a
combined rate of approximately 42 per cent after allowable deductions.
INTERNATIONAL
Under existing law, the UK Government has broad authority to regulate the
petroleum industry, including the power to regulate exploration, development,
conservation and rates of production.
Production from offshore fields as defined by applicable legislation, whose
development was approved prior to April 1, 1982, were subject to Royalty of 12.5
per cent on or after deduction of certain allowances. Fields receiving
development approval after April 1, 1982 were not subject to Royalty. On
November 27, 2002, the UK Government announced the elimination of Royalty
effective January 1, 2003.
Crude oil and natural gas fields granted development approval before March 16,
1993 are subject to UK Petroleum Revenue Tax ("PRT") of 50 per cent charged on
crude oil and natural gas profits. Crude oil and natural gas fields granted
development approval on or after March 16, 1993 are exempted from PRT. Profits
for PRT purposes are calculated on a field-by-field basis by deducting field
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 a deductible for CT purposes. The current
CT rate, which became effective April 1, 1999, is 30 per cent.
On April 17, 2002, the UK Government, in its 2002 budget speech by the UK
Chancellor of the Exchequer, announced changes to taxation policies on UK North
Sea crude oil and natural gas production. A supplementary CT charge of 10 per
cent, charged on the same profits as calculated for `normal' CT but excluding
any deduction for financing costs, was added to the current 30 per
8
cent CT charge. Also the deduction for expenditures on capital items was changed
from 25 per cent per annum to 100 per cent in the year incurred.
Terms of licences, including royalties and taxes payable on production or profit
sharing arrangements, vary by country and in some countries by concession within
each country. For instance, production from the Kiame field, on Block 4 in
Angola, was subject to a 6 per cent royalty on gross income and 50 per cent
Petroleum Income Tax, which equates to 7 per cent calculated on the Company's
gross income. Development of the Espoir field on CI-26, Cote d'Ivoire, 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 (See "Principal Crude Oil and Natural Gas Properties - Offshore West
Africa").
Any changes in government policies or operating environment in the countries
where the Company conducts business could have a significant impact on the
Company's business ventures in such jurisdictions. Risks of foreign operations
include, but are not necessarily limited to, changes of laws affecting foreign
ownership, government participation, taxation, royalties, duties, rates of
exchange, inflation, exchange control, repatriation of earnings and domestic or
international unrest. The effect of changes in any of these factors cannot be
accurately predicted.
COMPETITIVE MATTERS
The crude oil and natural gas industry, domestically and in the international
arena, is highly competitive by nature. The Company must compete with integrated
oil and natural gas companies and independent producers and marketers of crude
oil and natural gas products in all aspects of the Company's business. This
competition extends to exploration, property and asset acquisition and the
selling of the Company's crude oil and natural gas products. The financial
strength of some of the Company's competitors may be greater than that of the
Company.
ENVIRONMENTAL MATTERS
The Company carries out its activities in compliance with all relevant regional,
national and international regulations and best industry practice. 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 reports directly to 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. 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 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 annual environmental compliance audit and
inspection program of our operating facilities; an aggressive 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; progressive due
diligence related to groundwater monitoring; prevention of
9
and reclamation of spill sites, greenhouse gas reduction, and, flaring and
venting reduction. Since 1995, the Company has reduced its greenhouse gas
emissions by more than four million tonnes annually. This represents
approximately 40per cent of Canada's oil and natural gas industry reductions
based on the Canadian Association of Petroleum Producers data. CNRL participates
in Canada's Climate Change Voluntary Challenge & Registry Inc. The Company has
been a Gold Level Reporter since 2000. CNRL continues to invest in proven and
new technologies and in improved operating strategies that will help us achieve
our overall goal of a net reduction of greenhouse gas emissions per unit of
production.
The costs incurred by the Company for compliance with environmental matters and
site restoration costs amount to less than two per cent of the total exploration
and development expenditures incurred by the Company in each of the years ended
December 31, 2002, 2001 and 2000.
DESCRIPTION OF THE BUSINESS
CNRL is a Canadian based senior independent energy company engaged in the
acquisition, exploration, development, production, marketing and sale of crude
oil, natural gas liquids and natural gas. 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 CNRL 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 dominance 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, light oil, Pelican Lake oil, primary heavy oil and thermal heavy
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
49 per cent of 2002 production. Virtually all of the Company's natural gas and
natural gas liquids production is located in the Canadian provinces of Alberta
and British Columbia and is marketed in Canada and the United States. Light oil,
representing 21 per cent of 2002 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 oil operations in the Provinces of Alberta and
Saskatchewan account for 23 per cent of 2002 production. Other heavy oil, which
accounts for 7 per cent of 2002 production, is produced from the Pelican Lake
area in central Alberta. This production, which has medium oil netback
characteristics, is developed through a staged horizontal drilling program.
Midstream assets, comprised of three crude oil pipelines and an electricity
co-generation facility, provide cost effective infrastructure supporting the
heavy and medium oil operations. CNRL expects its ownership of oil sands leases
near Ft. McMurray, Alberta to provide a basis for long-term synthetic oil
production growth.
As a result of the Company's undeveloped land base of 10.2 million net acres in
western Canada, its international concessions and the Alberta oil sands leases,
the Company believes it has sufficient project portfolios in each of the product
offerings to provide growth for the next several years.
10
A. PRINCIPAL CRUDE OIL AND NATURAL GAS PROPERTIES
Set forth below is a summary of the principal crude oil and natural gas
properties as at December 31, 2002. The information is proportionate to the
working interests and royalty interests owned by the Company.
2002 AVERAGE YEAR ENDED
DAILY DECEMBER 31, WELLS DRILLED IN 2002 INFRASTRUCTURE
PRODUCTION RATES 2002 AS AT DECEMBER 31, 2002
------------------ ---------------- ---------------------- --------------------------------
Oil/Natural Batteries/
Gas/D&A Comppressors &
OIL & NATURAL UNDEVELOPED (excludes Pipeline plants/
NGLs GAS ACREAGE stratigraphic test & (thousand Platforms
REGION Mbbls MMcf (thousands) service wells) miles) /FPSO
NORTH AMERICA
Northeast B. C. 7.4 450.6 1,513 2.1 /40.2/ 4.4 2.0 8/ 71/ -/ -
Northwest Alberta 6.6 171.2 1,821 2.1 / 7.5/ 3.0 1.8 7/ 24/ -/ -
North Alberta 135.9 419.8 5,935 246.0 /62.4/ 15.0 8.2 23/ 102/ -/ -
Horizon Oil Sands - - 117 - / -/ - - -/ -/ -/ -
South Alberta 9.0 145.8 666 1.0 /51.6/ 2.5 2.6 32/ 27/ -/ -
Southeast 9.4 3.2 161 4.3 / -/ 1.0 - 35/ -/ -/ -
Saskatchewan
Non - core areas 1.4 13.3 1,940 0.7 / -/ - - - /- /- /
-
INTERNATIONAL
North Sea 38.8 27.1 410 4.9 / -/ - 0.1 -/ -/ 4/ 1
Offshore West
Africa
Angola 0.8 - 610 - / -/ 0.3 - - /- /- /
-
Cote d'Ivoire 6.0 1.3 333 2.4 / -/ 1.2 - -/ -/ -/ 1
---------------------------------------------------------------------------------------------------------------------
TOTAL 215.3 1,232.3 13,506 263.5 /161.7/ 27.4 14.7 105/ 224/ 4/ 2
---------------------------------------------------------------------------------------------------------------------
Set forth below is a summary of the number of gross and net wells within the
Company that are producing as of December 31, 2002:
------------------------- ----------------------------- ------------------------------ ------------------------------
JURISDICTION NATURAL GAS WELLS OIL WELLS TOTAL WELLS
GROSS NET GROSS NET GROSS NET
------------------------- -------------- -------------- --------------- -------------- --------------- --------------
NORTH AMERICA
British Columbia 790 685.8 276 242.1 1,066 927.9
Alberta 7,216 6,574.4 5,883 5,555.9 13,099 12,130.3
Saskatchewan 526 513.6 1,659 1,408.1 2,185 1,921.7
Manitoba - - 112 108.2 112 108.2
Northwest Territories 3 - - - 3 -
INTERNATIONAL
North Sea - - 162 130.3 162 130.3
Offshore West Africa
Angola - - - - -
Cote d'Ivoire - - 7 4.1 7 4.1
------------------------- -------------- -------------- --------------- -------------- --------------- --------------
TOTAL 8,535 7,773.8 8,099 7,448.7 16,634 15,222.5
------------------------- -------------- -------------- --------------- -------------- --------------- --------------
11
NORTHEAST BRITISH COLUMBIA
This region comprises lands from south of Fort St. John, British Columbia to the
northern border of British Columbia. Similar geological attributes extend
throughout the region, producing light oil, natural gas liquids and natural gas.
The Company holds working interests ranging up to 100 per cent and averaging 76
per cent in 2,703,335 gross acres (2,053,145 net) of producing and undeveloped
land in the region.
Crude oil reserves are found primarily in the Halfway or lower Halfway
formation, while natural gas and associated natural gas liquids are found in
numerous zones at depths reaching approximately 2,000 vertical meters. In the
southern portion of the region, the Company owns natural gas producing and
undeveloped lands in which the productive zones are at depths up to 3,500
meters. The exploration strategy focuses on comprehensive evaluation through
two-dimensional seismic, three-dimensional seismic and targeting economic
geological areas close to existing infrastructure. Applying under-balanced,
multi-leg horizontal drilling has also proven highly effective in this region.
Natural gas production from the region averaged 450.6 million cubic feet per day
for 2002, an increase of 42 per cent from the average of 317.5 million cubic
feet per day produced for 2001. Crude oil and natural gas liquids production
decreased to 7.4 thousand barrels per day in 2002 from an average of 9.2
thousand barrels per day in 2001.
This region contains the Ladyfern Slave Point natural gas pool, which is
estimated to contain between 660 and 680 billion cubic feet of natural
gas-in-place. During 2001, the Company drilled 8 net natural gas wells in the
area with a total production capability of over 600 million cubic feet per day.
Prior to the first quarter of 2002, production from the area had been restricted
due to insufficient processing facilities and pipelines with production exiting
2001 at approximately 150 million cubic feet per day. In the first quarter of
2002, additional facilities were constructed which enabled the Company to
increase production to approximately 210 million cubic feet per day in June
2002. Commencing in late August 2002, water encroachment resulted in the start
of significant declines from the pool. At the end of 2002, production, net to
the Company, was at 100 million cubic feet per day with expectations for 2003 to
exit at approximately 25 million cubic feet per day. The Ladyfern field is not
representative of typical natural gas pools both due to its overall size and its
production profile of very high production volumes with a very rapid decline.
Typical natural gas decline rates approximate 23 per cent for other natural gas
fields owned by the Company.
Through the acquisition of Ranger in 2000, the Company acquired an interest and
operatorship in extensive acreage adjacent to the northern border of this
region. A further acquisition in the fourth quarter of 2001 resulted in the
Company obtaining 100 per cent ownership in its producing natural gas assets and
undeveloped land in the Helmet area of the region. Ranger had drilled a number
of producing natural gas wells on the acreage. Further development of this
acreage will be enhanced through the facilities and infrastructure owned by the
Company in the region. Having identified optimal drilling strategies in the
region, Canadian Natural plans a multi-well annual drilling program commencing
in 2003.
During 2002 the Company drilled 2.1 (2001- 6.1) net oil wells, 40.1 (2001 -
68.3) net natural gas wells, 1.0 (2001 - 0.0) service wells and 4.4 (2001 - 6.0)
net abandoned wells on its lands in this region for a total of 47.6 (2001 -
80.4) net wells. The Company held an average 93 per cent working interest in
these wells. The Company owns and operates significant production facilities in
this region as noted above. Interests are also owned in additional facilities
operated by other industry participants. All of the facilities are in close
proximity to sales facilities.
12
NORTHWEST ALBERTA
The Company holds working interests ranging up to 100 per cent and averaging 82
per cent in 2,733,501 gross (2,252,967 net) acres of producing and undeveloped
land in the region.
The majority of the Company's holdings in the region were obtained through the
Plan of Arrangement in 2002, which facilitated the acquisition of RAX. This
region contains exceptional exploration and exploitation opportunities as well
as substantial available capacity within an extensively 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 1,000 to 4,500 metres. The northern portion of this core region
provides extensive multi-zone Cretaceous opportunities similar to the geology of
the Company's North Alberta core region. The southern portion provides a
significant opportunity in the regionally extensive Cretaceous Cardium zone. The
Cardium is a complex, tight natural gas reservoir where high productivity can be
achieved due to greater matrix porosity or natural fracturing. Canadian Natural
has chosen to pursue a modest 2003 development plan in this region so that
detailed geological, geophysical and engineering work can be completed and
interpreted.
Natural gas production from the region averaged 171.2 million cubic feet per day
for 2002, an increase of 237 per cent from the average of 50.8 million cubic
feet per day for 2001. Crude oil and natural gas liquids production increased to
6.6 thousand barrels per day in 2002 from 1.4 thousand barrels per day in 2001.
During 2002 the Company drilled 2.1 (2001-2.0) net oil wells, 7.5 (2001-5.8) net
natural gas wells, and 3.0 (2001-3.5) net abandoned wells on its lands in this
region for a total of 12.6 (2001-11.3) net wells. The Company held an average 79
per cent working interest in these wells. The Company owns and operates
significant production facilities in this region as noted above, many of which
have significant excess capacity, providing for cost effective future expansion
of operations. All of the facilities are in close proximity to sales facilities.
NORTH ALBERTA
The Company holds working interests ranging up to 100 per cent and averaging 82
per cent in 9,845,501 gross (8,117,571 net) acres of producing and undeveloped
land in the region. The region comprises lands located from townships 33 to 101
and west from Range 17 W 3 meridian in Saskatchewan to Range 10 W 5 meridian in
Alberta.
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, natural gas liquids and light oil are also
encountered at slightly deeper 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 419.8 million cubic feet per day in 2002 compared
to 357.0 million cubic feet per day in 2001. Crude oil and natural gas liquids
production from this region decreased to 135.9 thousand barrels per day in 2002
from 141.2 thousand barrels per day in 2001.
In the area near Lloydminster, Alberta, reserves of heavy oil (averaging
12(Degree) - 14(degree) 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 oil to the
wellbore in this type of heavy oil reservoir comes from solution gas. The oil
viscosity and the reservoir quality will determine the amount of crude oil
produced from the reservoir, which will vary from three to twenty per cent. A
key component to maintaining profitability in
13
the production of heavy oil is to be a low cost producer. The Company continues
to achieve low costs by holding a dominant position that includes a significant
land base and an extensive infrastructure of batteries and disposal facilities.
The price received for heavy oil is discounted from the benchmark WTI price and
during the last quarter of 2000, this differential widened to historically high
levels. As a result, the Company took a proactive stance and consciously reduced
the number of heavy oil wells drilled in 2001, reduced heavy oil production by
15 thousand barrels per day beginning December 2001 and changed the steaming
pattern at its Primrose facility. The heavy oil differential, as expected,
narrowed to more historical levels, allowing the Company to bring most of this
production back on-line and expand 2002 drilling programs. The Company continues
to monitor this market and work on strategies to eliminate some of the
uncertainty surrounding this commodity pricing.
Ranger owned significant land and production in this region, with much of its
land being contiguous to CNRL holdings. With the operations combined, future
development of the total lands in the region became more effective and provides
opportunities for cost savings. As part of the acquisition of Ranger, the
Company also acquired a 50 per cent interest in the ECHO Pipeline system, a
crude oil transportation pipeline; and, in 2001 the Company acquired the
remaining 50 per cent. The pipeline was extended to the Beartrap field during
2001, enhancing further development of the Company's extensive holdings in the
area. This pipeline is capable of transporting 57 thousand barrels per day of
hot unblended crude oil to sales facilities at Hardisty, Alberta. With minor
upgrades, its capacity can be expanded to handle up to 72 thousand barrels per
day. 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. The ECHO Pipeline system,
together with other midstream assets in which the Company has partial interests,
permits CNRL to transport in excess of 80 per cent of its heavy oil to the
international mainline liquids pipelines. This transportation control enhances
the Company's ability to control the full spectrum of costs associated with the
development and marketing of its heavy oil.
Production from the Primrose and Wolf Lake fields located near Bonnyville,
Alberta involves processes that utilize steam to increase the recovery of the
oil. The two processes employed by the Company are cyclic steam stimulation and
SAGD. Both recovery processes inject steam to heat the heavy oil deposits,
reducing the oil viscosity and therefore improving its flow characteristics.
There is also an infrastructure of gathering systems, a processing plant with a
capacity of 60 thousand barrels per day and a 50 per cent interest in a
co-generation facility capable of producing 84 megawatts of electricity for the
Company's use or sale into the Alberta power grid at pool prices. In 2000, the
Company successfully converted and tested two existing pads of wells from
low-pressure steaming to high-pressure steaming. This conversion increased
average production at the 20 existing wells from 100 to 190 barrels of crude oil
per day per well. An additional 24 wells were drilled using the high-pressure
steam process with initial production averaging 600 barrels of crude oil per day
per well. These results have confirmed the benefits of converting the Primrose
field to high-pressure steaming. In 2001, the Company received regulatory
approval to convert an additional six low-pressure cyclic pads to high-pressure
cyclic pads, and in 2002 received approval to take high-pressure steam
methodologies throughout the field. Canadian Natural plans to drill 48
high-pressure wells in 2003, which will increase field production commencing in
2004. Additional development of the leases will be undertaken in phases over the
next several years. A successful SAGD heavy oil project in which the Company
holds a 50 per cent interest is also in operation in the Saskatchewan portion of
this region.
14
Included in the northern part of this region, approximately 200 miles north of
Edmonton, are the Company's 100 per cent-owned holdings at Pelican Lake. These
lands contain reserves of 14(Degree)-17(Degree) API heavy oil. Operating costs
are low due to no sand production or disposal requirements, the gathering and
pipeline facilities in place and negligible water production and disposal. 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 future economic development of the large crude
oil pool located on the lands. In the first quarter of 2001, the Company added
to its holdings in this area through the acquisition of additional producing
lands from another industry participant. Following this acquisition, the Company
holds and controls in excess of 80 per cent of the known crude oil pool in this
area.
This field contains approximately three billion barrels of original oil-in-place
but is only expected to achieve a 6 per cent recovery factor using primary
technologies. Hence, in 2002 the Company embarked upon an Enhanced Oil Recovery
("EOR") scheme to increase the ultimate recoveries from the field. The
experimental Pelican Lake emulsion flood continues, with injection since early
April 2002. Indications to date suggest that the recovery mechanism is very
efficient, however response time is slow. Canadian Natural will be working to
increase the financial returns on the EOR scheme by finding the optimal balance
between response time and recovery factors. To this end, an observation well
will be drilled in the first quarter of 2003 to assess the effectiveness of the
injection to date. The Company will also be implementing a demonstration scale
waterflood project to evaluate this secondary recovery technique, which should
increase response time, but at the expense of overall recovery factors. If
either project is successful or a combination thereof, the recovery factor from
the thin Pelican Lake sands will substantially increase.
During 2002, the Company drilled 62.4 (2001 - 111.2) net natural gas wells,
246.0 (2001 - 210.6) net oil wells, 148.5 (2001 - 79.5) net stratigraphic tests
wells, 2.5 services wells (2001 - 15.0) and 15.0 (2001 - 21.8) net wells that
were abandoned for a total of 474.4 (2001 - 438.1) net wells. The Company's
average working interest in these wells was in excess of 93 per cent. The
Company operates and owns significant infrastructure in the region as shown
above and has additional interests in plants and compressors in the region,
which are operated by other companies.
HORIZON OIL SANDS PROJECT
The Company holds 100 per cent working interest in 116,596 gross acres located
in this region comprising the Horizon Oil Sands Project ("the Horizon Project").
During 2001, the Company filed a public disclosure document as the initial step
in making application to obtain regulatory approval for a long-term oil sands
project that has four components: surface mining and bitumen processing, in-situ
operations, an upgrader and associated infrastructure. The first phase of the
front-end engineering work on the Horizon Project has been completed. Regulatory
submissions, including an environmental Impact Assessment and Project
Description were completed and filed in June 2002. Following filing for
regulatory approvals, the Company commenced the Design Basis Memorandum, which
is the second of the three phases of engineering design work, and is expected to
be completed by the beginning of the second quarter of 2003.
Due to the uncertainty of the impact of the Kyoto Protocol on the Horizon
Project, the Company delayed the start-up of the Engineering Design
Specification ("EDS") phase of engineering and reduced its 2003 capital budget
for the Horizon Project from $300 million to $211 million. Canadian Natural
believes that certainty of long-term economic consequences of the Kyoto Protocol
on the Horizon Project is required prior to the final commitment for an
investment as
15
large as the Horizon Project. Recently the Federal Government has provided some
limits to the cost of Kyoto implementation through 2012; however, beyond 2012 no
implementation certainty exists. As the Horizon Project is scheduled to commence
production in 2008 and produce for over 40 years, the lack of clarity on Kyoto
implementation over the long term precludes Canadian Natural's ability to commit
to the construction of the Horizon Project at this time. Although a sufficient
level of implementation certainty to start construction does not exist today,
Canadian Natural anticipates such levels of certainty will be achieved, and
therefore has decided to continue with the EDS phase of engineering. The EDS
will commence in July of 2003 with related 2003 expenditures included in the
Company's current Horizon Project budget of $211 million.
Canadian Natural anticipates receiving regulatory approvals for the Horizon
Project from the Energy and Utilities Board in late 2003. The Company would be
in a position to commence site clearing and pre-construction in 2004, with full
construction commencing upon achieving a targeted 80 per cent completion of
detailed engineering and design. The Company expects that the first phase of the
Horizon Project would then be commissioned in 2008 at 110 thousand barrels per
day of light synthetic crude oil. The Company expects that phase two would be
commissioned in 2010, increasing production to 155 thousand barrels per day of
production. The Company expects that phase three would be completed in 2012,
bringing total production to 232 thousand barrels per day. The Company's leases
could support further expansions beyond that date.
No decision has been made on whether to proceed with the construction of the
Horizon Project in 2004. If a decision is made to commence construction, the
Company will then evaluate and choose between two potential approaches: (i)
completion of the Horizon Project in Ft. McMurray, with the $3 billion upgrader
on-site; or (ii) completion of the Horizon Project in Ft. McMurray, with
secondary upgrading facilities relocated to the U.S. By relocating these
facilities to the U.S., a degree of certainty on costs of Kyoto implementation
for the Horizon Project could be obtained.
Total expected capital costs of the Horizon Project are $8.0 billion to $8.4
billion, with approximately $4.5 billion to $5.0 billion required to bring the
first phase on line and are consistent with the final cost estimates for other
recent oil sands mining projects.
The project will provide for a potential recovery of 6 billion barrels of
bitumen over an estimated 40-year life span. No reserves from these leases are
included in the Company's current reserves of crude oil and natural gas liquids.
During 2002, the Company drilled 293 (2001 - 257) stratigraphic test wells to
further delineate the ore body and confirm resource quality and quantity.
SOUTH ALBERTA
The Company holds interests ranging up to 100 per cent and averaging 81 per cent
in 1,573,216 gross (1,279,609 net) acres of producing and undeveloped land in
the region.
Reserves of natural gas, condensate and light and medium 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 year
round. With a higher sales price for natural gas, it is economic to
16
drill shallow wells in closer proximity to each other, which may have smaller
overall reserves and lower productivity per well but will achieve a high return
on capital employed.
The Company's share of production averaged 9.0 (2001 - 6.7) thousand barrels of
crude oil and natural gas liquids per day and 145.8 (2001- 162.3) million cubic
feet of natural gas per day in 2002.
During 2002, the Company drilled a total of 1.0 (2001 - 5.0) net oil wells, 51.6
(2001 - 289.9) net natural gas wells and 2.5 (2001 - 0.0) net abandoned wells in
this region for a total of 55.1 (2001 - 294.9) net wells. The Company's average
working interest in these wells is 92 per cent. The wells are predominantly in
areas where the Company already has gathering and processing facilities as noted
above.
SOUTHEAST SASKATCHEWAN
The Williston Basin is located in Southeastern Saskatchewan with lands extending
into Manitoba and North Dakota. This region was owned by Sceptre and became a
core region of the Company in mid 1996 with the acquisition of Sceptre. The
Company holds interests ranging up to 100 per cent and averaging 80 per cent in
281,889 gross (226,247 net) acres of producing and undeveloped lands in the
region.
The region produces primarily light sour crude oil from as many as seven
productive horizons found at depths up to 2,700 meters. During 2002, net
production to the Company averaged 9.4 thousand barrels of crude oil per day
compared to an average of 6.5 thousand barrels of crude oil per day in 2001.
The Company drilled 4.3 (2001 - 4.0) net oil wells and 1.0 (2001 - 0.0) net
abandoned wells in this region in 2002 for a total of 5.3 (2001 - 4.0) net
wells. The Company's average working interest in these wells is 53 per cent.
These wells included a number of horizontal wells that further developed the
existing known pools of crude oil in the Company's lands.
NORTH SEA
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 per cent up to 100
per cent in 839,138 gross (465,619 net) acres of producing and non-producing
acreage in the UK sector of the North Sea. In 2002, the Company produced from 12
crude oil fields. The most northerly fields are centered around the Ninian field
where the Company has a 73.2 per cent working interest. The central processing
facility is connected to other fields including the Columba fields where the
Company operates with working interests of 85.8 per cent to 90.7 per cent. In
2002, the Company completed property acquisitions in the northern North Sea that
increased ownership levels in the Ninian, Murchison, Lyell and Columba Terraces
fields. The Company is now the operator on each of these fields. As part of the
transaction the Company also acquired an interest in the Strathspey field and 12
licenses 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. Ownership and operatorship levels
in the North Sea are now similar to those levels found throughout the Company's
other worldwide operations. The Company also receives tariff revenue from other
operators for the transportation and processing of crude oil and natural gas
17
through the processing facilities. Opportunities for further long reach well
development on adjacent fields are provided from the existing processing
facilities.
In the central portion of the North Sea, the Company owns a 55.9 per cent
working interest in the Banff field and a 45.7 per cent operated working
interest in the Kyle field. Production at the Banff field was temporarily
curtailed in September 2000 while the owners of the FPSO removed the vessel from
the field to make repairs and modifications. Production resumed from the field
in 2001. At the Kyle field the Company drilled one additional well and during
the summer of 2000 produced this well on an extended well test to confirm
reservoir quality. A third well was drilled, tested and connected to production
facilities in 2001, with a fourth well drilled and tied in during 2002. The
wells at Kyle are tied into a Company operated FPSO, which the Company took over
operatorship of in 2001, located at the Curlew field.
For 2003, the Company budgeted to spend a total of $281.0 million on its
international holdings in the U. K. sector of the North Sea. These funds will be
directed towards drilling an additional 17 wells in the northern North Sea and
one additional well in the central North Sea. Other exploitation and waterflood
optimization programs will also be carried out in both areas to increase the
productivity and recovery factors in these known pools of light oil.
During 2002, production to the Company from this region averaged 38.8 (2001 -
36.3) thousand barrels of crude oil per day and 27.1 (2001 - 12.0) million cubic
feet of natural gas per day. The Company drilled 4.9 (2001 - 2.2) net oil wells,
1.2 (2001 - 0.6) net service wells and 0.0 (2001 - 0.2) net abandoned wells in
2002 in this region for a total of 6.1 (2001 - 3.0) net wells. The Company's
average working interest in these wells is 41 per cent.
OFFSHORE WEST AFRICA
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. The Company owns working interests ranging from 25 per cent
to 100 per cent in 2,885,571 gross (1,253,513 net) acres in this region.
COTE D'IVOIRE
The Company owns interests in five exploration licences offshore Cote d'Ivoire
comprising 798,403 net acres. During 2001, the Company increased its interest in
Block CI-26, which contains the Espoir crude oil and natural gas field, to a 59
per cent operating interest. The Espoir field is located in water depths ranging
from 100 to 700 meters. During the 1980s, the Espoir field produced 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 development of East Espoir,
which includes the drilling of both producing and water injection wells from a
single wellhead tower, is continuing and development of the West Espoir field
will proceed after full development of East Espoir. Using an FPSO with a
capacity of 40 thousand barrels of crude oil per day, crude oil production
commenced in the first quarter of 2002 at an initial rate of 8.5 thousand
barrels of crude oil per day from one producing well. A subsea pipeline has been
constructed for the delivery of associated natural gas to onshore Cote d'Ivoire
where it will be sold to local power producers. Production continued at the end
of 2002 from three producing wells and two water injection wells. Unanticipated
uphole faults encountered in the drilling of a well, which was spud August 2002
has resulted in drilling program delays. The offshore development will continue
with two water injection wells and one producing well scheduled for drilling at
East Espoir during the first half of 2003. These injectors will enhance the
build up of pressures in the upper zones of the oil reservoir, which is
scheduled
18
for perforation by mid-2003, providing up to 5 thousand barrels per day of
additional net production. During December 2002 a satellite pool, Emien, was
drilled, but encountered no hydrocarbons. The Company anticipates drilling a
second, larger satellite pool, Acajou, during the first half of 2003.
In the first quarter of 2001, the Company drilled and tested the Baobab
exploration prospect, identified on Block CI-40, in which the Company has a 61
per cent interest, eight kilometres south of the Espoir facilities. The well
encountered hydrocarbons at a rate of 6.7 thousand barrels of crude oil per day.
A second test well in 2002 also produced hydrocarbons at a rate in excess of 10
thousand barrels of crude oil per day, leading the Company to declare the
prospect commercial. The development continues for first oil planned at initial
production rates of 45 thousand barrels per day in 2005, increasing with full
development to 60 thousand barrels per day. Several components of the subsea
infrastructure and the floating production storage and offtake vessel are
currently out to bid. This field contains approximately 200 million barrels of
recoverable reserves and is operated and 61per cent owned by Canadian Natural.
Field development plans were approved by the Government in December 2002.
Seismic surveys have been acquired on the other Cote d'Ivoire blocks and leads
or prospects identified.
Political unrest 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 another nearby country if the situation warrants such a move.
The Company's 2003 expenditure budget forecasts expenditures totaling $280
million in offshore West Africa. Expenditures in Cote d'Ivoire of approximately
$220 million will result in finalization of drilling and completion operations
at Espoir, an exploration well at Acajou and finalization of development plans
at Baobab.
During 2002, the Company drilled 2.4 (2001 - 1.2) net oil wells, 0.6 (2001 -
0.6) net service wells and 1.2 (2001 - 0.0) net abandoned wells for a total of
4.2 (2001 - 1.8) net wells. The Company's average working interest in these
wells is 61 per cent.
ANGOLA
During 2002, Canadian Natural was awarded operatorship and a 50 per cent working
interest in exploration Block 16 situated offshore The People's Republic of
Angola. Canadian Natural obtained 3-D seismic over the entire Block 16 before
obtaining title and has already identified two targets, Omba in the north and
Zenza in the west central portion of the Block. The Company has a two well
commitment over a four year time frame expiring August 31, 2006 and currently
expects to drill the first of the prospects, Zenza, during the fourth quarter of
2003.
The Company also owned 100 per cent of and operated the offshore Kiame field.
The field produced from June 1998 to April 2002 through a leased FPSO. The field
reached its economic limit of production and production ceased in April 2002.
The Company also had a 25 per cent non-operating interest in Block 19, a 1.2
million-acre block, which lies in water depths of 300 to 1,800 meters. A 2,500
square kilometre 3-D seismic survey was completed in 1999. After interpretation
of the seismic and drilling of a 25 per cent interest well in 2002 on Block 19,
the Company determined the block was not economic to develop and relinquished
its license on the block.
19
B. CRUDE OIL AND NATURAL GAS RESERVES
The Company retains independent petroleum engineering consultants Sproule
Associates Limited ("Sproule") to evaluate the Company's proved and probable
crude oil and natural gas reserves and prepare an evaluation report on the
Company's total reserves ("Evaluation Report"). For the year ended December 31,
2002, the Evaluation Report includes 89 per cent of the Company's reserves
evaluated by Sproule and the remaining 11 per cent internally evaluated by the
Company. The Company has retained Sproule since 1989 to evaluate its assets.
The Board of Directors' Reserves Committee meets with Sproule on a regular basis
and at such times carried out independent due diligence procedures with Sproule
as to the Company's reserves.
The following tables summarize the evaluations of reserves and estimated future
net production revenues at December 31, 2002.
THE ESTIMATED FUTURE NET REVENUES 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 PRESENT WORTH OF ALL PROBABLE RESERVES HAS BEEN REDUCED
BY 50 PER CENT TO ACCOUNT FOR RISK. THE ESTIMATED FUTURE NET REVENUES DERIVED
FROM THE ASSETS TAKE INTO ACCOUNT THE EFFECT OF ARTC, PROCESSING REVENUES AND
CORPORATE CAPITAL GAS COST ALLOWANCE BUT ARE PREPARED PRIOR TO CONSIDERATION OF
INCOME TAXES AND ABANDONMENT LIABILITIES. 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 ESCALATED CASES WILL BE ATTAINED AND
VARIANCES COULD BE SUBSTANTIAL.
CRUDE OIL, NGL AND NATURAL GAS RESERVES
ESCALATED PRICES AND COSTS
---------------------------------------------------------------------------------------------
GROSS GROSS
CRUDE OIL & NGL RESERVE NATURAL GAS RESERVE
VOLUMES (MMbbls) VOLUMES (Bcf)
-------------------------------------------- --------------------------------------------
By Jurisdiction PROVED PROBABLE TOTAL PROVED PROBABLE TOTAL
RESERVES RESERVES RESERVES RESERVES RESERVES RESERVES
NORTH AMERICA
Canada 665 77 742 3,046 401 3,447
United States - - - 2 1 3
INTERNATIONAL
United Kingdom 200 73 273 71 18 89
Cote d'Ivoire 96 70 166 90 31 121
Angola - - - - - -
-------------- -------------- ------------ ------------ -------------- --------------
TOTAL 961 220 1,181 3,209 451 3,660
============== ============== ============ ============ ============== ==============
20
CRUDE OIL, NGL AND NATURAL GAS RESERVES
ESCALATED PRICES AND COSTS
------------------------------------------------------------------------
CRUDE OIL AND NATURAL
GAS LIQUIDS (MMbbls) NATURAL GAS (Bcf)
-------------------------------- ------------------------------------
GROSS NET GROSS NET
----- --- ----- ---
Proved developed producing 459 412 2,607 2,107
Proved developed non-producing 74 66 203 166
Proved undeveloped 428 389 399 324
Total proved reserves 961 867 3,209 2,597
Probable reserves 220 194 451 359
-------------- -------------- --------------- ---------------
Total proved and probable reserves 1,181 1,061 3,660 2,956
============== ============== =============== ===============
ESTIMATED FUTURE NET REVENUES
($ Millions) ESCALATED PRICES AND COSTS
-------------------------------------------------------------------------
UNDISCOUNTED DISCOUNTED AT
----------------- ----------------------------------------------------
10% 15% 20%
--- --- ---
Proved developed producing $15,776 $9,880 $8,535 $7,581
Proved developed non-producing 1,711 1,087 927 810
Proved undeveloped 4,452 1,811 1,265 912
Total proved reserves 21,939 12,778 10,727 9,303
Probable reserves 2,193 1,038 780 608
-------------- -------------- --------------- ---------------
Total proved and probable reserves $24,132 $13,816 $11,507 $9,911
============== ============== =============== ===============
CRUDE OIL, NGL AND NATURAL GAS RESERVES
CONSTANT PRICES AND COSTS
--------------------------------------------------------------------
CRUDE OIL AND NATURAL
GAS LIQUIDS (MMbbls) NATURAL GAS (Bcf)
------------------------------- ---------------------------------
GROSS NET GROSS NET
----- --- ----- ---
Proved developed producing 459 407 2,608 2,105
Proved developed non-producing 76 67 202 164
Proved undeveloped 427 374 399 319
Total proved reserves 962 848 3,209 2,588
Probable reserves 219 186 450 356
-------------- -------------- --------------- ---------------
Total proved and probable reserves 1,181 1,034 3,659 2,944
============== ============== =============== ===============
ESTIMATED FUTURE NET REVENUES
($Millions) CONSTANT PRICES AND COSTS
--------------------------------------------------------------------
UNDISCOUNTED DISCOUNTED AT
---------------- ------------------------------------------------
10% 15% 20%
--- --- ---
Proved developed producing $21,752 $13,881 $11,946 $10,553
Proved developed non-producing 2,509 1,604 1,360 1,180
Proved undeveloped 8,297 3,850 2,871 2,220
Total proved reserves 32,558 19,335 16,177 13,953
Probable reserves 3,267 1,630 1,249 991
-------------- ----------------- --------------- ---------------
Total proved and probable reserves $35,825 $20,965 $17,426 $14,944
============== ================= =============== ===============
21
NOTES
1. "Gross" reserves means the total working and royalty interest share of
remaining recoverable reserves owned by the Company before deduction of
royalties payable to others.
2. "Net" reserves mean the Company's gross reserves less all royalties
payable to others.
3. "Proved developed producing" reserves are those proved reserves that
are presently being produced from completion intervals open for
production in existing wells with existing equipment and operating
methods.
4. "Proved developed non-producing" reserves are those proved reserves
which are currently not being produced but do exist in completed
intervals but not producing in existing wells, behind casing in
existing wells or at minor depths below the present bottom of existing
wells. These proved reserves are expected to be produced through the
existing wells in the predictable future and are classified as proved
developed since the cost of making such reserves available for
production is relatively small, compared to the cost of a new well.
5. "Proved undeveloped" reserves are those proved reserves that 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.
6. "Proved" reserves are those quantities of crude oil, natural gas and
natural gas liquids, which, upon analysis of geologic and engineering
data, appear with a high degree of certainty to be recoverable at
commercial rates in the future from known crude oil and natural gas
reservoirs under presently anticipated economic and operating
conditions for the escalated prices and costs case and under existing
economic and operating conditions for the constant prices and costs
case.
7. "Probable" reserves are those reserves which may be recoverable as a
result of the beneficial effects which may be derived from the future
institution of some form of pressure maintenance or other secondary
recovery method, or as a result of a more favourable performance of the
existing recovery mechanism than that which would be deemed proved at
the present time, or those reserves which may reasonably be assumed to
exist because of geophysical or geological indications and drilling
done in regions which contain proved reserves. THE ESTIMATED FUTURE NET
REVENUES OF THE PROBABLE RESERVES SET FORTH ABOVE HAVE BEEN RISK
WEIGHTED BY 50 PER CENT TO ACCOUNT FOR THE PROBABILITY OF OBTAINING
PRODUCTION FROM SUCH RESERVES.
8. Canadian securities legislation and policies permit the disclosure,
which is included or incorporated by reference herein under a
multi-jurisdicitional disclosure system adopted by the SEC, of probable
reserves which may not be disclosed in registration statements
otherwise filed with the SEC. 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.
9. All values are shown in Canadian dollars.
10. The escalated 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 of reserves and contract
conditions. Subsequent to 2014, reference prices and costs are
escalated at 1.5 per cent per year. Future crude oil, natural gas
liquids and natural gas price forecasts were based on Sproule's January
1, 2003 crude oil, natural gas liquids and natural gas pricing model.
The principal crude oil and natural gas price forecasts used in the
Evaluation Reports are as follows:
NATURAL GAS CRUDE OIL & NGLs
------------------------------------------------ ---------------------------------------------------
WTI @
COMPANY BRITISH COMPANY HARDISTY EDMONTON NORTH
AVERAGE HENRY HUB COLUMBIA AVERAGE CUSHING HEAVY PAR SEA
PRICE LOUISIANA AECO PLANTGATE PRICE (i) 12(DEGREE)API (ii) BRENT
YEAR $CDN/MCF $US/MMBTU $CDN/MMBTU $CDN/MMBTU $CDN/BBL $US/BBL $CDN/BBL $CDN/BBL $US/BBL
---- -------- --------- ---------- ---------- -------- ------- -------- -------- -------
2003 5.73 4.39 5.89 5.94 30.59 25.99 25.92 38.43 24.49
2004 5.22 4.05 5.38 5.43 27.91 23.60 23.78 34.82 22.08
2005 4.62 3.61 4.77 4.82 25.18 21.63 21.16 32.22 20.09
2006 4.31 3.40 4.45 4.48 25.48 21.96 21.83 32.78 20.39
2007 4.46 3.45 4.61 4.66 26.22 22.29 22.89 33.90 20.70
2008 4.52 3.50 4.67 4.74 26.55 22.62 23.38 34.42 21.01
2009 4.67 3.56 4.86 4.93 27.25 22.96 24.47 35.58 21.32
2010 4.77 3.61 4.94 5.01 27.53 23.31 24.98 36.13 21.64
2011 4.87 3.66 5.03 5.10 27.75 23.66 25.50 36.69 21.97
2012 4.96 3.72 5.13 5.20 27.89 24.01 26.03 37.26 22.30
2013 5.06 3.77 5.22 5.29 28.45 24.37 26.57 37.83 22.63
2014 5.16 3.83 5.31 5.38 29.18 24.74 27.11 38.42 22.97
(i) "WTI @ Cushing" refers to the price of West Texas Intermediate
crude oil at Cushing, Oklahoma.
22
(ii) "Edmonton Par Price" refers to the price of light gravity (40
(degree)API), low sulphur content crude oil at Edmonton,
Alberta.
11. Product prices in the constant price evaluation are those in effect at
the end of the year adjusted for the average light oil to heavy oil
differential used for 2003 in the escalated price evaluation. 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 not been escalated beyond 2003. In
addition, operating and capital costs have not been increased on an
inflationary basis.
12. Estimated future net revenue from all assets is income derived from the
sale of net reserves of crude oil, natural gas and natural gas liquids,
less all capital costs, production taxes, and operating costs and
before provision for income taxes, administrative overhead costs and
abandonment liabilities.
13. The estimated total capital costs net to the Company necessary to
achieve the estimated future net proved and risked weighted probable
production revenues are:
ESCALATED PRICE CASE CONSTANT PRICE CASE
($Millions) ($Millions)
----------- -----------
2003 648 641
2004 965 930
2005 359 337
2006 291 268
2007 150 136
2008 218 198
2009 130 115
2010 58 49
2011 180 157
2012 50 41
Thereafter 288 237
----- -----
3,337 3,109
===== =====
14. Estimated future net revenue includes the ARTC which, in both the
escalated and constant price case, is estimated to be $24.0 million
undiscounted and $5.2 million, $3.6 million and $2.7 million discounted
at 10%, 15% and 20% respectively.
15. Estimated future net revenue includes the value of the Company's
Corporate Capital GCA - Alberta Crown Credits which, in both the
escalated and constant price case is estimated to be $204.1 million
undiscounted and $158.7 million, $143.1 million and $130.5 million
discounted at 10%, 15% and 20% respectively.
16. Estimated future net revenue includes the value of the Company's
midstream assets which is estimated to be $573.4 million undiscounted
and $286.7 million, $225.1 million and $184.9 million in the escalated
price case discounted at 10%, 15% and 20% respectively. In the constant
price case the value of the Company's midstream assets is estimated to
be $621.4 million undiscounted and $300.1 million, $233.4 million and
$190.5 million discounted at 10%, 15% and 20% respectively.
17. The Evaluation Report was based upon data supplied by the Company with
respect to quality and heating value adjustments, interests owned,
royalties payable, operating costs and contractual commitments. No
field inspection was conducted.
23
C. RECONCILIATION OF CHANGES IN RESERVES
The following table summarizes the changes in reserves before deduction of
royalties payable to others during the past year:
----------------------------------------------- ------------------------------------------------
CRUDE OIL AND NATURAL GAS LIQUIDS (MMbbls) NATURAL GAS (Bcf)
OFFSHORE OFFSHORE
NORTH NORTH WEST NORTH NORTH WEST
AMERICA SEA AFRICA TOTAL AMERICA SEA AFRICA TOTAL
----------- ----------- ----------- ----------- ------------ ----------- ----------- -----------
PROVED RESERVES
Reserves, December 31, 2001 644 85 61 790 2,566 94 69 2,729
Extensions and discoveries 31 1 18 50 132 0 5 137
Property purchases 51 112 0 163 872 18 0 890
Property disposals (1) (18) 0 (19) (4) (56) 0 (60)
Production (62) (14) (3) (79) (439) (10) (1) (450)
Revisions of prior estimates 2 34 20 56 (79) 25 17 (37)
----------- ----------- ----------- ----------- ------------ ----------- ----------- -----------
Reserves, December 31, 2002 665 200 96 961 3,048 71 90 3,209
----------- ----------- ----------- ----------- ------------ ----------- ----------- -----------
PROBABLE RESERVES
Reserves, December 31, 2001 95 23 51 169 349 24 27 400
Extensions and discoveries 0 (1) (14) (15) 8 0 (17) (9)
Property purchases 10 24 0 34 82 6 0 88
Property disposals 0 (4) 0 (4) 0 (6) 0 (6)
Revisions of prior estimates (28) 31 33 36 (37) (6) 21 (22)
----------- ----------- ----------- ----------- ------------ ----------- ----------- -----------
Reserves, December 31, 2002 77 73 70 220 402 18 31 451
----------- ----------- ----------- ----------- ------------ ----------- ----------- -----------
Total Reserves,
December 31, 2002 742 273 166 1,181 3,450 89 121 3,660
----------- ----------- ----------- ----------- ------------ ----------- ----------- -----------
24
D. CRUDE OIL AND NATURAL GAS PRODUCTION
The Company's working interest share of oil, NGLs and natural gas production and
revenues received for the last two financial years is summarized in the
following tables:
YEAR ENDED DECEMBER 31
-----------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
Daily Production
Crude Oil and NGLs (bbls/d) 215,335 206,323 173,591 86,750 75,744
Natural Gas (MMcf/d) 1,232.3 918.1 794.4 721.0 672.6
Annual Production
Crude Oil and NGLs (Mbbls) 78,597 75,308 63,534 31,664 27,646
Natural Gas (Bcf) 449.8 335.1 290.8 263.2 245.5
NETBACKS
INFORMATION BY QUARTER
YEAR 2002 YEAR 2001
----------------------------------------- --------------------------------------------------
1ST 2ND 3RD 4TH YEAR 1ST 2ND 3RD 4TH YEAR
QUARTER QUARTER QUARTER QUARTER ENDED QUARTER QUARTER QUARTER QUARTER ENDED
------- ------- ------- ------- ----- ------- ------- ------- ------- -----
AVERAGE DAILY PRODUCTION
VOLUMES
Crude Oil and NGLs
(bbls) 188,439 189,386 242,051 240,596 215,335 205,588 214,716 207,065 198,000 206,323
Natural Gas (Mcf) 1,053.3 1,077.8 1,427.4 1,365.2 1,232.3 850.8 884.6 923.8 1,011.6 918.1
PRODUCT NETBACKS
Crude oil and NGLs
($/bbl)
Sales Price $ 24.50 $ 28.27 $ 33.57 $ 31.10 $ 29.76 $22.060 $ 25.32 $ 28.37 $ 21.28 $ 24.31
Royalties 2.28 3.02 3.56 3.53 3.16 2.36 2.42 2.47 1.41 2.17
Production Expenses 7.81 7.95 8.67 9.10 8.45 8.18 7.57 7.29 7.52 7.64
NETBACK $ 14.41 $ 17.30 $ 21.34 $ 18.47 $ 18.15 $ 11.52 $ 15.33 $ 18.61 $ 12.35 $ 14.50
Natural Gas ($/Mcf)
Sales Price $ 3.06 $ 3.68 $ 3.13 $ 5.00 $ 3.76 $ 9.306 $ 5.93 $ 3.12 $ 2.94 $ 5.16
Royalties 0.55 0.77 0.67 1.09 0.78 2.40 1.47 0.67 0.62 1.25
Production Expenses 0.58 0.57 0.55 0.57 0.57 0.50 0.50 0.50 0.53 0.51
NETBACK $ 1.93 $ 2.34 $ 1.91 $ 3.34 $ 2.41 $ 6.40 $ 3.96 $ 1.95 $ 1.79 $ 3.40
CRUDE OIL AND NGL NETBACKS
BY TYPE
Light/Pelican Lake/NGLs
($/bbl)
Sales Price $ 28.58 $ 31.84 $ 36.58 $ 36.38 $ 33.84 $330.96 $ 33.59 $ 32.75 $ 26.95 $ 31.13
Royalties 3.25 4.04 4.48 4.39 4.10 4.03 3.86 3.30 2.29 3.38
Production Expenses 7.48 8.36 10.06 9.38 8.97 5.99 6.10 6.12 7.15 6.34
NETBACK $ 17.85 $ 19.44 $ 22.04 $ 22.61 $ 20.77 $ 20.94 $ 23.63 $ 23.33 $ 17.51 $ 21.41
Heavy ($/bbl)
Sales Price $ 20.10 $ 24.20 $ 29.78 $ 24.54 $ 24.89 $212.76 $ 15.83 $ 23.21 $ 14.85 $ 16.63
Royalties 1.21 1.86 2.42 2.45 2.03 0.61 0.77 1.50 0.43 0.83
Production Expenses 8.18 7.48 6.91 8.77 7.84 10.48 9.24 8.68 7.93 9.10
Netback $ 10.62 $ 14.86 $ 20.45 $ 13.32 $ 15.02 $ 1.67 $ 5.82 $ 13.03 $ 6.49 $ 6.70
NOTE: Pelican Lake oil has an API of 14(0)to 17(0), but receives medium
quality crude netbacks due to exceptionally low operating costs and low
royalty rateS.
25
NETBACKS
INFORMATION BY QUARTER
YEAR 2002 YEAR 2001
----------------------------------------- --------------------------------------------------
1ST 2ND 3RD 4TH YEAR 1ST 2ND 3RD 4TH YEAR
QUARTER QUARTER QUARTER QUARTER ENDED QUARTER QUARTER QUARTER QUARTER ENDED
------- ------- ------- ------- ----- ------- ------- ------- ------- -----
SEGMENTED
NORTH AMERICA PRODUCT
NETBACKS
Light/Pelican Lake/NGLs
($/bbl)
Sales Price $ 25.27 $ 28.90 $ 32.83 $ 31.94 $ 30.01 $ 27.04 $ 27.49 $ 29.95 $ 23.83 $ 27.10
Royalties 4.24 5.11 5.98 5.81 5.35 4.57 5.04 4.17 2.79 4.16
Production Expenses 5.25 5.30 5.00 5.28 5.20 3.84 4.02 4.22 4.74 4.19
NETBACK $ 15.78 $ 18.49 $ 21.85 $ 20.85 $ 19.46 $ 18.63 $ 18.43 $ 21.56 $ 16.30 $ 18.75
Heavy ($/bbl)
Sales Price $ 20.01 $ 24.20 $ 29.78 $ 24.54 $ 24.89 $ 12.76 $ 15.83 $ 23.21 $ 14.85 $ 16.63
Royalties 1.21 1.86 2.42 2.45 2.03 0.61 0.77 1.50 0.43 0.83
Production Expenses 8.18 7.48 6.91 8.77 7.84 10.48 9.24 8.68 7.93 9.10
NETBACK $ 10.62 $ 14.86 $ 20.45 $ 13.32 $ 15.02 $ 1.67 $ 5.82 $ 13.03 $ 6.49 $ 6.70
Natural Gas ($/Mcf)
Sales Price $ 3.05 $ 3.72 $ 3.15 $ 5.04 $ 3.78 $ 9.30 $ 5.99 $ 3.13 $ 2.94 $ 5.19
Royalties 0.57 0.79 0.69 1.11 0.80 2.40 1.49 0.68 0.63 1.26
Production Expenses 0.56 0.55 0.52 0.55 0.55 0.50 0.50 0.50 0.52 0.50
NETBACK $ 1.92 $ 2.38 $ 1.94 $ 3.38 $ 2.43 $ 6.40 $ 4.00 $ 1.95 $ 1.79 $ 3.43
NORTH SEA PRODUCT
NETBACKS
Light Oil ($/bbl)
Sales Price $ 33.75 $ 39.36 $ 41.68 $ 41.83 $ 39.79 $ 41.04 $ 43.07 $ 37.28 $ 33.39 $ 38.66
Royalties 1.54 1.76 2.56 2.79 2.30 2.86 2.23 1.97 1.52 2.10
Production Expenses 10.09 15.72 18.30 14.68 15.06 9.22 8.42 8.09 10.54 9.00
NETBACK $ 22.12 $ 21.88 $ 20.82 $ 24.36 $ 22.43 $ 28.96 $ 32.42 $ 27.22 $ 21.33 $ 27.56
Natural Gas ($/Mcf)
Sales Price $ 3.77 $ 1.80 $ 1.98 $ 3.20 $ 2.75 $ - $ 1.74 $ 2.51 $ 3.00 $ 2.51
Royalties - - - - - - - - - -
Production Expenses 1.33 1.90 1.78 1.25 1.53 - 0.61 0.74 1.34 0.94
NETBACK $ 2.44 $ (0.10) $ 0.20 $ 1.95 $ 1.22 $ - $ 1.13 $ 1.77 $ 1.66 $ 1.57
OFFSHORE WEST AFRICA
PRODUCT NETBACKS
Light Oil ($/bbl)
Sales Price $ 37.61 $ 33.92 $ 42.78 $ 43.15 $ 40.10 $ 40.58 $ 39.75 $ 34.66 $ 19.56 $ 33.57
Royalties 1.65 1.11 1.34 1.35 1.35 - 0.65 2.03 0.64 0.93
Production Expenses 18.62 12.76 11.23 13.68 13.63 38.80 17.23 19.05 19.15 21.77
NETBACK $ 17.34 $ 20.05 $ 30.21 $ 28.12 $ 25.12 $ 1.78 $ 21.87 $ 13.58 $ (0.23) $ 10.87
Natural Gas ($/Mcf)
Sales Price $ 4.97 $ 4.63 $ 4.82
Royalties $ 0.15 $ 0.15 $ 0.15
Production Expenses $ 1.77 $ 1.85 $ 1.81
NETBACK $ - $ - $ 3.05 $ 2.63 $ 2.86 $ - $ - $ - $ - $ -
NOTE: Pelican Lake oil has an API of 14(0)to 17(0), but receives medium
quality crude netbacks due to exceptionally low operating costs and low
royalty rates.
26
E. DRILLING ACTIVITY
The following table sets forth the gross and net wells in which the Company has
participated for the period indicated:
YEAR ENDED DECEMBER 31
---------------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
GROSS NET GROSS NET GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- --- ----- --- ----- ---
Natural Gas 183 162 576 476 474 408 481 458 216 193
Crude Oil 316 264 270 231 375 333 229 211 120 107
Service/Stratigraphic 456 447 356 353 42 38 11 9 20 15
Dry & Abandoned 32 27 36 32 46 34 54 49 48 43
---------------------------------------------------------------------------------------------
Total 987 900 1,238 1,092 937 813 775 727 404 358
=============================================================================================
*Total Success Rate 94% 96% 96% 93% 87%
*excluding service and stratigraphic test wells
F. 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:
YEAR ENDED DECEMBER 31
--------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
($ Millions)
Corporate acquisition 2,393.2 - 1,687.3 - -
Net property acquisitions 440.2 519.2 150.2 1,422.3 63.9
Land acquisition and retention 113.5 100.5 79.7 46.2 39.0
Seismic evaluation 63.4 94.6 40.5 17.9 17.2
Well drilling, completion and equipping 625.6 635.3 508.9 267.8 253.2
Pipeline and production facilities 292.2 395.0 335.7 143.2 205.7
------- ------- ------- ------- -----
Reserve replacement expenditures 3,928.1 1,744.6 2,802.3 1,897.4 579.0
Projects under construction - - - (6.5) 25.4
Midstream operations 20.4 97.3 - - -
Horizon Project 68.1 26.8 - - -
Abandonments 42.9 9.4 15.1 7.0 2.0
Head office equipment 9.9 6.4 5.9 2.7 3.3
------- ------- ------- ------- -----
Total Net Capital Expenditures 4,069.4 1,884.5 2,823.3 1,900.6 609.7
============================================================
27
2002 THREE MONTHS ENDED
---------------------------------------------------------------------
($ Millions)
CAPITAL EXPENDITURES
BY QUARTER MAR. 31 JUNE 30 SEPT. 30 DEC. 31
------- ------- -------- -------
Corporate acquisition - - 2,393.2 -
Net property acquisitions 35.3 33.1 333.3 38.5
Land acquisition and retention 27.8 19.2 48.4 18.1
Seismic evaluation 24.8 14.6 4.9 19.1
Well drilling, completion and equipping 206.8 135.9 144.1 138.8
Pipeline and production facilities 124.3 66.6 56.5 44.8
------- -------- -------- -------
Reserve replacement expenditures 419.0 269.4 2,980.4 259.3
Midstream operations 9.6 5.2 - 5.6
Horizon Project 22.3 16.6 9.9 19.3
Abandonments 6.8 11.9 19.8 4.4
Head office equipment 1.1 1.7 3.9 3.2
------- -------- -------- -------
Total Net Capital Expenditures 458.8 304.8 3,014.0 291.8
=============================================================
2001 THREE MONTHS ENDED
---------------------------------------------------------------------
($ Millions)
CAPITAL EXPENDITURES
BY QUARTER MAR. 31 JUNE 30 SEPT. 30 DEC. 31
------- ------- -------- -------
Corporate acquisition
- - - -
Net property acquisitions
190.7 55.5 24.6 248.4
Land acquisition and retention
27.7 21.5 35.8 15.5
Seismic evaluation
37.0 20.2 8.6 28.8
Well drilling, completion and equipping
227.2 153.0 148.6 106.5
Pipeline and production facilities
111.4 105.0 109.7 68.9
------- ------- -------- -------
Reserve replacement expenditures 594.0 355.2 327.3 468.1
Midstream operations
28.9 6.8 16.1 45.5
Horizon Project
9.1 4.8 1.9 11.0
Abandonments
1.2 (0.2) 5.0 3.4
Head office equipment
1.5 1.4 1.8 1.7
------- ------- -------- -------
Total Net Capital Expenditures 634.7 368.0 352.1 529.7
=============================================================
28
G. NON-RESERVE ACREAGE
The following table summarizes the Company's working interest holdings in core
area non-reserve acreage earned by the Company as at December 31, 2002:
GROSS ACRES NET ACRES
----------- ---------
(thousands) (thousands)
NORTH AMERICA
Alberta 9,771 8,281
British Columbia 2,064 1,513
Saskatchewan 434 407
Manitoba 12 11
UNITED KINGDOM
North Sea 733 410
OFFSHORE WEST AFRICA
Angola 1,220 610
Cote d'Ivoire 452 333
-------------- -------------
Total 14,686 11,566
============== =============
29
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 DECEMBER 31
----------------------------------------------------------------------------------
2002 2001(1) 2000(1) 1999(1) 1998(1)
---- ------- ------- ------- -------
($ millions, except per share information)
Revenues (net of royalties) 3,482.9 3,008.5 2,754.4 1,103.6 760.8
Cash flow from operations
attributable to common shareholders 2,254.0 1,920.0 1,883.6 723.5 444.2
Per common share - basic 17.63 15.83 16.14 6.96 4.47
- diluted 16.99 15.23 15.64 6.85 4.46
Net earnings attributable to
common shareholders 569.8 642.6 767.1 219.5 39.4
Per common share - basic 4.46 5.30 6.57 2.11 0.40
- diluted 4.31 5.17 6.39 2.08 0.40
Total assets 13,358.9 8,966.9 7,753.5 4,850.5 3,227.8
Total long-term debt 4,074.0 2,669.2 2,454.5 2,156.8 1,425.5
---------------------------------------------------------------------------------
2002 THREE MONTHS ENDED
---------------------------------------------------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------- ------- -------- -------
($ millions, except per share information)
Revenues (net of royalties) 626.5 735.5 1,004.9 1,116.0
Net earnings attributable to 98.9 145.2 117.4 208.3
common shareholders
Per common share - basic 0.81 1.18 0.88 1.56
- diluted 0.79 1.09 0.86 1.51
---------------------------------------------------------------------------------
2001 THREE MONTHS ENDED(1)
---------------------------------------------------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------- ------- -------- -------
($ millions, except per share information)
Revenues (net of royalties) 903.5 815.5 706.3 583.2
Net earnings attributable to 221.8 286.6 81.3 52.9
common shareholders
Per common share - basic 1.82 2.37 0.67 0.44
- diluted 1.77 2.23 0.66 0.43
(1) Restated for change in accounting policy with respect to foreign currency
translation.
30
MARKET FOR CANADIAN NATURAL RESOURCES LIMITED SECURITIES
The Company's common shares are listed and posted for trading on the Toronto
Stock Exchange and the New York Stock Exchange under the symbol CNQ.
On January 17, 2001, the Company announced its intention to make a Normal Course
Issuer Bid through the facilities of the Toronto Stock Exchange and the New York
Stock Exchange, beginning January 22, 2001 and ending January 21, 2002, to
purchase for cancellation up to 6,114,726 common shares of the Company, being 5
per cent of the 122,294,533 common shares of the Company outstanding on January
17, 2001. During this period, 2,537,800 common shares were purchased for
cancellation at an average price of $44.61.
On January 21, 2002, the Company announced its intention to make a Normal Course
Issuer Bid through the facilities of the Toronto Stock Exchange and the New York
Stock Exchange, beginning January 23, 2002 and ending January 22, 2003, to
purchase for cancellation up to 6,060,180 common shares of the Company, being 5
per cent of the 121,203,603 common shares of the Company outstanding on January
18, 2002. No common shares were purchased during this program.
In January 2002, the Company issued 60,000 flow-through common shares at a price
of $39.00 per common share. The value of the common shares was determined as the
closing market price on the Toronto Stock Exchange on the day prior to the
allotment of the common shares.
On January 22, 2003, the Company announced its intention to make a Normal Course
Issuer Bid through the facilities of the Toronto Stock Exchange and the New York
Stock Exchange, beginning January 24, 2003 and ending January 23, 2004, to
purchase for cancellation up to 6,692,799 common shares of the Company, being 5
per cent of the 133,855,988 common shares of the Company outstanding on January
17, 2003. As at the date hereof 865,600 common shares were purchased for
cancellation.
DIVIDEND HISTORY
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 a regular quarterly dividend of $0.10 per common share. On February
25, 2002 the Board of Directors approved an increase in the quarterly dividend
to $0.125 per common share commencing with the dividend payable April 1, 2002.
On February 20, 2003 the Board of Directors approved a further increase in the
quarterly dividend to $0.15 per common share commencing with the dividend
payable April 1, 2003. These dividends are payable in January, April, July and
October of each year. The dividend policy of the Company continues to be under
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.
31
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:
POSITION PRINCIPAL
PRESENTLY OCCUPATION
NAME HELD DURING PAST 5 YEARS
N. Murray Edwards Vice-Chairman and President, Edco Financial Holdings Ltd. (a private
Calgary, Alberta Director(3)(5) management and consulting company). Has served
continuously as a director of the Company
since September 1988.
Ambassador Gordon D. Giffin Director(1)(2) Senior Partner, McKenna Long & Aldridge LLP (law firm)
Atlanta, Georgia since May 2001; prior thereto United States Ambassador
to Canada. Has served continuously as a
director of the Company since May 2002.
James T. Grenon Director(2)(4) Managing Director, TOM Capital Associates Inc.(a private
Calgary, Alberta investment company). Has served continuously as a
director of the Company since September 1988.
John G. Langille President and Director Officer of the Company. Has served continuously as a
Calgary, Alberta director of the Company since June 1982.
Keith A.J. MacPhail Director(3)(5) Chairman and President, Bonavista Petroleum Ltd. since
Calgary, Alberta November 1997. Has served continuously as a director of
the Company since October 1993.
Allan P. Markin Chairman and Director Chairman of the Company. Has served continuously as a
Calgary, Alberta director of the Company since January 1989.
James S. Palmer, C.M., Q.C. Director(1)(2)(3)(4) Chairman, Burnet, Duckworth & Palmer LLP (law firm). Has
Calgary, Alberta served continuously as a director of the Company since May
1997.
Dr. Eldon R. Smith, M.D. Director(4)(5) Professor and Former Dean, Faculty of Medicine, The
Calgary, Alberta University of Calgary. Has served continuously as a
director of the Company since May 1997.
David A. Tuer Director(1)(3) Chairman, Calgary Health Region since October 2001, prior
Calgary, Alberta thereto President and Chief Executive Officer, PanCanadian
Energy Corporation. Has served continuously as a director
of the Company since May 2002.
Steve W. Laut Chief Operating Officer Officer of the Company
Calgary, Alberta
Brian L. Illing Executive Officer of the Company
Calgary, Alberta Vice-President,
Exploration
Real M. Cusson Senior Vice-President, Officer of the Company
Calgary, Alberta Marketing
Real J. H. Doucet Senior Vice-President, Officer of the Company since October 2000; prior thereto
Calgary, Alberta Oil Sands director of various divisions at Suncor Inc. since 1993.
Allen M. Knight Senior Vice-President, Officer of the Company
Calgary, Alberta International &
Corporate Development
Tim S. McKay Senior Vice-President, Officer of the Company
Calgary, Alberta Operations
32
POSITION PRINCIPAL
PRESENTLY OCCUPATION
NAME HELD DURING PAST 5 YEARS
Douglas A. Proll Senior Vice-President, Officer of the Company since April 2001; prior thereto
Calgary, Alberta Finance Vice President Finance and Treasurer of Renaissance Energy
Ltd. until August 2000 and most recently Vice
President Finance and Business Development of
Husky Energy Inc. from August 2000 to February 2001.
Lyle G. Stevens SeniorVice-President, Officer of the Company
Calgary, Alberta Exploitation
Mary-Jo Case Vice President, Land Officer of the Company since May 2002; prior thereto
Calgary, Alberta Co-ordinator Land at PanCanadian Petroleum Limited 1994 to
1999 and most recently Manager Commercial
Ventures and Land at PanCanadian Petroleum
Limited 1999 to 2002.
William R. Clapperton Vice-President, Officer of the Company since January 2002; prior thereto
Calgary, Alberta Regulatory, Stakeholder Manager, Surface Land and Environment for the Company.
and Environmental
Affairs
Cameron S. Kramer Vice President, Officer of the Company since September 2002; prior thereto
Calgary, Alberta Field Operations Production Engineer of the Company until March 2000 and
most recently Manager, Field Operations of the
Company from April 2000 to September 2002.
Bruce E. McGrath Corporate Secretary Officer of the Company
Calgary, Alberta
(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 Safety, Health and Environmental Committee
All directors stand for election at each Annual General Meeting of CNRL
shareholders. All of the current directors are standing for election at the
Annual General Meeting of shareholders scheduled for May 8, 2003.
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).
As at December 31, 2002, the directors and senior officers of the Company, as a
group, beneficially owned, directly or indirectly, or exercised control or
direction over, in the aggregate, approximately 5.7 per cent of the total
outstanding common shares (approximately 7.4 per cent after the exercise of
options pursuant to the Company's stock option plan).
33
ADDITIONAL INFORMATION
Additional information including Directors' and Executive Officers'
remuneration, 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 28, 2003 in connection with the Annual General Meeting of
Shareholders of CNRL to be held on May 8, 2003 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 and
comparative Consolidated Financial Statements for the most recently completed
fiscal year ended December 31, 2002 found on pages 32 to 49 and 50 to 70
respectively, of the 2002 Annual Report to the Shareholders, which information
is incorporated herein by reference.
The Company shall provide to any person, upon request to the Corporate Secretary
of the Company:
(a) when securities of the Company are in the course of
distribution pursuant to a short form prospectus or a
preliminary short form prospectus has been filed in respect of
a distribution of its securities,
(i) one copy of the Annual Information Form of the
Company, together with one copy of any document, or
the pertinent pages of any document, incorporated by
reference in the Annual Information Form,
(ii) one copy of the comparative consolidated financial
statements of the Company for its most recently
completed financial year together with the
accompanying report of the auditor and one copy of
any interim consolidated financial statements of the
issuer subsequent to the consolidated financial
statements for its most recently completed financial
year,
(iii) one copy of the information circular of the Company
in respect of its most recent annual meeting of
shareholders that involved the election of directors
or one copy of any annual filing prepared in lieu of
that information circular, as appropriate, and
(iv) one copy of any other documents that are incorporated
by reference into the preliminary short form
prospectus or the short form prospectus and are not
required to be provided under (i) to (iii) above; or
(b) at any other time, one copy of any other documents referred to
in (a)(i), (ii) and (iii) above, provided the Company may
require the payment of a reasonable charge if a person who is
not a security holder of the issuer makes the request.
For additional copies of this Annual Information Form and the materials listed
in the preceding paragraphs, please contact:
Corporate Secretary of the Corporation at:
2500, 855 - 2nd Street S.W.
Calgary, Alberta T2P 4J8
DOCUMENT 2
----------
MANAGEMENT'S
DISCUSSION & ANALYSIS
Canadian Natural Resources is a Canadian based senior independent
energy company engaged in the acquisition, exploration, development,
production, marketing and sale of oil and natural gas. The Company initiates,
operates and maintains a large working interest in a majority of the prospects
in which it participates. The Company's principal core areas of oil and
natural gas operations are in the Western Canadian Sedimentary Basin,
the United Kingdom sector of the North Sea and Offshore West Africa.
================================================================================
MANAGEMENT'S DISCUSSION & ANALYSIS
================================================================================
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements in the Management's Discussion and Analysis for Canadian
Natural Resources Limited (the "Company") may constitute forward-looking
statements within the meaning of the United States Private Litigation Reform Act
of 1995. These forward-looking statements can generally be identified as such
because of the context of the statements including words such as the Company
believes, anticipates, expects, plans, estimates or words of a similar nature.
The forward-looking statements are based on current expectations and are subject
to known and unknown risks, uncertainties and other factors that may cause the
actual results, performance or achievements of the Company, or industry results,
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; foreign
currency exchange rates; 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; the ability of the Company to implement its
business strategy, including exploration and development activities; the ability
of the Company to complete its capital programs; the ability of the Company to
transport its products to market; potential delays or changes in plans with
respect to exploration or development projects or capital expenditures; the
availability and cost of financing; the success of exploration and development
activities; production levels; uncertainty of reserve estimates; actions by
governmental authorities; government regulations and the expenditures required
to comply with them (especially safety and environmental laws and regulations);
site restoration costs; and other circumstances affecting revenues and expenses.
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 management's course of action would depend upon its assessment of
the future considering all information then available.
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.
Readers are cautioned that the foregoing list of important factors is not
exhaustive. 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. The Company assumes no obligation to update
forward-looking statements should circumstances or management's estimates or
opinions change.
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, 2002. The consolidated financial statements have been prepared in
accordance with Canadian generally accepted accounting principles ("GAAP"). A
reconciliation of Canadian GAAP to United States GAAP is included in note 16 to
the consolidated financial statements. All dollar amounts are referenced in
Canadian dollars, except when noted otherwise. The calculation of barrels of oil
equivalent ("boe") is based on a conversion ratio of six thousand cubic feet of
natural gas to one barrel of oil to estimate relative energy content.
The following discussion details the Company's 2002 financial results compared
to 2001 and 2000, including its capital program, and outlook for 2003.
OBJECTIVE AND STRATEGY
The Company's objective is to increase cash flow, net earnings, and oil and
natural gas production and reserves through the development of its existing oil
and natural gas properties and by the discovery and acquisition of new reserves.
The Company accomplishes this by having a defined growth and value enhancement
plan for each of its products and segments. The Company effectively allocates
its capital by maintaining:
o Balance between its products, namely natural gas, light oil, Pelican
Lake oil (1), primary heavy oil and thermal heavy oil;
o Balance between near-, mid- and long-term projects;
o Balance between acquisitions, exploitation and exploration; and
o Balance between sources of debt and a strong balance sheet.
Strategic acquisitions, such as the acquisition of Rio Alto Exploration Ltd.
("Rio Alto"), are a key component of the Company's strategy.
Cost control is central to the Company's strategy. By controlling costs
consistently throughout all industry cycles, the Company is able to achieve
continued growth. Cost control is attained by core area domination and by
operating at a high working interest.
(1) Pelican Lake oil is 14-17(0) API oil, but receives medium quality crude
netbacks due to exceptionally low operating costs and low royalty rates.
2002 Annual Report 33
================================================================================
MANAGEMENT'S DISCUSSION & ANALYSIS
================================================================================
The year ended December 31, 2002 was another successful year in the execution of
the Company's strategy. The highlights were:
o Acquired Rio Alto;
o Acquired North Sea properties that provide the Company with the level
of operatorship and working interests in the North Sea necessary to
effectively control costs;
o Commenced production from the Espoir field offshore Cote d'Ivoire;
o Successfully delineated the Baobab field located offshore Cote
d'Ivoire;
o Received government approval for development of the Baobab field;
o Received regulatory approval for high-pressure steaming at Primrose,
Alberta;
o Submitted regulatory application for the Horizon Oil Sands Project
("Horizon Project");
o Signed a Production Sharing Agreement for Block 16, offshore Angola and
Block CI-400 offshore Cote d'Ivoire; and
o Successfully issued public debt to balance our sources of debt.
ACQUISITION OF RIO ALTO
The Company paid cash of $850.0 million and issued 10,008,218 common shares to
acquire all of the issued and outstanding common shares of Rio Alto by way of a
plan of arrangement. This was a strategic acquisition by the Company as it
strengthened the Company's natural gas production in North America and added a
new natural gas core region in Northwest Alberta that will provide the
opportunity for significant future natural gas volumes. The Rio Alto acquisition
is included in the results of operations commencing July 1, 2002.
CASH FLOW AND NET EARNINGS
Financial Highlights ($ millions, except per share amounts) 2002 2001(1) 2000 (1)
--------------------------------------------------------------------------------------------------------------------
Revenue $ 4,083.2 $ 3,588.8 $ 3,260.6
--------------------------------------------------------------------------------------------------------------------
Cash flow from operations attributable to common shareholders (2) $ 2,254.0 $ 1,920.0 $ 1,883.6
Per common share - basic $ 17.63 $ 15.83 $ 16.14
- diluted $ 16.99 $ 15.23 $ 15.64
Net earnings attributable to common shareholders (3) $ 569.8 $ 642.6 $ 767.1
Per common share - basic $ 4.46 $ 5.30 $ 6.57
- diluted $ 4.31 $ 5.17 $ 6.39
Business combinations $ 2,393.2 $ - $ 1,687.3
Capital expenditures, net of dispositions $ 1,676.2 $ 1,884.5 $ 1,136.0
====================================================================================================================
(1) Restated for change in accounting policy (see consolidated financial
statements - note 2) and to conform to current year presentation.
(2) After dividend on preferred securities.
(3) After dividend and revaluation of preferred securities.
[Graphic Omitted]
CASH FLOW FROM OPERATIONS NET EARNINGS PER SHARE
ATTRIBUTABLE TO COMMON ATTRIBUTABLE TO COMMON
SHAREHOLDERS ($ millions) SHAREHOLDERS* ($ millions)
98 444.2 98 0.40
99 723.5 99 2.11
00 1,883.6 00 6.57
01 1,920.0 01 5.30
02 2,254.0 02 4.46
* Restated for change in accounting
policy
NET EARNINGS ATTRIBUTABLE RETURN ON AVERAGE COMMON
TO COMMON SHAREHOLDERS* SHAREHOLDER'S EQUITY* (%)
($ millions) 98 3.2
98 39.4 99 14.5
99 219.5 00 31.6
00 767.1 01 18.8
01 642.6 02 13.8
02 569.8 * Restated for change in accounting
* Restated for change in accounting policy
policy
34 Canadian Natural
================================================================================
MANAGEMENT'S DISCUSSION & ANALYSIS
================================================================================
Cash flow from operations attributable to common shareholders increased 17% to
$2,254.0 million ($17.63 per common share), up from $1,920.0 million ($15.83 per
common share) in 2001 and $1,883.6 million ($16.14 per common share) in 2000.
The increase in cash flow resulted primarily from increased production volumes
offset by lower natural gas prices. In 2002, the Company's average price per
barrel of oil and liquids increased to $29.76 from $24.31 in 2001 (2000 -
$29.99). Production volumes increased 17% to 420,722 boe/d from 359,347 boe/d in
2001 (2000 - 305,987 boe/d).
Net earnings attributable to common shareholders decreased 11% in 2002 to $569.8
million, down from $642.6 million in 2001 and down from $767.1 million in 2000.
The decrease in net earnings resulted from the natural gas weighted acquisition
of Rio Alto, higher depletion, depreciation and amortization costs and increased
future income tax expense.
OPERATING HIGHLIGHTS 2002 2001(1) 2000(1)
------------------------------------------------------------------------------------------------------------
OIL AND LIQUIDS ($/bbl, except daily production)
Daily production (bbls/d) 215,335 206,323 173,591
Sales price $ 29.76 $ 24.31 $ 29.99
Royalties 3.16 2.17 3.05
Production expense 8.45 7.64 6.84
------------------------------------------------------------------------------------------------------------
Netback $ 18.15 $ 14.50 $ 20.10
------------------------------------------------------------------------------------------------------------
NATURAL GAS ($/mcf, except daily production)
Daily production (mmcf/d) 1,232 918 794
Sales price $ 3.76 $ 5.16 $ 4.53
Royalties 0.78 1.25 1.08
Production expense 0.57 0.51 0.44
------------------------------------------------------------------------------------------------------------
Netback $ 2.41 $ 3.40 $ 3.01
------------------------------------------------------------------------------------------------------------
BARREL OF OIL EQUIVALENT ($/boe, except daily production)
Daily production (boe/d) 420,722 359,347 305,987
Sales price $ 26.25 $ 27.15 $ 28.77
Royalties 3.91 4.42 4.51
Production expense 5.99 5.69 5.02
------------------------------------------------------------------------------------------------------------
Netback $ 16.35 $ 17.04 $ 19.24
============================================================================================================
(1) Restated to conform to current year presentation.
REVENUE
Product Prices
2002 2001 2000
------------------------------------------------------------------------------------------------------------
OIL AND LIQUIDS ($/bbl)
North America $ 27.04 $ 21.00 $ 28.15
North Sea $ 39.79 $ 38.66 $ 44.61
Offshore West Africa $ 40.10 $ 33.57 $ 45.77
Company average $ 29.76 $ 24.31 $ 29.99
NATURAL GAS ($/mcf)
North America $ 3.78 $ 5.19 $ 4.53
North Sea $ 2.75 $ 2.51 $ 3.66
Offshore West Africa $ 4.82 $ - $ -
Company average $ 3.76 $ 5.16 $ 4.53
PERCENTAGE OF REVENUE (excluding midstream revenue)
Oil and liquids 58.1% 51.5% 59.2%
Natural gas 41.9% 48.5% 40.8%
============================================================================================================
2002 Annual Report 35
================================================================================
MANAGEMENT'S DISCUSSION & ANALYSIS
================================================================================
ANALYSIS OF CHANGES IN REVENUE (excluding midstream operations)
CHANGES DUE TO CHANGES DUE TO
---------------------------------------------------------------------------------------------------------------------------
($ MILLIONS) 2000 VOLUMES PRICES 2001 VOLUMES PRICES 2002
---------------------------------------------------------------------------------------------------------------------------
NORTH AMERICA
Oil and liquids $ 1,591.0 $ 122.5 $ (434.1) $ 1,279.4 $ 23.0 $ 373.4 $ 1,675.8
Natural gas 1,314.1 183.3 220.0 1,717.4 565.1 (621.0) 1,661.5
---------------------------------------------------------------------------------------------------------------------------
2,905.1 305.8 (214.1) 2,996.8 588.1 (247.6) 3,337.3
---------------------------------------------------------------------------------------------------------------------------
NORTH SEA
Oil and liquids 280.8 309.5 (78.5) 511.8 37.0 16.3 565.1
Natural gas 2.0 14.3 (5.1) 11.2 13.6 2.5 27.3
---------------------------------------------------------------------------------------------------------------------------
282.8 323.8 (83.6) 523.0 50.6 18.8 592.4
---------------------------------------------------------------------------------------------------------------------------
OFFSHORE WEST AFRICA
Oil and liquids 34.6 22.1 (15.1) 41.6 41.5 16.2 99.3
Natural gas - - - - 2.2 - 2.2
---------------------------------------------------------------------------------------------------------------------------
34.6 22.1 (15.1) 41.6 43.7 16.2 101.5
---------------------------------------------------------------------------------------------------------------------------
TOTAL
Oil and liquids 1,906.4 454.1 (527.7) 1,832.8 101.5 405.9 2,340.2
Natural gas 1,316.1 197.6 214.9 1,728.6 580.9 (618.5) 1,691.0
---------------------------------------------------------------------------------------------------------------------------
$ 3,222.5 $ 651.7 $ (312.8) $ 3,561.4 $ 682.4 $ (212.6) $ 4,031.2
===========================================================================================================================
Oil and natural gas revenue rose 13% to $4,031.2 million from $3,561.4 million
in 2001 (2000 - $3,222.5 million). In 2002, 17% of the Company's oil and natural
gas revenue was generated outside of North America (2001 - 16%, 2000 - 10%),
with the North Sea accounting for 15% of these revenues, in both 2002 and 2001
(2000 - 9%) and Offshore West Africa accounting for 2%, up from 1% in 2001 (2000
- 1%). Revenue from the sale of natural gas accounted for 42% of oil and natural
gas revenue, down from 49% in 2001 (2000 - 41%).
Oil and liquids pricing realized by the Company is directly correlated with
world oil pricing and heavy oil differentials. The realized oil and liquids
price earned by the Company in 2002 increased 22% to average $29.76 per bbl for
the year, up from $24.31 per bbl in 2001 (2000 - $29.99 per bbl). World oil
prices were low in the beginning of 2002 but increased throughout the year due
to supply and demand fundamentals, general market uncertainty surrounding
tension in the Middle East, and disruptions in the supply of oil from Venezuela.
The West Texas Intermediate ("WTI") oil price increased 1% to average US $26.11
per bbl, up from US $25.91 per bbl in 2001 (2000 - US $30.20 per bbl). During
the same time, the heavy oil differential averaged US $6.50 per bbl, down from
US $10.73 per bbl in 2001 (2000 - US $8.23 per bbl). Heavy oil differentials
were lower than the historical 10-year average 30% discount to WTI pricing due
to a lower supply of heavy oil from western Canadian producers. The higher heavy
oil differentials experienced in 2001 were affected by the temporary shutdown of
a heavy oil refinery in the US mid-west and reduced demand for heavy oil.
Natural gas prices decreased 27% to average $3.76 per mcf, down from $5.16 per
mcf in 2001 (2000 - $4.53 per mcf), due to lower demand and higher storage
levels in the first half of 2002. Prices in 2001 were impacted by the increased
demand for natural gas due to cold winter temperatures, low inventory levels,
increased natural gas-fired power generation and increased export capacity. AECO
prices averaged $4.07 per mmbtu in 2002 compared to $6.25 per mmbtu in the year
2001 (2000 - $5.02 per mmbtu). NYMEX natural gas prices per mmbtu averaged US
$3.25 in 2002 compared to US $4.38 in 2001 (2000 - $3.91).
The Company uses certain financial instruments to protect against the downside
commodity prices received on the sale of certain oil and natural gas production
and to protect its capital program. The price realized from the sale of oil was
reduced by $1.46 per bbl in 2002 compared to an increase of $0.86 per bbl in
2001 (2000 - reduction of $1.89 per bbl), as a result of the financial
instruments. The price realized from the sale of natural gas was reduced by
$0.01 per mcf in 2002 compared to a reduction of $0.29 per mcf in 2001 (2000 -
reduction of $0.39 per mcf), as a result of the financial instruments.
As part of its overall risk management program, the Company has entered into
"costless collars" on a portion of its oil and natural gas production. These
financial instruments are summarized in note 12 to the consolidated financial
statements.
36 Canadian Natural
================================================================================
MANAGEMENT'S DISCUSSION & ANALYSIS
================================================================================
DAILY PRODUCTION
2002 2001 2000
--------------------------------------------------------------------------------
OIL AND LIQUIDS (bbls/d)
North America 169,675 166,675 154,331
North Sea 38,876 36,252 17,195
Offshore West Africa 6,784 3,396 2,065
--------------------------------------------------------------------------------
Total 215,335 206,323 173,591
--------------------------------------------------------------------------------
NATURAL GAS (mmcf/d)
North America 1,204 906 793
North Sea 27 12 1
Offshore West Africa 1 - -
--------------------------------------------------------------------------------
Total 1,232 918 794
--------------------------------------------------------------------------------
PRODUCT MIX
Light oil and liquids 20.8% 20.7% 18.1%
Pelican Lake oil 7.0% 9.7% 9.4%
Primary heavy oil 14.0% 15.8% 18.0%
Thermal heavy oil 9.4% 11.2% 11.2%
Natural gas 48.8% 42.6% 43.3%
================================================================================
The Company's daily oil and liquids production increased 4% to average 215,335
bbls in 2002 from 206,323 bbls in 2001 (2000 - 173,591 bbls). Oil and liquids
production increased for all segments from the year ended December 31, 2001. The
increase in North American production is attributable to additional heavy oil
drilling activity and property acquisitions in the Company's core operating
regions. Oil production in the North Sea increased as a result of the
acquisition of additional interests in the northern sector of the North Sea in
2002. Offshore West Africa oil production increased from 2001 as a result of
production commencing from the Company's operated Espoir field, located offshore
Cote d'Ivoire, in February 2002.
Natural gas continues to represent the Company's largest product offering,
accounting for nearly 49% of the Company's total production in 2002 compared to
43% of total production in both 2001 and 2000. North America accounts for over
98% of the Company's natural gas production in 2002 and 2001 (2000 - 100%).
Daily natural gas production increased 34% to 1,232 mmcf from 918 mmcf in 2001
(2000 - 794 mmcf). Natural gas production increased from the comparable periods
due to development of the Ladyfern field and the 2002 mid-year acquisition of
Rio Alto. Natural gas production from Rio Alto properties averaged 376 mmcf/d
over the last half of 2002. The Ladyfern field averaged 168 mmcf/d of natural
gas production during 2002, up from 40 mmcf/d in 2001. Natural gas production
increased in the North Sea due to the acquisition of additional interests in the
Banff and Kyle fields.
[GRAPHIC OMITTED]
NATURAL GAS PRODUCTION CRUDE OIL AND NGLs PRODUCTION
(mmcf/d) (mbbls/d)
98 673 98 76
99 721 99 87
00 794 00 174
01 918 01 206
02 1,232 02 215
2002 Annual Report 37
================================================================================
MANAGEMENT'S DISCUSSION & ANALYSIS
================================================================================
ROYALTIES
2002 2001 2000
--------------------------------------------------------------------------------
OIL AND LIQUIDS ($/bbl)
North America $ 3.42 $ 2.22 $ 3.17
North Sea $ 2.30 $ 2.10 $ 2.40
Offshore West Africa $ 1.35 $ 0.93 $ -
Company average $ 3.16 $ 2.17 $ 3.05
NATURAL GAS ($/mcf)
North America $ 0.80 $ 1.26 $ 1.08
Offshore West Africa $ 0.15 $ - $ -
Company average $ 0.78 $ 1.25 $ 1.08
Company average ($/boe) $ 3.91 $ 4.42 $ 4.51
PERCENTAGE OF REVENUE
(excluding financial instruments)
Oil and liquids 10.1% 9.3% 9.6%
Natural gas 20.8% 22.8% 22.0%
================================================================================
Oil and liquids royalties in North America increased to $3.42 per bbl, up from
$2.22 per bbl in 2001 (2000 - $3.17 per bbl), due to changes in oil prices. Oil
and liquids royalties in North America increased as a percentage of revenue as a
result of certain primary and thermal heavy oil projects that were subject to a
lower royalty structure reaching payout and becoming subject to higher
government royalty rates. The majority of the Company's oil sands projects
continue to benefit from reduced royalty rates as a result of the Alberta
program to promote development of oil sands resources, which provides a reduced
royalty rate until an oil sands project recovers its capital costs. In 2002,
North Sea oil royalties increased to $2.30 per bbl from $2.10 per bbl in 2001
(2000 - $2.40 per bbl). The increase per barrel and as a percentage of revenue
is due to the acquisition of additional interests in the royalty paying Ninian,
Murchison and Columba fields. In late November 2002, it was announced that
royalties in the North Sea would be eliminated effective January 1, 2003.
Offshore West Africa oil royalties increased from the prior year due to the
Espoir field commencing production in February 2002. In 2001, the Kiame field in
Angola was the only field on production and was on royalty holiday for a portion
of that year.
Natural gas royalties for the Company decreased to $0.78 per mcf for the year
2002, down from $1.25 per mcf in 2001 (2000 - $1.08 per mcf), due to the overall
decrease in natural gas prices. North American natural gas royalties are
sensitive to price changes and increased as a percentage of revenue in 2001 due
to the higher sales prices received. Natural gas royalties as a percentage of
revenue decreased to 20.8% in 2002 from 22.8% of revenue in 2001 (2000 - 22.0%)
due to lower average natural gas prices. In the North Sea, the Company's natural
gas production is derived from the non-royalty paying Banff and Kyle fields.
PRODUCTION EXPENSE
2002 2001(1) 2000(1)
--------------------------------------------------------------------------------
OIL AND LIQUIDS ($/bbl)
North America $ 6.73 $ 7.05 $ 6.45
North Sea $ 15.06 $ 9.00 $ 8.66
Offshore West Africa $ 13.63 $ 21.77 $ 20.41
Company average $ 8.45 $ 7.64 $ 6.84
NATURAL GAS ($/mcf)
North America $ 0.55 $ 0.50 $ 0.44
North Sea $ 1.53 $ 0.94 $ 0.79
Offshore West Africa $ 1.81 $ - $ -
Company average $ 0.57 $ 0.51 $ 0.44
COMPANY AVERAGE ($/boe) $ 5.99 $ 5.69 $ 5.02
================================================================================
(1) Restated to conform to current year presentation.
38 Canadian Natural
================================================================================
MANAGEMENT'S DISCUSSION & ANALYSIS
================================================================================
The decrease in 2002 North America oil and liquids production expense to $6.73
per bbl from $7.05 per bbl in 2001 (2000 - $ 6.45 per bbl) is primarily
attributable to the decrease in natural gas prices. Natural gas is used to
produce steam to heat the thermal oil formations to facilitate extraction in the
Primrose area of Alberta. Production expense in 2001 was higher due to higher
fuel and power costs incurred during the first half of the year. North Sea oil
production expense increased in 2002 to $15.06 per bbl from $9.00 per bbl in
2001 (2000 - $8.66 per bbl), due to costs incurred as a result of the planned
maintenance shutdowns of the Ninian North and Ninian Central platforms during
the third quarter of 2002. Production expense in the North Sea also increased in
2002 as a result of costs incurred to rectify a natural gas pipeline blockage at
Kyle experienced in the second quarter of 2002, and because the Columba B and D
fields reached a production milestone during 2001, thereby giving rise to higher
tariff rates on a go-forward basis. Offshore West Africa oil production expense
decreased to $13.63 per bbl from $21.77 per bbl in 2001 (2000 - $ 20.41 per bbl)
as a result of production ceasing from the higher production expense Kiame field
and as a result of production commencing from the Espoir field.
Natural gas production expense for the year 2002 increased to $0.57 per mcf from
$0.51 per mcf in 2001 (2000 - $0.44 per mcf), due to increased gathering and
processing charges and increased toll rates on Ladyfern production in the first
half of 2002.
MIDSTREAM
($ millions) 2002 2001 2000
--------------------------------------------------------------------------------
Revenue $ 52.0 $ 27.4 $ 38.1
Operating costs 14.1 11.2 8.7
Operating cash flow 37.9 16.2 29.4
Depreciation 7.6 3.8 1.8
Segment earnings before taxes $ 30.3 $ 12.4 $ 27.6
================================================================================
The Company's midstream assets consist of the 100% owned and operated ECHO
pipeline, the 15% interest in the Cold Lake pipeline system, the 62% interest in
the operated Pelican Lake pipeline, and the 50% interest in the 84 megawatt
co-generation system located in the Primrose area. The midstream pipeline assets
allow the Company to transport its own production volumes as well as earn third
party revenue from excess capacity. The Company transports approximately 82% of
its heavy oil through its pipelines to the international mainline liquid
pipelines. These midstream assets enhance the Company's ability to control the
full range of costs associated with the development and marketing of its heavy
oil.
The increase in operating cash flow and segment earnings before taxes in 2002
was due to the expansion of the ECHO pipeline, as well as the increased interest
in the Pelican Lake pipeline and the commencement of operations from the Cold
Lake pipeline system in late December 2001. The increased pipeline revenues were
partially offset by a decline in electricity revenue received from the sale of
excess electricity from the Company's cogeneration system to the Alberta Power
Pool.
DEPLETION, DEPRECIATION AND AMORTIZATION (1)
($ millions, except per boe amounts) 2002 2001 2000
--------------------------------------------------------------------------------
North America $ 1,032.8 $ 747.1 $ 585.9
North Sea 193.3 129.0 54.4
Offshore West Africa 80.5 23.9 2.5
Expense $ 1,306.6 $ 900.0 $ 642.8
$/boe $ 8.51 $ 6.86 $ 5.73
================================================================================
(1) DD&A excludes midstream operations.
Depletion, depreciation and amortization ("DD&A") increased in total and per boe
to $1,306.6 million or $8.51 per boe from $900.0 million or $6.86 per boe in
2001 (2000 - $642.8 million or $5.73 per boe). This increase was due to the
higher finding and development costs associated with natural gas exploration in
North America, the allocation of the acquisition costs associated with Rio Alto,
and future abandonment costs associated with the acquisition of additional
interests in the North Sea. DD&A was further increased in 2002 as a result of
the Company's decision to exit from its interests in Block 19, Angola, and from
the Aje field, Nigeria. The decision to exit from Block 19, Angola was made
after a technical review of the results of the Mariposa well where the Company
held a 25% non-operated working interest. The decision to exit from the Aje
field was based on a reinterpretation of seismic that showed the structural
closures were greatly reduced from previous expectations. The reduction in
likely oil-in-place and associated risk meant that the project failed to meet
the Company's economic threshold. The Company charged all related capitalized
costs in those countries, totaling $51 million, to DD&A during the second
quarter of 2002.
ADMINISTRATION EXPENSE
($ millions, except per boe amounts) 2002 2001 2000
--------------------------------------------------------------------------------
Gross cost $ 147.2 $ 109.9 $ 67.8
$/boe $ 0.96 $ 0.84 $ 0.61
Net expense $ 61.3 $ 37.6 $ 27.2
$/boe $ 0.40 $ 0.29 $ 0.25
================================================================================
2002 Annual Report 39
================================================================================
MANAGEMENT'S DISCUSSION & ANALYSIS
================================================================================
Gross administration expense increased to $0.96 per boe from $0.84 per boe in
2001 (2000 - $0.61 per boe) mainly due to higher staffing levels associated with
the growth in production and the expanding asset base. Gross administration
expense also increased as a result of the higher costs related to the assumption
of operatorship of certain fields in the North Sea and the cost of relocating
the majority of the Company's UK operations to Aberdeen during the fourth
quarter 2002. Net administration expense, after operator recoveries and
capitalized overhead relating to exploration and development in the North Sea
and Offshore West Africa as well as the Horizon Project, increased to $0.40 per
boe in 2002 from $0.29 per boe in 2001 (2000 - $0.25 per boe), due to the higher
staffing levels and expanding asset base.
INTEREST EXPENSE
2002 2001 2000
--------------------------------------------------------------------------------
Interest expense ($ millions) $ 158.9 $ 137.8 $ 162.3
$/boe $ 1.03 $ 1.05 $ 1.45
Average effective interest rate 4.5% 5.4% 6.4%
================================================================================
Interest expense increased in total to $158.9 million in 2002 from $137.8
million in 2001 (2000 - $162.3 million), due to higher average outstanding debt
levels as a result of the acquisition of Rio Alto and other property
acquisitions. Interest expense was consistent with 2000 as the overall increase
in debt levels in the last half of 2002 was offset by the lower cost of
borrowing. The impact of the higher debt levels was partially offset by the
lower overall cost of borrowing of 4.5% in 2002 from 5.4% in 2001 (2000 - 6.4%).
Interest expense per boe remained consistent at $1.03 per boe in 2002 compared
to $1.05 per boe in 2001 as the higher interest expense was offset by increased
production, but decreased from 2000 due to the increase in production and the
lower cost of borrowing. The Company continues to benefit from the lower
short-term interest rates as its fixed-rate debt accounts for only 40% of total
debt outstanding (after interest rates swaps, see note 12 to the consolidated
financial statements) as at December 31, 2002 (2001 - 21%, 2000 - 23%).
FOREIGN EXCHANGE
($ millions) 2002 2001(1) 2000(1)
--------------------------------------------------------------------------------
Realized foreign exchange loss (gain) $ 3.4 $ (1.3) $ (0.2)
Unrealized foreign exchange (gain) loss (35.1) 64.1 16.1
--------------------------------------------------------------------------------
$ (31.7) $ 62.8 $ 15.9
================================================================================
(1) Restated for change in accounting policy (see consolidated financial
statements - note 2).
Effective January 1, 2002, the Company retroactively adopted the Canadian
Institute of Chartered Accountants' new accounting standard with respect to
foreign currency translation. The new standard requires foreign exchange gains
and losses on the Company's US dollar denominated debt to be expensed
immediately rather than deferring and amortizing the gains and losses over the
term of the related debt. The change in accounting policy was applied
retroactively and foreign exchange losses for the year ended December 31, 2001
were increased by $48.1 million (2000 - $13.5 million). The majority of the
foreign exchange amounts are due to the translation of the US dollar denominated
debt.
The Company's US dollar denominated debt increased to US $1,968.0 million, up
from US $899.0 million in 2001 and US $509.0 million in 2000. The increase in
the US dollar denominated debt in 2002 was due to the following issuances:
o US $400 million of US dollar debt securities, maturing January 15, 2032,
and bearing interest at 7.20%;
o US $350 million of US dollar debt securities, maturing October 1, 2012, and
bearing interest at 5.45%; and
o US $350 million of US dollar debt securities, maturing June 30, 2033, and
bearing interest at 6.45%.
US dollar denominated debt represented 76% of total debt outstanding at December
31, 2002 (2001 - 53%, 2000 - 31%). Due to the greater amount of US dollar
denominated debt outstanding, the Company's net earnings were more affected by
the fluctuations in the Canadian dollar. The US/Canadian dollar exchange rate
fluctuated throughout 2002 due to economic and political uncertainties. The
Canadian dollar averaged US $0.637 in 2002, down from US $0.646 in 2001 (2000 -
US $0.673).
In order to mitigate a portion of the volatility associated with the Canadian
dollar, the Company, effective July 1, 2002, designated certain US dollar
denominated debt as a hedge against its net investment in US dollar based
self-sustaining foreign operations. Accordingly, translation gains and losses on
this US dollar denominated debt are included in the foreign currency translation
adjustment in shareholders' equity in the consolidated balance sheets.
40 Canadian Natural
================================================================================
MANAGEMENT'S DISCUSSION & ANALYSIS
================================================================================
TAXES
($ millions, except for tax rates) 2002 2001 2000
--------------------------------------------------------------------------------
Taxes other than income tax
Current $ 53.4 $ 69.3 $ 57.1
Deferred 9.5 (0.2) (7.6)
--------------------------------------------------------------------------------
Total $ 62.9 $ 69.1 $ 49.5
================================================================================
Current income tax
North Sea $ (19.6) $ 61.8 $ 33.7
Offshore West Africa 6.0 - -
North America - Large Corporations Tax 21.2 15.1 14.7
--------------------------------------------------------------------------------
Total $ 7.6 $ 76.9 $ 48.4
================================================================================
Future income tax $ 401.0 $ 282.5 $ 464.0
Effective income tax rate 41.6% 35.4% 39.9%
================================================================================
Taxes other than income tax consist of current and deferred petroleum revenue
tax ("PRT"), other international taxes and provincial capital taxes. PRT is
charged on certain fields in the North Sea at the rate of 50% of net operating
income after certain deductions including abandonment expenditures. Taxes other
than income tax decreased to $62.9 million or $0.41 per boe in 2002 from $69.1
million or $0.53 per boe in 2001 (2000 - $49.5 million or $0.44 per boe). The
decrease in taxes other than income taxes was mainly due to the lower netback
earned in the North Sea as a result of increased production costs. Taxes other
than income taxes increased from the year 2000 due to a full year of production
from the North Sea properties acquired in the Ranger Oil Limited ("Ranger")
acquisition. North Sea PRT accounts for $51.1 million or $0.33 per boe in 2002
compared to $59.1 million or $0.45 per boe in 2001 (2000 - $33.3 million or
$0.29 per boe).
In 2002, there was a recovery of current income tax in the North Sea of $19.6
million or $0.13 per boe compared to an income tax expense of $61.8 million or
$0.47 per boe in 2001 (2000 - $33.7 million or $0.30 per boe). The decrease in
the current income tax expense was partly due to the decision by the UK
Government to increase the first year capital allowance rate for plant and
machinery expenditures to 100% from the previous rate of 25%. The recovery of
current income tax also resulted from the settlement of certain outstanding
matters from prior years. Offshore West Africa current income tax expense
increased from the prior year due to the commencement of operations at the
Espoir field located offshore Cote d'Ivoire in February 2002. The Company did
not incur any cash Canadian federal income taxes in 2002. It is anticipated
that, based on the current availability of $3.1 billion of tax pools in Canada
at the end of 2002 and the current pricing, the Company could be cash taxable in
Canada in 2003. The Company is liable for the payment of federal Large
Corporations Tax ("LCT"). LCT increased to $21.2 million or $0.14 per boe from
$15.1 million or $0.11 per boe (2000 - $14.7 million, $0.13 per boe) due to the
higher taxable capital base as a result of increased debt levels and
shareholders' equity associated with the acquisition of Rio Alto.
The Company's future income tax provision for 2002 increased to $401.0 million
($2.61 per boe) from $282.5 million ($2.15 per boe) in 2001 (2000 - $464.0
million or $4.14 per boe) due to the increase in net earnings before tax. Future
income tax expense for the year ended December 31, 2002 also increased over the
prior year due to the introduction in the UK of a 10% supplementary charge on
profits from North Sea oil and natural gas production. The supplementary charge
is in addition to the current corporate tax rate of 30% and excludes any
deduction for financing costs. As a result of this additional charge, the future
income tax liability in the North Sea was increased by $34 million. The increase
in the North Sea future income tax liability was partially offset by a $26
million decrease in the North American future income tax liability as a result
of a reduction in a Canadian province's corporate income tax rate in the second
quarter of 2002. In 2001, the North American future income tax liability was
reduced by $63 million as a result of reductions in Canadian provinces'
corporate income tax rates. Future income taxes also increased in 2002 because
of the increased capital allowance rates in the North Sea, resulting in a lower
current tax expense and a higher future income tax expense. Future income taxes
in 2000 were higher due to higher product netbacks and higher current income tax
rates in Canada.
The Company's effective tax rate increased to 41.6% in 2002 from 35.4% in 2001
(2000 - 39.9%). The increase is a result of the introduction of the 10%
supplementary charge on profits from North Sea oil and natural gas production
and the reductions in certain Canadian provinces' corporate income tax rates
during 2001.
2002 Annual Report 41
================================================================================
MANAGEMENT'S DISCUSSION & ANALYSIS
================================================================================
LIQUIDITY AND CAPITAL RESOURCES
($ millions, except ratios) 2002 2001(1) 2000(1)
---------------------------------------------------------------------------------------
Working capital deficit $ 13.8 $ 5.6 $ 77.3
Long-term debt 4,074.0 2,669.2 2,454.5
---------------------------------------------------------------------------------------
Net debt $ 4,087.8 $ 2,674.8 $ 2,531.8
=======================================================================================
Shareholders' equity
Preferred securities $ 126.4 $ 127.4 $ 119.9
Share capital 2,303.8 1,698.3 1,692.6
Retained earnings 2,414.3 1,908.5 1,390.6
Foreign currency translation adjustment 23.6 72.8 -
---------------------------------------------------------------------------------------
Total $ 4,868.1 $ 3,807.0 $ 3,203.1
=======================================================================================
Debt to cash flow (2) 1.8x 1.4x 1.3x
Debt to book capitalization 45.6% 41.2% 43.4%
Debt to market capitalization 38.9% 34.9% 32.1%
After tax return on average common
shareholders' equity (2) 13.8% 18.8% 31.6%
After tax return on average capital
employed (2) 8.9% 12.0% 18.1%
=======================================================================================
(1) Restated for change in accounting policy (see consolidated financial
statements - note 2).
(2) Based on trailing 12-month period and does not include
amounts related to acquired assets for the six-month period prior to
June 30, 2002.
The Company recognizes the need for a strong financial position in order to
withstand volatile oil and natural gas commodity prices and the operational
risks inherent in the oil and natural gas business environment.
LONG-TERM DEBT
Long-term debt at December 31, 2002 amounted to $4,074 million and reflected a
1.8x debt to cash flow ratio and a debt to book capitalization of 45.6%. These
ratios are within the Company's guidelines for balance sheet management.
At December 31, 2002 the Company had:
o Approximately $1.3 billion of available unused bank credit facilities;
o A fixed/floating interest rate mix of 40%/60%;
o An overall average cost of borrowing of approximately 4.5%;
o 76% of borrowings denominated in US dollars; and
o 76% of total long-term debt is non-bank based borrowing with an average
maturity of 15.6 years.
During 2002, the Company issued US dollar debt securities and used the proceeds
from the issuances to repay bank indebtedness. In January 2002, the Company
issued US $400 million of 30-year US dollar debt securities maturing January 15,
2032, bearing interest at 7.20%. In September 2002, the Company issued US $350
million of ten-year US dollar debt securities maturing October 1, 2012, bearing
interest at 5.45% and US $350 million of 30-year US dollar debt securities
maturing June 30, 2033, bearing interest at 6.45%. Subsequent to these
issuances, the Company entered into interest rate swap contracts that convert
the fixed rate interest coupon into a floating interest rate (see consolidated
financial statements - note 12). The Company has US $300 million remaining on a
US $1 billion shelf prospectus filed on August 16, 2002 that allows for the
issue of debt securities until September 2004. In addition, the Company
maintains a shelf prospectus in Canada for the offering of up to $1 billion of
medium-term notes in Canada. If issued, these securities will bear interest as
determined at the date of issuance. Future offerings under the shelf
prospectuses will provide flexibility to the Company's debt investment base,
extend maturities and provide balance in the fixed to floating interest rate
mix.
The ratings of the Company's debt securities and its relationships with
principal banks are extremely important to the Company as it continues to expand
and grow. Hence, the Company's management will continually undertake to
strengthen its balance sheet and financial position. The Company's debt
securities are rated "Baa1" by Moody's Investor Services Inc., "BBB+" by
Standard & Poors Corporation and "BBB(high)" by Dominion Bond Rating Services
Limited.
As at December 31, 2002, the Company had unsecured bank credit facilities of
$2,275 million compared to $1,840 million at the close of 2001 (2000 - $2,800
million). During 2002, the Company repaid and cancelled a $725 million credit
and term loan facility and a US $150 million credit and term loan facility. At
December 31, 2002, the Company had approximately $1.3 billion of unutilized bank
credit lines available to it, in addition to funds that are available through
the Company's Canadian and US shelf prospectuses.
42 Canadian Natural
================================================================================
MANAGEMENT'S DISCUSSION & ANALYSIS
================================================================================
SHARE CAPITAL
The Company issued 10.0 million common shares at an attributed value of $522.4
million as part of the consideration to acquire Rio Alto. A further 2.5 million
shares were issued from the exercise of stock options throughout 2002 for
proceeds of $82.1 million. In 2001, 1.5 million common shares from the exercise
of stock options and warrants were issued for proceeds of $45.5 million. In
2000, 3.2 million common shares were issued from the exercise of stock options
for proceeds of $65.3 million and 7.6 million common shares were issued at an
attributed value of $358.0 million as part of the consideration to acquire
Ranger.
During 2002, the Company issued 60,000 flow-through common shares to a director
of the Company at a price of $39.00 per common share, for total proceeds of $2.3
million. The value of the common shares was determined based on the closing
market price of the common shares on the Toronto Stock Exchange on the day prior
to the allotment.
In January 2001, the Company announced its intention to make a Normal Course
Issuer Bid through the facilities of the Toronto Stock Exchange and the New York
Stock Exchange. As at January 21, 2002, the Company had purchased 2,537,800
common shares, of the allowable 6,114,726 common shares for a total cost of
$113.3 million. In January 2002, the Company renewed its Normal Course Issuer
Bid. No common shares were purchased under the renewed Normal Course Issuer Bid
in the period ended January 23, 2003.
In January 2003, the Company renewed its Normal Course Issuer Bid, allowing the
Company to purchase up to 6,692,799 common shares or 5% of the Company's
outstanding common shares on the date of announcement, during the 12-month
period beginning January 24, 2003 and ending January 23, 2004. As at February
26, 2003, 175,600 common shares had been purchased under the Normal Course
Issuer Bid for a total cost of $8.3 million.
In January 2001, the Company announced a regular quarterly dividend of $0.10 per
common share payable in January, April, July and October of each year. In
February 2002, the Board of Directors increased the Company's regular quarterly
dividend to $0.125 per common share. In February 2003, the Board of Directors
declared a 20% increase in the regular quarterly dividend to $0.15 per common
share, or $0.60 per share per annum, commencing with the April 1, 2003 payment.
The Company declared dividends on common shares in the amount of $64.0 million
($0.50 per common share) during the year ended December 31, 2002, up from $48.5
million ($0.40 per common share) in 2001 (2000 - $ nil).
CAPITAL EXPENDITURES
($ millions) 2002 2001(1) 2000(1)
----------------------------------------------------------------------------------------------
BUSINESS COMBINATIONS $ 2,393.2 $ - $ 1,687.3
==============================================================================================
EXPENDITURES ON PROPERTY, PLANT AND EQUIPMENT
Net property acquisitions $ 440.2 $ 519.2 $ 150.2
Land acquisition and retention 113.5 100.5 79.7
Seismic evaluations 63.4 94.6 40.5
Well drilling, completion and equipping 625.6 635.3 508.9
Pipeline and production facilities 292.2 395.0 335.7
----------------------------------------------------------------------------------------------
TOTAL NET RESERVE REPLACEMENT EXPENDITURES 1,534.9 1,744.6 1,115.0
==============================================================================================
Horizon Project 68.1 26.8 -
Midstream 20.4 97.3 -
Abandonments 42.9 9.4 15.1
Head office 9.9 6.4 5.9
----------------------------------------------------------------------------------------------
TOTAL NET CAPITAL EXPENDITURES $ 1,676.2 $ 1,884.5 $ 1,136.0
==============================================================================================
BY SEGMENT (excluding business combinations)
North America $ 1,132.1 $ 1,485.5 $ 1,041.8
North Sea 333.3 97.8 54.9
Offshore West Africa 190.4 203.9 39.3
Midstream 20.4 97.3 -
----------------------------------------------------------------------------------------------
Total $ 1,676.2 $ 1,884.5 $ 1,136.0
==============================================================================================
(1) Restated to conform to current year presentation.
The Company's strategy is focused on continuing to build a diversified asset
base, that is balanced between products, namely natural gas, light oil, Pelican
Lake oil, primary heavy oil and thermal heavy oil.
Capital expenditures totaled $1,676.2 million in the year 2002, excluding the
acquisition of Rio Alto, compared to $1,884.5 million in 2001 (2000 - $1,136.0
million, excluding the acquisition of Ranger). Capital expenditures on North
American properties accounted for 69% of total capital
2002 Annual Report 43
================================================================================
MANAGEMENT'S DISCUSSION & ANALYSIS
================================================================================
expenditures (2001 - 84%, 2000 - 92%), with the remainder expended in the
Company's core operating regions in the North Sea and Offshore West Africa. In
2002, the number of net wells drilled (excluding injection/stratigraphic test
wells) decreased 39% to 453 from the 739 in 2001 (2000 - 775 net wells). The
number of natural gas wells drilled was 162 net wells, down from 476 net wells
in 2001 (2000 - 408 net wells), which reflects the Company's decision to defer
natural gas drilling from 2002 to 2003 to offset anticipated Ladyfern production
declines. In addition, during 2002 the Company drilled 293 net stratigraphic
test wells on the oil sands leases in the Horizon Project. The first quarter of
2002 included natural gas exploration that concentrated on larger outlying pools
in the Ladyfern area and the construction and commissioning of the Ladyfern
natural gas pipeline.
North Sea capital expenditures in 2002 included the consolidation of interests
in the Banff, Kyle, Ninian, Lyell, Murchison and Columba fields. The Company
also acquired an interest in 12 licenses covering 20 exploration blocks and part
blocks, and additional equity interests in the Brent and Ninian pipelines and
the Sullom Voe Terminal. The consideration for these acquisitions included cash
payments and the Company's interests in the Harding, Pierce and Claymore fields.
As a result of these acquisitions, the Company was able to assume operatorship
of several fields during 2002.
Offshore West Africa capital expenditures in Cote d'Ivoire included the
continued development of the Espoir and Baobab fields. During 2002, three
producing wells and two water injection wells were completed in the Espoir
field. Unanticipated uphole faults delayed completion of the fourth producing
well. Development continued on the Baobab field, where a second successful well
was drilled and tested at a rate in excess of 10,000 bbls/d in the first quarter
of 2002. The Company received approval for the Baobab development plan by the
Government of Cote d'Ivoire in December 2002. During December 2002, a satellite
pool, Emien, was drilled but encountered no hydrocarbons. The Company also
acquired an interest in the exploration Block CI-400 in deeper waters offshore
Cote d'Ivoire. This block is located adjacent to the Baobab discovery. The
Company will operate Block CI-400 and retain a 90% working interest. In
addition, during 2002 the Company entered into a production sharing agreement
("PSA") for Block 16, offshore Angola, in which the Company has a 50% working
interest. The PSA was effective September 1, 2002 for an initial four-year
period.
ENVIRONMENT
The Company's environmental management plan and operating guidelines focus on
minimizing the impact of field operations while meeting regulatory requirements
and corporate standards. The Company as part of this plan has implemented a
proactive program than includes:
o An annual internal environmental compliance audit and inspection program of
our operating facilities;
o An aggressive suspended well inspection program to support future
development or eventual abandonment;
o Appropriate reclamation and decomissioning standards for wells and
facilities ready for abandonment;
o An effective surface reclamation program;
o A progressive due diligence program related to groundwater monitoring;
o A rigorous program related to preventing and reclaiming spill sites; and
o A solution gas reduction and conservation program.
Internationally, the Company has established stringent operating standards in
four areas:
o Using water-based, environmentally friendly drilling muds whenever
possible;
o Implementing cost effective ways of reducing greenhouse natural gas
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.
In 2002, the Company's capital expenditures included $42.9 million of
abandonment expenditures, up from $9.4 million in 2001 (2000 - $15.1 million).
ESTIMATED FUTURE SITE RESTORATION LIABILITY
($ millions, excluding salvage value)
2002
--------------------------------------------------------------------------------
North America 1,206.0
North Sea 745.3
Offshore West Africa 34.9
--------------------------------------------------------------------------------
1,986.2
North Sea PRT recovery (304.9)
--------------------------------------------------------------------------------
1,681.3
================================================================================
The estimate of the future site restoration liability is based on estimates of
future costs to abandon and restore the wells, production facilities and
offshore production platforms. There are numerous factors that affect these
costs including such things as the number of wells drilled, well depth and the
specific environmental legislation. The estimated costs are based on engineering
estimates using current costs and technology in accordance with current
legislation and industry practice. It is important to note that the future
abandonment costs to be incurred by the Company in the North Sea
44 Canadian Natural
================================================================================
MANAGEMENT'S DISCUSSION & ANALYSIS
================================================================================
will result in an estimated recovery of PRT of $304.9 million, as abandonment
costs are an allowable deduction in determining PRT and may be carried back to
reclaim PRT previously paid. The PRT recovery reduces the net abandonment
liability of the Company to $1,681.3 million.
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.
RISKS AND UNCERTAINTIES
The Company is exposed to several operational risks inherent in exploring,
developing, producing and marketing of oil and natural gas. These inherent risks
include: economic risk of finding and producing reserves at a reasonable cost;
financial risk of marketing reserves at an acceptable price given current market
conditions; cost of capital risk associated with securing the needed capital to
carry out the Company's operations; risk of fluctuating foreign exchange rates;
risk of carrying out operations with minimal environmental impact; risk of
governmental policies, social instability or other political, economic or
diplomatic developments in its international operations; and credit risk of
non-payment for sales contracts or non-performance by counterparties to
contracts.
The Company uses a variety of means to help minimize these risks. The Company
maintains a comprehensive insurance program to reduce risk to an acceptable
level and to protect it against potentially significant losses. Operational
control is enhanced by focusing efforts on large core regions with high working
interests and by assuming operatorship of all key facilities. Product mix is
diversified, ranging from the production of natural gas to the production of oil
of various grades. The Company believes this diversification reduces price risk
when compared with over-leverage to one commodity. Sales of oil and natural gas
are aimed at various markets to ensure that undue exposure to any one market
does not exist. 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 risks by entering into sales contracts
and financial derivatives with only highly rated entities and financial
institutions. In addition, 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.
The Company's current position with respect to its financial instruments is
detailed in note 12 of the Company's consolidated financial statements. 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.
The Company continues to employ an Environmental Management Plan (the "Plan") to
ensure the welfare of its employees, the communities in which it operates, and
the environment as a whole. Environmental protection is of fundamental
importance and is undertaken in accordance with guiding principles approved by
the Company's Board of Directors. A detailed copy of the Company's Plan is
presented to, and reviewed by, the Board of Directors annually. The Plan is
updated quarterly at the Directors' meetings.
KYOTO PROTOCOL
The Horizon Project is situated on leases containing over 6 billion bbls of
mineable oil reserves, supporting a three-phase development that will produce
232,000 bbls/d of light, sweet oil for over 40 years. The Horizon Project
encompasses four operational segments: minesite, extraction, primary upgrading
and secondary upgrading. Additional development potential also exists on the
leases to extract a further 2 billion bbls of mineable reserves and 1 billion
bbls of in-situ reserves. To date, capital expenditures of $228.7 million have
been incurred on the Horizon Project.
The Company believes that certainty of long-term costs and implementation
consistency is required prior to the final commitment for an investment as large
as the Horizon Project. In December 2002, the Canadian Federal Government
ratified the Kyoto Protocol ("Kyoto") which has resulted in a decrease in cost
certainty. Recently, the Canadian Federal Government has provided some limits to
the cost of Kyoto implementation through 2012; however, beyond 2012 no
implementation certainty exists. As the Horizon Project is scheduled to commence
production in 2008 and produce for over 40 years, the lack of clarity on Kyoto
implementation over the long term precludes the Company's ability to commit to
the construction of the Horizon Project at this time.
The Company anticipates completion of its Design Basis Memorandum ("DBM") phase
of engineering in the first quarter of 2003. Although sufficient levels of
implementation certainty to start construction do not exist today, the Company
anticipates such levels of certainty will be achieved, and therefore has decided
to continue with the Engineering Design Specification ("EDS") phase of
engineering. The EDS will commence after completion of the DBM, with related
2003 expenditures included in the Company's current Horizon Project budget of
$211 million.
The Company will continue to work with the Canadian Federal Government to
clarify long-term economic consequences of Kyoto implementation on the Horizon
Project before any site clearing or pre-construction work begins in 2004.
COTE D'IVOIRE
The Company's development activities in Cote d'Ivoire remain unaffected by
recent political insurrection in the country as the Company's operations are
located offshore. The Company has established back-up facilities in a
neighbouring country to ensure operations are not affected should conditions
significantly deteriorate. To date, the Company has not needed to utilize this
contingency.
2002 Annual Report 45
================================================================================
MANAGEMENT'S DISCUSSION & ANALYSIS
================================================================================
CRITICAL ACCOUNTING ESTIMATES
A comprehensive discussion of the Company's significant accounting policies is
contained in note 1 to the consolidated financial statements. The following is a
discussion of the accounting estimates that are critical in determining the
Company's financial results.
FULL COST ACCOUNTING
The Company follows the full cost method of accounting for oil and natural gas
properties and equipment as prescribed by the Canadian Institute of Chartered
Accountants. Accordingly, all costs relating to the exploration for and
development of oil and natural gas reserves are capitalized and accumulated in
country-by-country cost centres. The capitalized 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. Capitalized costs
in each cost centre may not exceed the sum of discounted future net revenues
from proved properties and the cost of unproved properties, net of provision for
impairment, less estimated future financing and administrative expenses and
income taxes (the "ceiling test"). If the net capitalized costs of a cost centre
are determined to be in excess of the calculated ceiling, which is based largely
on reserve estimates, the excess must be charged as an expense against net
earnings. Proceeds on disposal of properties are ordinarily deducted from such
costs without recognition of profit or loss except where such disposal
constitutes a significant portion of the Company's reserves in that country.
The alternate acceptable method of accounting for 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.
OIL AND NATURAL GAS RESERVES
The Company retains independent petroleum engineering consultants Sproule
Associates Limited ("Sproule") to evaluate the Company's proved and probable oil
and natural gas reserves and prepares an evaluation report on the Company's
total reserves. In 2002, Sproule's report incorporated 89% of the Company's
reserves with the Company internally evaluating the remaining 11%.
The estimation of reserves involves the exercise of judgement. Forecasts are
based on engineering data, 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 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 depreciation, depletion and
amortization. A revision to the reserve estimate could 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 oil and natural gas property, plant and equipment
under the ceiling test.
FUTURE SITE RESTORATION
The Company provides for the estimated future dismantlement, site restoration
and abandonment costs of oil and natural gas properties using the
unit-of-production method. Processing and production facilities are provided for
using the straight-line method over their estimated useful lives of 20 years.
The annual provision is included in depletion, depreciation and amortization.
The estimated costs are based on engineering estimates using current costs and
technology in accordance with current legislation and industry practice. The
estimation of these costs can be affected by factors such as the number of wells
drilled, well depth and area specific environmental legislation. These estimates
are reviewed regularly and could impact the DD&A rate used by the Company. A
revision to these estimated future costs could result in a higher or lower DD&A
expense charged to net earnings.
STOCK-BASED COMPENSATION
The Company's Stock Option Plan (the "Option Plan") provides for granting of
stock options to directors, officers and employees. Stock options granted under
the Option Plan have a maximum term of six years to expiry and vest equally over
a five-year period starting on the first anniversary date of the grant. The
exercise price of each stock option granted is determined as the closing market
price of the common shares on the Toronto Stock Exchange on the day prior to the
day of the grant. Each stock option granted permits the holder to purchase one
common share of the Company at the stated exercise price. Currently, GAAP does
not require the Company to record compensation expense in the consolidated
financial statements for stock options granted. If the Company had used the
fair-value method to account for its stock based compensation, compensation
expense of $24.9 million would have been charged to net earnings in 2002.
Further details regarding the Company's stock-based compensation are included in
note 9 of the consolidated financial statements.
OUTLOOK
The Company continues its strategy of maintaining a large portfolio of varied
projects, which enables the Company over an extended period of time to provide
consistent growth in production and high shareholder returns. Annual budgets are
developed, scrutinized throughout the year and changed if necessary in the
context of 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.
46 Canadian Natural
================================================================================
MANAGEMENT'S DISCUSSION & ANALYSIS
================================================================================
The Company expects production levels in 2003 to average 1,280 to 1,330 mmcf/d
of natural gas and 240 to 260 mbbls/d of oil and liquids, unchanged from
previous expectations. First quarter 2003 production guidance for natural gas is
1,300 to 1,320 mmcf/d of natural gas and 235 to 240 mbbls/d of oil and liquids.
The budgeted capital expenditures for 2003 are as follows:
Canadian natural gas properties $ 691 million
Canadian oil properties $ 517 million
Horizon Project $ 211 million
International oil properties - North Sea $ 281 million
International oil properties - Offshore West Africa $ 280 million
Property acquisitions $ 300 million
--------------------------------------------------------------------------------
Total capital expenditures $ 2,280 million
================================================================================
In North America, the Company will commence development of the undeveloped land
acquired in the Rio Alto acquisition with the drilling of 51 wells, 49 of which
will be natural gas wells. Approximately 17 of the wells will be Cardium wells,
which is a complex geological zone requiring both horizontal and vertical wells
to test the production capabilities of the formation. The drilling in 2003 will
be utilized to test and develop new geological theories on best practices for
exploitation of the Cardium zone, thereby facilitating an expanded 2004 drilling
program. In addition, an observation well will be drilled in the experimental
Pelican Lake emulsion flood project in the first quarter of 2003 to assess the
effectiveness of the injection to date. The Company will also be implementing a
demonstration scale waterflood project to evaluate this secondary recovery
technique, which should increase response time. If either project is successful,
the recovery factor from the Pelican Lake sands is expected to increase. This
field contains approximately three billion barrels of original oil-in-place but
is only expected to achieve a 6% recovery factor using primary technologies.
Following regulatory approval in 2002 to utilize high-pressure steaming at its
thermal oil project at Primrose in eastern Alberta, the Company will develop and
drill new pads containing a total of 48 wells incorporating high-pressure
steaming in 2003. Steaming of these wells will commence in the third quarter of
2003 with initial oil production following in mid 2004.
The Company anticipates receiving regulatory approvals for the Horizon Project
from the Energy and Utilities Board in late 2003. The Company would be in a
position to commence site clearing and pre-construction in 2004, with full
construction commencing upon achieving a targeted 80% completion of detailed
engineering and design. The first phase of the Horizon Project would then be
commissioned in 2008 at 110,000 bbls/d of light synthetic oil. Phase two would
be commissioned in 2010, increasing production to 155,000 bbls/d of production.
Phase three would be completed in 2012, bringing total production to 232,000
bbls/d. The Company's leases could support further expansions beyond that date.
In 2003, the Company has budgeted to spend a total of $281 million on its
international holdings in the North Sea. These funds will be directed towards
drilling 18 wells in the North Sea. Other exploitation and waterflood
optimization programs will also be carried out in both the northern and central
areas of the North Sea to increase the productivity and recovery factors in
these known pools of light oil.
Offshore West Africa budgeted capital expenditures total $280 million in 2003.
In Cote d'Ivoire, the Company will complete the drilling and completion
operations at Espoir, drill an exploration well at Acajou, and finalize the
Baobab development plans with development drilling commencing in the fourth
quarter of 2003. The Company also plans on drilling one of two identified
prospects on its Block 16 exploration acreage, located offshore Angola, during
the second half of 2003. This high-risk/high-potential exploration block, in
which the Company is the operator with a 50% interest, is located in one of the
world's most prolific oil basins.
The original budget was based on an average natural gas price of $5.20 per mcf
at AECO, an oil price of US $24.00 per bbl for WTI and a heavy oil differential
of US $8.50 per bbl. The current price-deck for our products, if maintained,
could result in a significant increase in cash flow over the original budget
established late in 2002. The Company will monitor its expected cash flow excess
and at present intends to allocate a minimum of 50% of such excess towards debt
repayment. The remaining excess will be directed to the Company's authorized
share buy-back program and additional expenditures on conventional oil and
natural gas opportunities. Such expenditures will only be incurred as excess
cash flows are realized and will be subject to the same economic tests as
regular budgeted expenditures. It is expected that the largest portion of the
additional capital expenditures will take place late in the third and fourth
quarters of 2003 and accordingly will not add materially to the Company's 2003
average production volumes. Should additional economic opportunities for share
buy-backs or capital activities not present themselves to the extent allocated,
such allocations of excess cash flow would revert to debt repayment.
2002 Annual Report 47
================================================================================
MANAGEMENT'S DISCUSSION & ANALYSIS
================================================================================
SENSITIVITY ANALYSIS (1)
CASH FLOW FROM CASH FLOW FROM
OPERATIONS(2) OPERATIONS(2) NET EARNINGS(2) NET EARNINGS(2)
($ millions) ($/share, basic) ($ millions) ($/share, basic)
----------------------------------------------------------------------------------------------------------------------------
PRICE CHANGES
Oil - WTI US $1.00/bbl(3)
Excluding financial derivatives $104 $0.78 $69 $0.52
Including financial derivatives $69-$73 $0.51-$0.55 $45-$48 $0.34-$0.36
Natural gas - AECO Cdn $0.10/mcf(3)
Excluding financial derivatives $38 $0.28 $23 $0.17
Including financial derivatives $38 $0.28 $23 $0.17
Volume changes
Oil - 10,000 bbls/d $55 $0.41 $21 $0.15
Natural gas - 10 mmcf/d $12 $0.09 $4 $0.03
Foreign currency rate change
$0.01 change in Cdn $ in relation to US $(3)
Excluding financial derivatives $57 $0.43 $15 $0.11
Including financial derivatives $52-$55 $0.39-$0.41 $12-$14 $0.09-$0.11
Interest rate change - 1% $24 $0.18 $15 $0.11
============================================================================================================================
(1) The sensitivities are calculated based on 2002 fourth quarter results.
(2) Attributable to common shareholders.
(3) For details of financial instruments in place, see consolidated financial
statements note 12.
DAILY PRODUCTION
BY SEGMENT
Q1 Q2 Q3 Q4 2002 2001 2000
----------------------------------------------------------------------------------------------------------------------------
OIL AND LIQUIDS (bbls/d)
North America 152,268 158,196 185,990 181,744 169,675 166,675 154,331
North Sea 30,910 25,685 47,114 51,478 38,876 36,252 17,195
Offshore West Africa 5,261 5,505 8,947 7,374 6,784 3,396 2,065
----------------------------------------------------------------------------------------------------------------------------
Total 188,439 189,386 242,051 240,596 215,335 206,323 173,591
----------------------------------------------------------------------------------------------------------------------------
NATURAL GAS (mmcf/d)
North America 1,026 1,058 1,395 1,331 1,204 906 793
North Sea 27 20 29 32 27 12 1
Offshore West Africa - - 3 2 1 - -
----------------------------------------------------------------------------------------------------------------------------
Total 1,053 1,078 1,427 1,365 1,232 918 794
----------------------------------------------------------------------------------------------------------------------------
BARRELS OF OIL EQUIVALENT
(boe/d)
North America 323,340 334,497 418,600 403,499 370,337 317,658 286,476
North Sea 35,389 29,020 51,946 56,879 43,391 38,293 17,446
Offshore West Africa 5,261 5,505 9,403 7,754 6,994 3,396 2,065
----------------------------------------------------------------------------------------------------------------------------
Total 363,990 369,022 479,949 468,132 420,722 359,347 305,987
----------------------------------------------------------------------------------------------------------------------------
PER UNIT RESULTS
Q1 Q2 Q3 Q4 2002 2001(1) 2000(1)
----------------------------------------------------------------------------------------------------------------------------
OIL AND LIQUIDS ($/bbl)
Sales price $ 24.50 $ 28.27 $ 33.57 $ 31.10 $ 29.76 $ 24.31 $ 29.99
Royalties 2.28 3.02 3.56 3.53 3.16 2.17 3.05
Production expense 7.81 7.95 8.67 9.10 8.45 7.64 6.84
----------------------------------------------------------------------------------------------------------------------------
Netback $ 14.41 $ 17.30 $ 21.34 $ 18.47 $ 18.15 $ 14.50 $ 20.10
----------------------------------------------------------------------------------------------------------------------------
NATURAL GAS ($/mcf)
Sales price $ 3.06 $ 3.68 $ 3.13 $ 5.00 $ 3.76 $ 5.16 $ 4.53
Royalties 0.55 0.77 0.67 1.09 0.78 1.25 1.08
Production expense 0.58 0.57 0.55 0.57 0.57 0.51 0.44
----------------------------------------------------------------------------------------------------------------------------
Netback $ 1.93 $ 2.34 $ 1.91 $ 3.34 $ 2.41 $ 3.40 $ 3.01
BARRELS OF OIL EQUIVALENT
($/boe)
Sales price $ 21.58 $ 25.29 $ 26.26 $ 30.54 $ 26.25 $ 27.15 $ 28.77
Royalties 2.78 3.79 3.80 4.98 3.91 4.42 4.51
Production expense 5.73 5.76 6.01 6.34 5.99 5.69 5.02
----------------------------------------------------------------------------------------------------------------------------
Netback $ 13.07 $ 15.74 $ 16.45 $ 19.22 $ 16.35 $ 17.04 $ 19.24
============================================================================================================================
(1) Restated to conform to current year presentation.
48 Canadian Natural
================================================================================
MANAGEMENT'S DISCUSSION & ANALYSIS
================================================================================
NETBACK ANALYSIS
($/boe, except daily production) 2002 2001(1) 2000(1)
-----------------------------------------------------------------------------------------------
Daily production (boe/d) 420,722 359,347 305,987
Sales price $ 26.25 $ 27.15 $ 28.77
Royalties 3.91 4.42 4.51
Production expense 5.99 5.69 5.02
-----------------------------------------------------------------------------------------------
Netback 16.35 17.04 19.24
Midstream contribution (0.25) (0.12) (0.26)
Administration 0.40 0.29 0.25
Interest 1.03 1.05 1.45
Realized foreign exchange loss (gain) 0.02 (0.01) -
Taxes other than income tax (current) 0.35 0.53 0.51
Current income tax (North Sea) (0.13) 0.47 0.30
Current income tax (Offshore West Africa) 0.04 - -
Current income tax (Large Corporations Tax) 0.14 0.11 0.13
-----------------------------------------------------------------------------------------------
Cash flow $ 14.75 $ 14.72 $ 16.86
===============================================================================================
(1) Restated to conform to current year presentation.
QUARTERLY FINANCIAL INFORMATION
($ millions, except per share amounts) Q1 Q2 Q3 Q4 TOTAL
-----------------------------------------------------------------------------------------------------------------------------
2002
Revenue $ 717.5 $ 862.8 $ 1,172.6 $ 1,330.3 $ 4,083.2
Cash flow from operations attributable
to common shareholders $ 359.1 $ 474.5 $ 643.8 $ 776.6 $ 2,254.0
Per share - basic $ 2.95 $ 3.86 $ 4.83 $ 5.81 $ 17.63
- diluted $ 2.85 $ 3.70 $ 4.71 $ 5.62 $ 16.99
Net earnings attributable to common shareholders $ 98.9 $ 145.2 $ 117.4 $ 208.3 $ 569.8
Per share - basic $ 0.81 $ 1.18 $ 0.88 $ 1.56 $ 4.46
- diluted $ 0.79 $ 1.09 $ 0.86 $ 1.51 $ 4.31
=====================================================================
2001
Revenue $ 1,130.7 $ 981.2 $ 810.5 $ 666.4 $ 3,588.8
Cash flow from operations attributable
to common shareholders $ 629.3 $ 527.6 $ 437.4 $ 325.7 $ 1,920.0
Per share - basic $ 5.15 $ 4.36 $ 3.62 $ 2.69 $ 15.83
- diluted $ 5.03 $ 4.17 $ 3.54 $ 2.65 $ 15.23
Net earnings attributable to common shareholders $ 221.8 $ 286.6 $ 81.3 $ 52.9 $ 642.6
Per share - basic $ 1.82 $ 2.37 $ 0.67 $ 0.44 $ 5.30
- diluted $ 1.77 $ 2.23 $ 0.66 $ 0.43 $ 5.17
=============================================================================================================================
TRADING AND SHARE STATISTICS
Q1 Q2 Q3 Q4 2002 TOTAL 2001 TOTAL
-----------------------------------------------------------------------------------------------------------------------------
TSX - CDN $
Trading volume (thousands) 35,401 40,769 34,404 44,255 154,829 133,744
Share price ($/share)
High $ 53.05 $ 54.54 $ 53.91 $ 50.50 $ 54.54 $ 52.35
Low $ 37.60 $ 46.60 $ 44.10 $ 38.80 $ 37.60 $ 35.90
Close $ 51.60 $ 51.52 $ 50.35 $ 46.80 $ 46.80 $ 38.31
Market capitalization at December 31 ($ millions) $ 6,261 $ 4,643
Shares outstanding (thousands) 133,776 121,201
NYSE - US $
Trading volume (thousands) 1,400 1,923 1,365 3,278 7,966 5,191
Share price ($/share)
High $ 33.25 $ 34.48 $ 34.88 $ 31.81 $ 34.88 $ 34.51
Low $ 23.55 $ 29.52 $ 27.52 $ 24.55 $ 23.55 $ 22.80
Close $ 32.94 $ 34.25 $ 31.80 $ 29.67 $ 29.67 $ 24.40
Market capitalization at December 31 ($ millions) $ 3,969 $ 2,957
Shares outstanding (thousands) 133,776 121,201
=============================================================================================================================
2002 Annual Report 49
DOCUMENT 3
----------
================================================================================
MANAGEMENT'S REPORT AND AUDITOR'S REPORT
================================================================================
MANAGEMENT'S REPORT
The accompanying consolidated financial statements and all information in the
annual report are the responsibility of management. The consolidated financial
statements have been prepared by management in accordance with the accounting
policies in the notes to the consolidated financial statements. Where necessary,
management has made informed judgements and estimates in accounting for
transactions which were not complete at the balance sheet date. In the opinion
of management, the financial statements have been prepared within acceptable
limits of materiality and are in accordance with Canadian generally accepted
accounting principles appropriate in the circumstances. The financial
information elsewhere in the annual report has been reviewed to ensure
consistency with that in the consolidated financial statements.
Management maintains appropriate systems of internal control. Policies and
procedures are designed to give reasonable assurance that transactions are
appropriately authorized, assets are safeguarded from loss or unauthorized use
and financial records are properly maintained to provide reliable information
for preparation of financial statements.
PricewaterhouseCoopers LLP, an independent firm of Chartered Accountants, has
been engaged, as approved by a vote of the shareholders at the Company's most
recent Annual General Meeting, to examine the consolidated financial statements
in accordance with generally accepted auditing standards in Canada and provide
an independent professional opinion. Their report is presented with the
consolidated financial statements.
The Board of Directors is responsible for ensuring that management fulfills its
responsibilities for financial reporting and internal control. The Board
exercises this responsibility through the Audit Committee of the Board. This
committee, which is comprised of non-management directors, meets with management
and the external auditors to satisfy itself that management responsibilities are
properly discharged and to review the consolidated financial statements before
they are presented to the Board of Directors for approval. The consolidated
financial statements have been approved by the Board of Directors on the
recommendation of the Audit Committee.
/s/ John G. Langille /s/ Douglas A. Proll /s/ Randall S. Davis
-------------------- -------------------- --------------------
John G. Langille, CA Douglas A. Proll, CA Randall S. Davis, CA
President and Director Senior Vice-president, Finance Financial Controller
February 26, 2003
AUDITORS' REPORT
To the Shareholders of Canadian Natural Resources Limited
We have audited the consolidated balance sheets of Canadian Natural Resources
Limited as at December 31, 2002 and 2001 and the consolidated statements of
earnings, retained earnings and cash flows for each of the years in the three
year period ended December 31, 2002. These consolidated 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 in accordance with Canadian generally accepted auditing
standards. Those standards require that we plan and perform an audit to obtain
reasonable assurance whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
In our opinion, these consolidated financial statements present fairly, in all
material respects, the financial position of the Company as at December 31, 2002
and 2001 and the results of its operations and its cash flows for each of the
years in the three year period ended December 31, 2002 in accordance with
Canadian generally accepted accounting principles.
/s/ PriceWatershouseCooper LLP Calgary, Alberta, Canada
Chartered Accountants February 26, 2003
Comments by Auditor for US readers on Canada-US 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 financial statements, such as the change described in note 2 to
the consolidated financial statements. Our report to the shareholders dated
February 26, 2003 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 financial statements.
/s/ PriceWatershouseCooper LLP Calgary, Alberta, Canada
Chartered Accountants February 26, 2003
50 Canadial Natural
================================================================================
CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
CONSOLIDATED BALANCE SHEETS
As at December 31
(millions of Canadian dollars) 2002 2001
------------------------------------------------------------------------------------------
ASSETS
Current assets
Cash $ 30.0 $ 15.0
Accounts receivable and other 745.2 509.0
------------------------------------------------------------------------------------------
775.2 524.0
Property, plant and equipment (note 4) 12,499.6 8,442.9
Deferred charges 84.1 -
13,358.9 8,966.9
==========================================================================================
LIABILITIES
Current liabilities
Accounts payable 336.5 249.5
Accrued liabilities 428.4 264.2
Current portion of long-term debt (note 5) 24.1 15.9
------------------------------------------------------------------------------------------
789.0 529.6
Long term debt (note 5) 4,074.0 2,669.2
Future site restoration (note 6) 440.4 193.8
Future income tax (note 7) 3,187.4 1,767.3
------------------------------------------------------------------------------------------
8,490.8 5,159.9
------------------------------------------------------------------------------------------
SHAREHOLDER'S EQUITY
------------------------------------------------------------------------------------------
Preferred securities (note 8) 126.4 127.4
Share capital (note 9) 2,303.8 1,698.3
Retained earnings 2,414.3 1,908.5
Foreign currency translation adjustment (note 10) 23.6 72.8
------------------------------------------------------------------------------------------
4,868.1 3,807.0
------------------------------------------------------------------------------------------
$ 13,358.9 $ 8,966.9
==========================================================================================
Commitments (note 13) on behalf of the Board:
/s/ Gordon D. Giffin /s/ N. Murray Edwards
--------------------------- -------------------------
Ambassador Gordon D. Giffin N. Murray Edwards
Chairman of the Audit Committee Vice-Chairman of the
and Director Corporation and Director
2002 Annual Report 51
================================================================================
CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
CONSOLIDATED FINANCIAL STATEMENTS
For the Years Ended December 31
(millions of Canadian dollars, except per common share amounts) 2002 2001 2000
-------------------------------------------------------------------------------------------------------------
REVENUE $ 4,083.2 $ 3,588.8 $ 3,260.6
Less: royalties (600.3) (580.3) (506.2)
-------------------------------------------------------------------------------------------------------------
3,482.9 3,008.5 2,754.4
=============================================================================================================
EXPENSES
Production 933.9 757.9 571.0
Depletion, depreciation and amortization 1,314.2 903.8 644.6
Administration 61.3 37.6 27.2
Interest 158.9 137.8 162.3
Foreign exchange (gain) loss (note 2) (31.7) 62.8 15.9
Loss on sale of United States assets (note 4) - 24.1 -
-------------------------------------------------------------------------------------------------------------
2,436.6 1,924.0 1,421.0
-------------------------------------------------------------------------------------------------------------
EARNINGS BEFORE TAXES 1,046.3 1,084.5 1,333.4
Taxes other than income tax (note 7) 62.9 69.1 49.5
Current income tax (note 7) 7.6 76.9 48.4
Future income tax (note 7) 401.0 282.5 464.0
-------------------------------------------------------------------------------------------------------------
NET EARNINGS 574.8 656.0 771.5
Dividend on preferred securities, net of tax (6.0) (5.9) (2.8)
Revaluation of preferred securities (note 2) 1.0 (7.5) (1.6)
-------------------------------------------------------------------------------------------------------------
Net earnings attributable to common shareholders $ 569.8 $ 642.6 $ 767.1
=============================================================================================================
Net earnings attributable to common shareholders
per common share (note 11)
Basic $ 4.46 $ 5.30 $ 6.57
Diluted $ 4.31 $ 5.17 $ 6.39
=============================================================================================================
CONOLIDATED STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31
(millions of Canadian dollars) 2002 2001 2000
-------------------------------------------------------------------------------------------------------------
Balance - beginning of year as previously reported $ 1,979.5 $ 1,406.0 $ 623.8
Change in accounting policy - foreign exchange (note 2) (71.0) (15.4) (0.3)
=============================================================================================================
Balance - beginning of year as restated 1,908.5 1,390.6 623.5
Net earnings 574.8 656.0 771.5
Dividend on preferred securities, net of tax (6.0) (5.9) (2.8)
Revaluation of preferred securities (note 2) 1.0 (7.5) (1.6)
Dividend on common shares (note 9) (64.0) (48.5) -
Purchase of common shares (note 9) - (76.2) -
-------------------------------------------------------------------------------------------------------------
Balance - end of year $ 2,414.3 $ 1,908.5 $ 1,390.6
=============================================================================================================
52 Canadian Natural
================================================================================
CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
For the Years Ended December 31
(millions of Canadian dollars) 2002 2001 2000
---------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net earnings $ 574.8 $ 656.0 $ 771.5
Non-cash items
Depletion, depreciation and amortization 1,314.2 903.8 644.6
Unrealized foreign exchange (gain) loss (35.1) 64.1 16.1
Deferred petroleum revenue tax 9.5 (0.2) (7.6)
Future income tax 401.0 282.5 464.0
Loss on sale of United States assets - 24.1 -
---------------------------------------------------------------------------------------------------------
Cash flow provided from operations 2,264.4 1,930.3 1,888.6
Deferred charges (84.1) - -
Net change in non-cash working capital (156.9) (42.2) (55.4)
---------------------------------------------------------------------------------------------------------
2,023.4 1,888.1 1,833.2
---------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Repayment of bank credit facilities (1,234.3) (442.3) (187.7)
Issue of medium-term notes - - 125.0
Repayment of senior unsecured notes (15.9) (15.8) (15.1)
Issue of US dollar debt securities 1,749.3 615.2 -
Repayment of obligations under capital leases (3.9) - -
Repayment of limited recourse loan - (11.8) (0.7)
Dividend on preferred securities (10.4) (10.3) (5.0)
Issue of common shares 84.1 42.8 66.4
Dividend on common shares (59.4) (36.4) -
Purchase of common shares - (113.3) -
Net change in non-cash working capital 26.0 7.4 5.8
---------------------------------------------------------------------------------------------------------
535.5 35.5 (11.3)
---------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Business combinations, net of cash acquired (note 3) (843.2) - (722.8)
Expenditures on property, plant and equipment (1,752.3) (1,947.5) (1,294.6)
Net proceeds on sale of property, plant and equipment 76.1 63.0 160.3
---------------------------------------------------------------------------------------------------------
Net expenditures on property, plant and equipment (2,519.4) (1,884.5) (1,857.1)
Net change in non-cash working capital (24.5) (52.1) 63.1
---------------------------------------------------------------------------------------------------------
(2,543.9) (1,936.6) (1,794.0)
=========================================================================================================
Increase (decrease) in cash 15.0 (13.0) 27.9
Cash - beginning of year 15.0 28.0 0.1
---------------------------------------------------------------------------------------------------------
Cash - end of year $ 30.0 $ 15.0 $ 28.0
=========================================================================================================
Supplemental disclosure of cash flow information (note 14)
2002 Annual Report 53
================================================================================
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(tabular amounts in million of Canadian dollars, unless otherwise noted)
================================================================================
1. ACCOUNTING POLICIES
Canadian Natural Resources Limited (the "Company") is a senior independent oil
and natural gas exploration, development and production company based in
Calgary, Alberta, Canada. The Company's operations are focused in North America,
largely in western Canada, the North Sea and Offshore West Africa.
Within western Canada, the Company is developing its Horizon Oil Sands Project
(the "Horizon Project") and maintains its midstream activities. The Horizon
Project involves a plan to recover bitumen through mining operations, while the
midstream activities include the Company's 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. A summary of
differences between accounting principles in Canada and those generally accepted
in the United States ("US") is contained in note 16.
Significant accounting policies are summarized as follows:
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the Company and
all of its subsidiaries and partnerships. Portions 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.
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.
Depletion, depreciation and amortization and amounts used for ceiling test
calculations are based on estimates of proved oil and natural gas reserves and
future sales prices, production expenses and capital costs required to develop
and produce those reserves. The majority of the Company's reserve estimates are
evaluated annually by independent engineering firms. By their nature, estimates
of reserves and the related future cash flows 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 measurement of petroleum revenue tax expense and the related provision in
the consolidated financial statements are subject to uncertainty associated with
future recoverability of oil and natural gas reserves, commodity prices and the
timing of future events, which could result in material changes to deferred
amounts.
CASH
Cash comprises cash on hand and demand deposits. Other investments (term
deposits and certificates of deposit) with a term to maturity of three months or
less from the transaction date are reported as cash equivalents.
PROPERTY, PLANT AND EQUIPMENT
The Company follows the full cost method of accounting for oil and natural gas
properties and equipment as prescribed by the Canadian Institute of Chartered
Accountants ("CICA"). Accordingly, all costs relating to the exploration for and
development of oil and natural gas reserves are capitalized and accumulated in
country-by-country cost centres. Administrative overhead incurred during the
development phase of large capital projects is capitalized until commercial
production commences. Proceeds on disposal of properties are ordinarily deducted
from such costs without recognition of profit or loss except where such disposal
constitutes a significant portion of the Company's reserves in that country.
DEPLETION, DEPRECIATION AND AMORTIZATION
The 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. 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. The unproved properties are assessed periodically to ascertain
whether impairment has occurred. When proved reserves are assigned or the value
of the 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.
Certain costs in cost centres from which there has been no commercial production
are not subject to depletion until commercial production commences.
Processing and production facilities, net of salvage value, are depreciated on a
straight-line basis over their estimated useful lives of 20 years.
The Company carries its oil and natural gas properties at the lower of net
capitalized cost and net recoverable amount (the "ceiling test"). The net
capitalized cost of each cost centre is calculated as the net book value of the
related assets less the accumulated provisions for future income taxes and
future site restoration. Net recoverable amount is limited to the sum of
undiscounted future net revenues from proved properties and the cost of unproved
properties net of provisions for impairment less estimated future financing and
administrative expenses and income taxes. Future net revenues are based on sales
prices and costs prevailing at year end.
The Company carries its midstream assets at the lower of net capitalized cost
and net recoverable amount. Midstream assets, net of salvage value, are
depreciated on a straight-line basis over their estimated useful lives of 20
years.
54 Canadian Natural
================================================================================
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(tabular amounts in million of Canadian dollars, unless otherwise noted)
================================================================================
Other capital assets are amortized on a declining balance basis over their
estimated useful lives of five years.
DEFERRED CHARGES
Deferred charges include deferred financing costs associated with the issuance
of long-term debt and settlement costs of long-term natural gas contracts.
Deferred charges are amortized over the original term of the related instrument.
FUTURE SITE RESTORATION
Estimated future dismantlement, site restoration and abandonment costs of oil
and natural gas properties are provided for using the unit-of-production method.
Processing and production facilities are provided for using the straight-line
method over their estimated useful lives of 20 years. The estimated costs are
based on engineering estimates using current costs and technology in accordance
with current legislation and industry practice. The annual provision is included
in depletion, depreciation and amortization. Expenditures incurred to dismantle
the processing and production facilities and to abandon and restore well sites
are charged against the related site restoration liability.
FOREIGN CURRENCY TRANSLATION
Foreign operations that are operationally and financially independent 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 the foreign
currency translation adjustment in shareholders' equity in the consolidated
balance sheets.
Foreign operations that are not considered to be self-sustaining 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 and
non-monetary assets and liabilities are translated at the rate of exchange 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 items.
PETROLEUM REVENUE TAX
The Company accounts for future United Kingdom petroleum revenue tax ("PRT") by
the life-of-the-field method. The total future liability or recovery of PRT is
estimated using current sales prices and costs. The estimated future PRT is
apportioned to accounting periods on the basis of total estimated future
revenues. Changes in the estimated total future PRT are accounted for
prospectively.
PRODUCTION SHARING CONTRACT
Production generated from the Espoir field, offshore Cote d'Ivoire, is shared by
the terms of the Production Sharing Contract ("PSC") with the State Oil Company
of Cote d'Ivoire ("Petroci"). Revenues are divided into cost recovery revenues
and profit revenues. Cost recovery revenues allow the Company to recover the
capital and operating costs carried by the Company on behalf of Petroci. These
revenues are reported as sales revenues. Profit revenues are allocated to the
Espoir joint venture partners in accordance with their respective equity
interests, after a portion has been allocated to the Cote d'Ivoire Government.
The Government's share of revenues, attributable to the Company's equity
interest, is reported as either a royalty expense or a current tax expense in
accordance with the PSC.
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 on 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.
REVENUE RECOGNITION
Revenues are recognized when products have been delivered or services have been
performed.
STOCK-BASED COMPENSATION PLANS
The Company accounts for its stock-based compensation using the intrinsic value
method; therefore, no stock-based compensation expense is recorded either on
granting or exercise of stock options under the Company's Stock Option Plan (the
"Option Plan"). Consideration paid by employees, officers or directors on the
exercise of stock options under the Option Plan is recorded as share capital.
The Company matches employee contributions to the Company's Stock Savings Plan
and these cash payments are recorded as compensation expense.
FINANCIAL INSTRUMENTS
Financial instruments are utilized by the Company to manage its commodity
prices, foreign currency and interest rate exposures. These financial
instruments are entered into solely for hedging purposes and are not used for
trading or other speculative purposes.
2002 Annual Report 55
================================================================================
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
The Company's policy is to formally document relationships between hedging
instruments and hedged items, the risk management objective, and the strategy
for undertaking various hedge transactions. The Company assesses whether the
financial instruments entered into are highly effective as fair value and cash
flow hedges, both at the inception of the hedge and over the term of the
financial instrument.
The Company enters into commodity price contracts to hedge anticipated sales of
oil and natural gas production in order to protect cash flow for capital
expenditure programs. Gains or losses on these contracts are included in oil and
natural gas revenue at the time of sale of the related product.
Foreign exchange translation gains and losses on foreign currency denominated
financial instruments used to hedge anticipated US dollar denominated oil and
natural gas sales are recognized in revenue at the time of sale of the related
product.
The Company has assumed, through the Rio Alto acquisition, a foreign currency
swap agreement that hedges a foreign currency denominated long-term debt
instrument through an offsetting forward exchange contract. The foreign exchange
translation gains and losses on the financial instrument are used to offset the
respective translation gains and losses recognized on the long-term debt.
The Company enters into interest rate swap agreements to manage its fixed to
floating interest rate mix on long-term debt. These swaps are designated as
hedges of the underlying debt. The interest rate swap agreements require the
periodic exchange of payments without the exchange of the notional principal
amount on which the payments are based. Gains or losses on these financial
instruments are included in interest expense in the consolidated statement of
earnings when realized. The related amount receivable from or payable to
counterparties is included as an adjustment to accrued interest in the
consolidated balance sheets.
Realized gains and losses on the termination of financial instruments that have
been accounted for as hedges are deferred under non-current assets or
liabilities on the consolidated balance sheets and recognized in net earnings in
the period in which the underlying hedged transaction is recognized.
In the event a designated hedged item is sold, extinguished or matures prior to
the termination of the related derivative instrument, any realized or unrealized
gain or loss on such derivative instrument is recognized in net earnings.
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 and other dilutive
instruments are used to purchase common shares at the average market price
during the year.
COMPARATIVE FIGURES
Certain figures provided for prior years have been reclassified to conform to
the presentation adopted in 2002.
2. CHANGE IN ACCOUNTING POLICY
FOREIGN CURRENCY TRANSLATION
Effective January 1, 2002, the Company retroactively adopted the CICA's new
accounting standard with respect to foreign currency translation. As a result of
adopting this new standard, gains or losses on the translation of long-term debt
denominated in US dollars are no longer deferred and amortized over the term of
the debt. Translation gains or losses are either recognized in net earnings
immediately, or in the foreign currency translation adjustment (note 10) for
translation gains or losses on that portion of the US dollar denominated debt
designated as a hedge of self-sustaining foreign operations. This new standard
has been adopted retroactively and prior periods have been restated.
The new standard affects the Company's accounting for US dollar denominated
long-term debt and preferred securities. Adoption of the new accounting policy
had the following effects on the Company's consolidated financial statements:
2002 2001 2000
-----------------------------------------------------------------------------------------------------
Consolidated balance sheets
-----------------------------------------------------------------------------------------------------
Decrease deferred foreign exchange loss $ - $ (61.9) $ (13.8)
(Decrease) increase preferred securities $ (1.0) $ 9.1 $ 1.6
Decrease in opening retained earnings $ (71.0) $ (15.4) $ (0.3)
Consolidated statements of earnings
Foreign exchange (gain) loss $ (53.3) $ 48.1 $ 13.5
Revaluation of preferred securities (gain) loss $ (1.0) $ 7.5 $ 1.6
Increase (decrease) net earnings attributable to
common shareholders per common share
- Basic $ 0.42 $ (0.46) $ (0.13)
- Diluted $ 0.40 $ (0.38) $ (0.11)
-----------------------------------------------------------------------------------------------------
3. BUSINESS COMBINATIONS
RIO ALTO EXPLORATION LTD.
In July 2002, the Company paid cash of $850.0 million and issued 10,008,218
common shares with an attributed value of $522.4 million to acquire all of the
issued and outstanding common shares of Rio Alto Exploration Ltd. ("Rio Alto")
by way of a plan of arrangement (the "Plan of Arrangement").
56 Canadian Natural
================================================================================
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
Rio Alto was engaged in the exploration for and production of oil and natural
gas in western Canada and through wholly owned subsidiaries, in South America.
Under the Plan of Arrangement, the subsidiaries of Rio Alto that held its South
American properties were sold to a new company, Rio Alto Resources International
Inc. ("Rio Alto International"), and each shareholder of Rio Alto received one
common share of Rio Alto International for each Rio Alto common share held.
The acquisition was accounted for based on the purchase method. Results of Rio
Alto are consolidated with the results of the Company since the date of
acquisition. The allocation of the purchase price to assets acquired and
liabilities assumed based on their fair values is set out in the following
table:
July 1, 2002
--------------------------------------------------------------------------------
Purchase price:
--------------------------------------------------------------------------------
Cash consideration $ 850.0
Share consideration 522.4
Cash acquired (6.8)
Non-cash working capital deficit assumed 91.3
Long-term debt assumed 936.3
--------------------------------------------------------------------------------
Total purchase price $ 2,393.2
================================================================================
Purchase price allocated as follows:
--------------------------------------------------------------------------------
Property, plant and equipment $ 3,411.8
Future site restoration (43.5)
Future income tax (975.1)
--------------------------------------------------------------------------------
$ 2,393.2
================================================================================
RANGER OIL LIMITED
In July 2000, the Company paid cash of $722.8 million and issued 7,602,068
common shares with an attributed value of $358.0 million to acquire all of the
issued and outstanding common shares of Ranger Oil Limited ("Ranger"). Ranger
was engaged in the exploration for and development of oil and natural gas in the
North Sea, North America and Offshore West Africa.
The acquisition was accounted for based on the purchase method. Results of
Ranger are consolidated with the results of the Company since the date of
acquisition. The allocation of the purchase price to assets acquired and
liabilities assumed based on their fair values is set out in the following
table:
July 1, 2000
--------------------------------------------------------------------------------
Purchase price:
--------------------------------------------------------------------------------
Cash consideration $ 722.8
Share consideration 358.0
Non-cash working capital deficit assumed 111.6
Long-term debt assumed 376.6
Preferred securities assumed 118.3
--------------------------------------------------------------------------------
Total purchase price $ 1,687.3
================================================================================
Purchase price allocated as follows:
--------------------------------------------------------------------------------
Property, plant and equipment $ 1,966.4
Future site restoration (129.3)
Future income tax (149.8)
--------------------------------------------------------------------------------
$ 1,687.3
================================================================================
4. PROPERTY, PLANT AND EQUIPMENT
2002
--------------------------------------------------------------------------------
ACCUMULATED
DEPLETION AND
COST DEPRECIATION NET
--------------------------------------------------------------------------------
Oil and natural gas
--------------------------------------------------------------------------------
North America $ 13,863.3 $ 3,611.3 $ 10,252.0
North Sea 1,621.2 344.2 1,277.0
Offshore West Africa 611.9 93.6 518.3
Horizon Project 228.7 - 228.7
Midstream 214.0 18.4 195.6
Other 50.1 22.1 28.0
--------------------------------------------------------------------------------
$ 16,589.2 $ 4,089.6 $ 12,499.6
================================================================================
2002 Annual Report 57
================================================================================
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
PROPERTY, PLANT AND EQUIPMENT (continued)
2001
--------------------------------------------------------------------------------
Accumulated
depletion and
Cost depreciation Net
--------------------------------------------------------------------------------
Oil and natural gas
--------------------------------------------------------------------------------
North America $ 9,424.7 $ 2,617.1 $ 6,807.6
North Sea 1,050.3 184.7 865.6
Offshore West Africa 425.2 15.3 409.9
Horizon Project 160.6 - 160.6
Midstream 193.6 10.8 182.8
Other 32.3 15.9 16.4
--------------------------------------------------------------------------------
$ 11,286.7 $ 2,843.8 $ 8,442.9
================================================================================
During the year ended December 31, 2002, the Company capitalized administrative
overhead of $13.0 million (2001 - $6.7 million; 2000 - $3.7 million) relating to
exploration and development in the North Sea and Offshore West Africa and $3.9
million (2001 - $nil, 2000 - $nil) relating to the Horizon Project in North
America. During 2001, the Company sold a large portion of its properties in the
United States and recorded a loss on sale of $24.1 million.
Included in property, plant and equipment are undeveloped land and projects
under development that are not subject to depletion or depreciation:
2002 2001 2000
--------------------------------------------------------------------------------
Oil and natural gas
--------------------------------------------------------------------------------
North America $ 666.8 $ 424.0 $ 351.5
North Sea 62.0 49.5 45.5
Offshore West Africa 131.8 398.8 175.3
Horizon Project 228.7 160.6 141.8
--------------------------------------------------------------------------------
$ 1,089.3 $ 1,032.9 $ 714.1
================================================================================
5. LONG-TERM DEBT
2002 2001
------------------------------------------------------------------------------------------------------------------------
Bank credit facilities
Bankers' acceptances $ 728.0 $ 1,003.4
US $ Bankers' acceptances (2002 - US $150.0 million, 2001 - US $196.0 million) 236.9 312.1
US $ LIBOR advances (2002 - US $nil, 2001 - US $100.0 million) - 159.3
Medium-term notes
6.85% unsecured debentures due May 28, 2004 125.0 125.0
7.40% unsecured debentures due March 1, 2007 125.0 125.0
Senior unsecured notes
6.95% due September 30, 2003 (2002 - US $10.0 million, 2001 - US $20.0 million) 15.8 31.9
6.42% due May 27, 2004 (US $40.0 million) 63.2 63.7
7.69% due December 19, 2005 (US $125.0 million) 193.7 -
6.50% due May 1, 2008 (US $50.0 million) 79.0 79.6
Adjustable rate due May 27, 2009 (US $93.0 million) 146.9 148.1
US dollar debt securities
6.70% due July 15, 2011 (US $400.0 million) 631.8 637.0
5.45% due October 1, 2012 (US $350.0 million) 552.9 -
7.20% due January 15, 2032 (US $400.0 million) 631.8 -
6.45% due June 30, 2033 (US $350.0 million) 552.9 -
Obligations under capital leases 15.2 -
------------------------------------------------------------------------------------------------------------------------
4,098.1 2,685.1
Less: current portion of long-term debt 24.1 15.9
------------------------------------------------------------------------------------------------------------------------
$ 4,074.0 $ 2,669.2
========================================================================================================================
58 Canadian Natural
================================================================================
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
BANK CREDIT FACILITIES
The Company has unsecured bank credit facilities of $2,275.0 million comprised
of a $100.0 million operating demand facility, a revolving credit and term loan
facility of $1,675.0 million and a $500.0 million acquisition term credit
facility repayable July 3, 2004. The Canadian dollar revolving credit and term
loan facility is fully revolving for 364-day periods with a provision for
extension at the mutual agreement of the Company and the lenders. If not
extended, the facility converts to a non-revolving reducing loan with a term of
three years. Principal payments during the term period amortize on the basis of
one-third of the outstanding principal being due 12 months after the initiation
of the term period followed by eight equal quarterly payments thereafter. The
facility provides that the borrowings may be made by way of operating advances,
prime loans, bankers' acceptances, US base rate loans or US dollar LIBOR
advances which bear interest at the bank's prime rates or at money market rates
plus applicable margins. During the year, the Company repaid and cancelled a
$725.0 million credit and term loan facility and a US $150.0 million credit and
term loan facility.
The weighted average interest rate of bank credit facilities outstanding at
December 31, 2002 was 3.37% (2001 - 2.71%). Included in this rate is debt under
the bank credit facilities totaling $100.0 million that is subject to an
interest rate swap that fixes the interest rate at 5.08% plus a stamping fee
(note 12).
In addition to the outstanding debt, letters of credit aggregating to $25.1
million have been issued.
MEDIUM-TERM NOTES
In July 2001, the Company authorized a medium-term note program in the aggregate
principal amount of up to $1.0 billion for issue in Canada until July 2003. If
issued, these notes will bear interest as determined at the date of issuance. No
amounts are currently drawn under this program. The Company has $250.0 million
of unsecured debentures outstanding from a previous medium-term note program.
SENIOR UNSECURED NOTES
The final principal repayment on the 6.95% senior unsecured notes is due
September 30, 2003. The 6.42% senior unsecured notes are due in full May 27,
2004. Annual principal repayments of US $10.0 million on the 6.50% notes
commence May 1, 2004, and are payable through May 1, 2008. The adjustable rate
senior unsecured notes bear interest at 6.54% increasing to 6.64% under certain
circumstances, and have annual principal repayments of US $31.0 million
commencing on May 27, 2007, through May 27, 2009. The debt instruments contain
covenants pertaining to the Company's net worth, certain financial ratios and
the ability to grant security.
On July 1, 2002, as part of the Rio Alto acquisition, the Company assumed US
$125.0 million of senior unsecured notes maturing December 19, 2005, bearing
interest at 7.69%. Through a currency swap, the interest and principal repayment
amounts are fixed at 7.30% and $193.7 million, respectively (note 12).
US DOLLAR DEBT SECURITIES
On July 24, 2001, the Company issued US $400.0 million of US dollar debt
securities, maturing July 15, 2011, bearing interest at 6.70%. Subsequently, the
Company entered into interest rate swap contracts that convert the fixed rate
interest coupon into a floating interest rate for a portion of the term (note
12).
On January 23, 2002, the Company issued US $400.0 million of US dollar debt
securities, maturing January 15, 2032, bearing interest at 7.20%. Proceeds from
the securities issued were used to repay bankers' acceptances under the
Company's bank credit facilities. Subsequently, the Company entered into
interest rate swap contracts that convert the fixed rate interest coupon into a
floating interest rate for a portion of the term (note 12).
On September 16, 2002, the Company issued US $350.0 million of US dollar debt
securities maturing October 1, 2012, bearing interest at 5.45% and US $350.0
million of US dollar debt securities maturing June 30, 2033, bearing interest at
6.45%. Proceeds from the securities issued were used to repay bankers'
acceptances under the Company's bank credit facilities. Subsequently, the
Company entered into interest rate swap contracts that convert the fixed rate
interest coupon into a floating interest rate for a portion of the ten-year
securities (note 12).
The Company has US $300.0 million remaining on a US $1.0 billion shelf
prospectus filed on August 16, 2002 that allows for the issue of debt securities
until September 2004. If issued, these securities will bear interest as
determined at the date of issuance.
OBLIGATIONS UNDER CAPITAL LEASES
The obligations under capital leases bear interest at an average interest rate
of 6.91% and are secured by the related assets.
REQUIRED DEBT REPAYMENTS
Required debt repayments are as follows:
Year Repayment
--------------------------------------------------------------------------------
2003 $ 24.1
2004 $ 710.8
2005 $ 209.5
2006 $ 15.8
2007 $ 189.8
Thereafter $ 2,483.2
================================================================================
2002 Annual Report
================================================================================
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
No debt repayments are reflected for the bank credit facilities due to the
extendable nature of the facilities, other than the $500.0 million acquisition
term credit facility due July 3, 2004.
6. FUTURE SITE RESTORATION
2002 2001
--------------------------------------------------------------------------------
Balance - beginning of year $ 193.8 $ 170.5
Future site restoration provision 69.4 34.1
Current year expenditures (34.3) (9.4)
Acquisitions and dispositions 211.5 (1.4)
--------------------------------------------------------------------------------
Balance - end of year $ 440.4 $ 193.8
================================================================================
At December 31, 2002, the Company's total estimated future site restoration
costs, excluding salvage values, were $1,986.2 million (2001 - $1,081.0 million,
2000 - $874.3 million). These costs are accrued over the life of the Company's
proved reserves.
7. TAXES
Taxes other than income tax 2002 2001 2000
----------------------------------------------------------------------------------------------
Current petroleum revenue tax $ 41.6 $ 59.3 $ 40.9
Deferred petroleum revenue tax 9.5 (0.2) (7.6)
Provincial capital taxes and surcharges 11.1 8.5 12.3
Other 0.7 1.5 3.9
----------------------------------------------------------------------------------------------
$ 62.9 $ 69.1 $ 49.5
==============================================================================================
Income tax
The provision for income tax is as follows:
2002 2001 2000
----------------------------------------------------------------------------------------------
Current income tax expense
Current income tax - North Sea $ (19.6) $ 61.8 $ 33.7
Current income tax - Offshore West Africa 6.0 - -
Large Corporations Tax - North America 21.2 15.1 14.7
----------------------------------------------------------------------------------------------
7.6 76.9 48.4
Future income tax expense 401.0 282.5 464.0
----------------------------------------------------------------------------------------------
Income taxes $ 408.6 $ 359.4 $ 512.4
==============================================================================================
The provision for income taxes 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:
2002 2001 2000
----------------------------------------------------------------------------------------------
Canadian statutory income tax rate 42.4% 42.8% 44.0%
----------------------------------------------------------------------------------------------
Income tax provision at statutory rate $ 443.6 $ 464.2 $ 586.7
Effect on income taxes of:
Non-deductible crown royalties,
lease rentals and mineral taxes 211.0 201.1 193.2
Resource allowance (243.4) (219.5) (238.1)
Large Corporations Tax 21.2 15.1 14.7
Deductible petroleum revenue tax (21.7) (25.3) (14.6)
Foreign income tax rate differentials (1.4) (18.9) (40.9)
Provincial income tax rate reductions (20.5) (63.1) -
UK income tax rate increase 34.0 - -
Foreign exchange (21.7) 20.6 5.9
Other 7.5 (14.8) 5.5
----------------------------------------------------------------------------------------------
Income taxes $ 408.6 $ 359.4 $ 512.4
==============================================================================================
60 Canadian Natural
================================================================================
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
The following table summarizes the temporary differences that give rise to the
future income tax liability:
2002 2001
--------------------------------------------------------------------------------
Future income tax liabilities
--------------------------------------------------------------------------------
Property, plant and equipment $ 2,656.0 $ 1,384.8
Timing of partnership items 736.9 493.2
Other 27.5 5.0
Future income tax assets
Future site restoration (160.5) (54.1)
Attributed Canadian Royalty Income (54.0) (39.8)
Other (14.1) (9.9)
Deferred petroleum revenue tax (4.4) (11.9)
--------------------------------------------------------------------------------
Future income tax liability $ 3,187.4 $ 1,767.3
================================================================================
8. PREFERRED SECURITIES
The US $80.0 million preferred securities are in the form of 8.30% subordinated
notes. Principal repayments of US $26.7 million are required annually commencing
June 25, 2009. The securities may be prepaid at the option of the Company at any
time. The prepaid amount is subject to certain adjustments to compensate holders
for any potential loss of return over the original life of the securities, based
on market conditions at that time. The notes are subordinated to the long-term
debt of the Company and contain, among other things, certain financial covenants
restricting the granting of security for new borrowings and the maintenance of
specified financial ratios.
The Company has the unrestricted right to pay dividends, principal and principal
prepayment amounts by delivering common shares to the Trustee of the preferred
securities. Accordingly, the preferred securities are classified as
shareholders' equity in the consolidated balance sheets. Dividend payments, net
of tax, are charged directly to retained earnings. The semi-annual dividend
payments may be deferred at the option of the Company for up to two consecutive
periods, with a maximum of eight deferral periods over the life of the
securities.
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
2002 2001
----------------------------------------------------------------------------------------------------------------------------
NUMBER OF SHARES AMOUNT NUMBER OF SHARES AMOUNT
COMMON SHARES (THOUSANDS) (THOUSANDS)
----------------------------------------------------------------------------------------------------------------------------
Balance - beginning of year 121,201 $ 1,698.3 122,279 $ 1,688.0
----------------------------------------------------------------------------------------------------------------------------
Issued upon acquisition of Rio Alto 10,008 522.4 - -
Issued upon exercise of stock options 2,523 82.1 1,005 29.2
Issue of flow-through shares, net of tax 60 1.3 - -
Cancellation of common shares (16) (0.3) - -
Exercise of warrants - - 455 16.3
Purchase of common shares under Normal Course Issuer Bid - - (2,538) (35.2)
----------------------------------------------------------------------------------------------------------------------------
Balance - end of year 133,776 $ 2,303.8 121,201 $ 1,698.3
============================================================================================================================
The Company issued 10,008,218 common shares at an attributed value of $522.4
million as part of the consideration to acquire Rio Alto (note 3).
In January 2002, the Company issued 60,000 flow-through common shares to a
director of the Company at a price of $39.00 per common share, for total
proceeds of $2.3 million. The value of the common shares was determined as the
closing market price of the common shares on the Toronto Stock Exchange on the
day prior to the allotment.
2002 Annual Report 61
================================================================================
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
During the the year, 16,288 common shares were returned to treasury and
cancelled on the expiry of the conversion period for exchanging shares of
companies previously acquired for common shares of the Company.
NORMAL COURSE ISSUER BID
In January 2003, the Company renewed its Normal Course Issuer Bid, allowing the
Company to purchase up to 6,692,799 common shares or 5% of the Company's
outstanding common shares on the date of announcement, during the 12-month
period beginning January 24, 2003 and ending January 23, 2004. As at February
26, 2003, 175,600 common shares for a total cost of $8.3 million have been
purchased under this renewed Normal Course Issuer Bid.
Under a previous Normal Course Issuer Bid, the Company purchased 2,537,800
common shares in 2001 for a total cost of $113.3 million. The excess cost over
book value of the common shares purchased was applied to eliminate contributed
surplus and reduce retained earnings.
DIVIDEND POLICY
The Company pays regular quarterly dividends in January, April, July and October
of each year. In February 2003, the Board of Directors set the Company's regular
quarterly dividend at $0.15 per common share (2002 - $0.125 per common share,
2001 - $0.10 per common share, 2000 - $nil per common share) commencing with the
April 1, 2003 payment.
WARRANTS
During 1999, the Company issued 500,000 warrants at an ascribed value of $2.9
million to acquire property, plant and equipment. Each warrant entitled the
holder to acquire one common share of the Company at a price of $30.00 per
common share until August 16, 2001.
STOCK OPTIONS
The Company's Stock Option Plan (the "Option Plan") provides for the granting of
stock options to directors, officers and employees. Stock options granted under
the Option Plan have a maximum term of six years to expiry and vest equally over
a five-year period starting on the first anniversary date of the grant. The
exercise price of each stock option granted is determined as the closing market
price of the common shares on the Toronto Stock Exchange on the day prior to the
day of the grant. Each stock option granted permits the holder to purchase one
common share of the Company at the stated exercise price.
The following table summarizes information relating to stock options outstanding
and exercisable under the Option Plan at December 31, 2002 and 2001:
2002 2001
--------------------------------------------------------------------------------------------------------------
WEIGHTED WEIGHTED
AVERAGE AVERAGE
STOCK OPTIONS EXERCISE STOCK OPTIONS EXERCISE
(thousands) PRICE (thousands) PRICE
--------------------------------------------------------------------------------------------------------------
Outstanding - beginning of year 12,051 $ 34.77 10,664 $ 32.78
--------------------------------------------------------------------------------------------------------------
Granted 3,845 $ 41.88 3,500 $ 40.85
Exercised (2,523) $ 32.54 (1,005) $ 29.12
Forfeited (491) $ 40.03 (1,108) $ 39.89
--------------------------------------------------------------------------------------------------------------
Outstanding - end of year 12,882 $ 37.13 12,051 $ 34.77
Exercisable - end of year 3,508 $ 32.53 3,615 $ 31.42
==============================================================================================================
The range of exercise prices of stock options outstanding and exercisable under
the Option Plan at December 31, 2002 is as follows:
STOCK OPTIONS OUTSTANDING STOCK OPTIONS EXERCISABLE
--------------------------------------------------------------------------------------------------------------------
STOCK WEIGHTED WEIGHTED STOCK WEIGHED
OPTIONS AVERAGE AVERAGE OPTIONS AVERAGE
OUTSTANDING REMAINING TERM EXERCISE EXERCISABLE EXERCISE
RANGE OF EXERCISE PRICES (thousands) (years) PRICE (thousands) PRICE
--------------------------------------------------------------------------------------------------------------------
$19.90 to $24.99 1,106 1.8 $ 22.02 750 $ 22.01
$25.00 to $29.99 1,069 1.2 $ 27.13 691 $ 27.19
$30.00 to $34.99 2,555 2.8 $ 33.63 927 $ 33.61
$35.00 to $39.99 4,556 4.4 $ 39.03 578 $ 39.20
$40.00 to $44.99 1,868 4.3 $ 43.19 446 $ 43.97
$45.00 to $48.50 1,728 5.2 $ 46.61 116 $ 46.59
--------------------------------------------------------------------------------------------------------------------
12,882 3.7 $ 37.13 3,508 $ 32.53
====================================================================================================================
STOCK-BASED COMPENSATION COSTS
The Company accounts for its stock-based compensation using the intrinsic value
method and as a result, no compensation costs have been recorded in the
consolidated financial statements for stock options granted or exercised. Had
the Company adopted the fair value based method of accounting,
62 Canadian Natural
================================================================================
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
the compensation costs, along with the pro forma net earnings attributable to
common shareholders and pro forma net earnings attributable to common
shareholders per common share of the Company would be as follows:
2002 2001 2000
--------------------------------------------------------------------------------------------------------------------
Stock-based compensation costs $ 24.9 $ 18.8 $ 8.5
Net earnings attributable to common shareholders
As reported $ 569.8 $ 642.6 $ 767.1
Pro forma $ 544.9 $ 623.8 $ 758.6
Net earnings attributable to common shareholders per common share
Basic
As reported $ 4.46 $ 5.30 $ 6.57
Pro forma $ 4.26 $ 5.14 $ 6.50
Diluted
As reported $ 4.31 $ 5.17 $ 6.39
Pro forma $ 4.12 $ 5.03 $ 6.32
====================================================================================================================
The stock-based compensation costs are recognized over the vesting period of the
stock options granted. The pro forma amounts shown above do not include the
stock-based compensation costs associated with stock options granted prior to
January 1, 2000.
The fair value of each stock option granted is estimated on the date of grant
using the Black-Scholes option pricing model based on the following:
2002 2001 2000
-------------------------------------------------------------------------------------------------------------------------------
Fair value of stock options granted (per common share)
Directors, officers and executives $ 14.70 $ 16.52 $ 16.35
Other employees $ 12.29 $ 13.56 $ 14.00
Risk-free interest rate 3.7% 5.2% 6.2%
Expected life (years)
Directors, officers and executives 5.5 5.5 5.5
Other employees 3.7 3.6 3.6
Expected volatility 35% 39% 38%
Expected dividend yield 1.2% 1.0% -
====================================================================================================================
10. FOREIGN CURRENCY TRANSLATION ADJUSTMENT
The foreign currency translation adjustment represents the unrealized gain
(loss) on the Company's net investment in self-sustaining foreign operations.
Effective July 1, 2002, the Company designated certain US dollar denominated
debt as a hedge against its net investment in US dollar-based self-sustaining
foreign operations. Accordingly, gains and losses on this debt are included in
the foreign currency translation adjustment.
2002 2001
----------------------------------------------------------------------------------------
Balance - beginning of year $ 72.8 $ -
Unrealized (loss) gain on translation of net investment (11.6) 72.8
Hedge of net investment with US dollar denominated debt (37.6) -
Balance - end of year $ 23.6 $ 72.8
========================================================================================
2002 Anual Report 63
================================================================================
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
NET EARNINGS AND CASH FLOW FROM OPERATIONS PER COMMON SHARE
The following table provides a reconciliation between basic and diluted amounts
per common share:
(thousands) 2002 2001 2000
----------------------------------------------------------------------------------------------------------------------------
Weighted average common shares outstanding - basic 127,883 121,300 116,701
Effect of dilutive stock options and warrants 2,744 2,594 2,624
Assumed settlement of preferred securities with common shares 2,681 2,883 1,427
----------------------------------------------------------------------------------------------------------------------------
Weighted average common shares outstanding - diluted 133,308 126,777 120,752
============================================================================================================================
Net earnings attributable to common shareholders $ 569.8 $ 642.6 $ 767.1
Dividend on preferred securities, net of tax 6.0 5.9 2.8
Revaluation of preferred securities (1.0) 7.5 1.6
----------------------------------------------------------------------------------------------------------------------------
Diluted net earnings attributable to common shareholders $ 574.8 $ 656.0 $ 771.5
============================================================================================================================
Net earnings attributable to common shareholders per common share
Basic $ 4.46 $ 5.30 $ 6.57
Diluted $ 4.31 $ 5.17 $ 6.39
============================================================================================================================
Cash flow from operations attributable to common shareholders $ 2,254.0 $ 1,920.0 $ 1,883.6
Dividend on preferred securities 10.4 10.3 5.0
----------------------------------------------------------------------------------------------------------------------------
Diluted cash flow from operations attributable to common shareholders $ 2,264.4 $ 1,930.3 $ 1,888.6
============================================================================================================================
Cash flow from operations attributable to common shareholders per common share
Basic $ 17.63 $ 15.83 $ 16.14
Diluted $ 16.99 $ 15.23 $ 15.64
============================================================================================================================
For the year ended December 31, 2002, 319,916 stock options with a weighted
average exercise price of $48.33 (2001 - 692,790 stock options with a weighted
average exercise price of $45.78, 2000 - 1,861,475 stock options with a weighted
average exercise price of $44.38) were excluded from the calculation of per
common share amounts as their effect on per common share amounts was
anti-dilutive.
12. FINANCIAL INSTRUMENTS
FINANCIAL CONTRACTS
The Company's financial instruments recognized in the consolidated balance
sheets consist of cash, accounts receivable, accounts payable, accrued
liabilities and long-term debt.
The estimated fair values of financial instruments have been determined based on
the Company's assessment of available market information and appropriate
valuation methodologies; however, these estimates may not necessarily be
indicative of the amounts that could be realized or settled in a current market
transaction.
The carrying value of cash, accounts receivable, accounts payable, accrued
liabilities and long-term debt with variable interest rates approximate their
fair value.
The estimated fair values of other financial instruments are as follows:
2002 2001
--------------------------------------------------------------------------------------------------------------
CARRYING VALUE FAIR VALUE CARRYING VALUE FAIR VALUE
ASSET (LIABILITY)
Derivative financial instruments $ - $ 56.4 $ - $ (32.9)
Fixed rate notes $ (3,259.6) $ (3,573.2) $ (1,328.6) $ (1,336.9)
==============================================================================================================
The Company uses certain derivative financial instruments to manage its
commodity prices, foreign currency and interest rate exposures. These financial
instruments are entered into solely for hedging purposes and are not used for
trading or other speculative purposes.
64 Canadian Natural
================================================================================
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
The following summarizes transactions outstanding as at February 26, 2003, which
includes all transactions outstanding at December 31, 2002:
REMAINING TERM VOLUME AVERAGE PRICE INDEX
------------------------------------------------------------------------------------------------------------------------------
OIL
Brent differential swaps Jan. 2003 - Dec. 2003 15,000 bbls/d US $1.00 Dated Brent/ WTI
Oil price collars Jan. 2003 - Mar. 2003 117,333 bbls/d US $22.74 - US $28.26 WTI
Apr. 2003 - Jun. 2003 110,667 bbls/d US $22.48 - US $28.06 WTI
Jul. 2003 - Sep. 2003 73,333 bbls/d US $23.45 - US $28.75 WTI
Oct. 2003 - Dec. 2003 40,000 bbls/d US $24.00 - US $30.17 WTI
NATURAL GAS
NYMEX collar Jan. 2003 - Oct. 2003 30,000 mmbtu/d US $ 2.88 - US $ 6.12 NYMEX
Sumas fixed Jan. 2003 - Oct. 2003 10,000 mmbtu/d Cdn $2.85 Sumas
AECO collars Jan. 2003 - Mar. 2003 500,000 GJ/d Cdn $4.16 - Cdn $6.98 AECO
Apr. 2003 - Jun. 2003 240,000 GJ/d Cdn $4.13 - Cdn $6.11 AECO
Jul. 2003 - Sep. 2003 40,000 GJ/d Cdn $3.50 - Cdn $5.38 AECO
Oct. 2003 40,000 GJ/d Cdn $3.50 - Cdn $5.38 AECO
==============================================================================================================================
AMOUNT AVERAGE EXCHANGE RATE
REMAINING TERM ($ millions) (US $/Cdn $)
------------------------------------------------------------------------------------------------------------------------------
FOREIGN CURRENCY
Currency collars Jan. 2003 - May 2003 US $ 4.2/month 1.43 - 1.53
Jan. 2003 - Aug. 2004 US $25.0/month 1.51 - 1.59
==============================================================================================================================
EXCHANGE INTEREST INTEREST
AMOUNT RATE RATE RATE
REMAINING TERM ($ millions) (US $/Cdn $) (US $) (Cdn $)
------------------------------------------------------------------------------------------------------------------------------
Currency swap Jan. 2003 - Dec. 2005 US $125.0 1.55 7.69% 7.30%
==============================================================================================================================
AMOUNT
REMAINING TERM ($ millions) FIXED RATE FLOATING RATE
------------------------------------------------------------------------------------------------------------------------------
INTEREST RATE
------------------------------------------------------------------------------------------------------------------------------
Swaps - fixed into floating Jan. 2003 - Jul. 2004 US $200.0 6.70% LIBOR + 2.09%
Jan. 2003 - Jul. 2006 US $200.0 6.70% LIBOR + 1.58%
Jan. 2003 - Jan. 2005 US $200.0 7.20% LIBOR + 3.00%
Jan. 2003 - Jan. 2007 US $200.0 7.20% LIBOR + 2.23%
Jan. 2003 - Oct. 2012 US $200.0 5.45% LIBOR + 0.81%
Swaps - floating into fixed Jan. 2003 - Mar. 2004 Cdn $100.0 5.08% CDOR
Jan. 2003 - Mar. 2007 Cdn $16.5 7.36% CDOR
==============================================================================================================================
CREDIT RISK
Accounts receivable are mainly with customers in the oil and natural gas
industry and are subject to normal industry credit risks. The Company minimizes
this risk by entering into sales contracts with only highly rated entities. In
addition, 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. The Company
is also exposed to certain losses in the event of non-performance by
counterparties to derivative financial instruments; however, the Company
minimizes this credit risk by entering into agreements with only highly rated
financial institutions.
13. COMMITMENTS
The Company has committed to certain payments over the next five years as
follows:
2003 2004 2005 2006 2007
----------------------------------------------------------------------------------------------------------------------
Natural gas transportation charges $ 192.0 $ 177.3 $ 159.6 $ 138.9 $ 111.7
Oil transportation and pipeline charges $ 12.9 $ 14.6 $ 13.3 $ 13.2 $ 14.8
Offshore equipment operating lease charges $ 71.6 $ 52.2 $ 48.9 $ 29.2 $ 29.2
Electricity charges $ 33.2 $ 26.2 $ 25.3 $ 5.4 $ 5.2
Office lease charges $ 17.1 $ 13.2 $ 12.2 $ 10.1 $ 10.1
======================================================================================================================
14. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
2002 2001 2000
--------------------------------------------------------------------------------
Interest paid $ 132.2 $ 127.4 $ 169.3
Taxes paid $ 160.4 $ 161.2 $ 62.3
================================================================================
2002 Annual Report 65
================================================================================
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
15. SEGMENTED INFORMATION
The Company's oil and natural gas activities are conducted in three geographic
segments: North America, the North Sea and Offshore West Africa. These
activities relate to the exploration, development, production and marketing of
oil, natural gas liquids and natural gas.
The Company's Horizon Project has been classified as a separate segment at
December 31, 2002. As the bitumen will be recovered through mining operations,
this project constitutes a distinct segment from oil and natural gas activities.
There are currently no revenues for this project and all directly related
expenditures have been capitalized.
As a result of the Company's increasing midstream activities, the Company
determined that effective January 1, 2002, the midstream activities within North
America constitute a distinct operating segment. Midstream activities include
the Company's pipeline operations and an electricity co-generation system.
Oil and Natural Gas
-------------------------------------------------------------------------------------------------------------------
North America North Sea
-------------------------------------------------------------------------------------------------------------------
2002 2001 2000 2002 2001 2000
-------------------------------------------------------------------------------------------------------------------
REVENUE
Revenue $ 3,337.3 $ 2,996.8 $ 2,905.1 $ 592.4 $ 523.0 $ 282.8
-------------------------------------------------------------------------------------------------------------------
Less: royalties (564.2) (551.3) (491.1) (32.7) (27.8) (15.1)
2,773.1 2,445.5 2,414.0 559.7 495.2 267.7
-------------------------------------------------------------------------------------------------------------------
Expenses
Production 656.4 596.4 492.0 228.8 123.3 54.9
Depletion, depreciation
and amortization 1,032.8 747.1 585.9 193.3 129.0 54.4
Administration 61.0 37.1 26.4 0.3 0.5 0.8
Interest 156.1 129.7 155.5 3.4 8.3
Foreign exchange (gain) loss (52.7) 59.7 14.3 21.0 1.6 3.2
Loss on sale of United States assets - 24.1 - - - -
-------------------------------------------------------------------------------------------------------------------
1,853.6 1,594.1 1,274.1 446.8 262.7 120.1
-------------------------------------------------------------------------------------------------------------------
Earnings before taxes 919.5 851.4 1,139.9 112.9 232.5 147.6
Taxes other than income tax 11.1 8.5 12.3 51.1 59.1 33.3
Current income tax 21.2 15.1 14.7 (19.6) 61.8 33.7
Future income tax 322.5 290.4 466.5 82.5 (9.0) (15.0)
-------------------------------------------------------------------------------------------------------------------
Net earnings 564.7 537.4 646.4 (1.1) 120.6 95.6
Dividend on preferred securities,
net of tax (6.0) (5.9) (2.8) - - -
Revaluation of preferred securities 1.0 (7.5) (1.6) - - -
-------------------------------------------------------------------------------------------------------------------
Net earnings attributable to
common shareholders $ 559.7 $ 524.0 $ 642.0 $ (1.1) $ 120.6 $ 95.6
===================================================================================================================
Midstream
-------------------------------------------------------------------------------------------------------------------
Offshore West Africa
-------------------------------------------------------------------------------------------------------------------
2002 2001 2000 2002 2001 2000
-------------------------------------------------------------------------------------------------------------------
REVENUE
Revenue $ 101.5 $ 41.6 $ 34.6 $ 52.0 $ 27.4 $ 38.1
-------------------------------------------------------------------------------------------------------------------
Less: royalties (3.4) (1.2) - - - -
98.1 40.4 34.6 52.0 27.4 38.1
-------------------------------------------------------------------------------------------------------------------
Expenses
Production 34.6 27.0 15.4 14.1 11.2 8.7
Depletion, depreciation
and amortization 80.5 23.9 2.5 7.6 3.8 1.8
Administration - - - - - -
Interest 6.8 (0.6) (0.2) - - -
Foreign exchange (gain) loss - 1.5 (1.6) - - -
Loss on sale of United States assets - - - - - -
-------------------------------------------------------------------------------------------------------------------
114.5 52.2 16.3 21.7 15.0 10.5
-------------------------------------------------------------------------------------------------------------------
Earnings before taxes (16.4) (11.8) 18.3 30.3 12.4 27.6
Taxes other than income tax 0.7 1.5 3.9 - - -
Current income tax 6.0 - - - - -
Future income tax (16.8) (4.2) 0.4 12.8 5.3 12.1
-------------------------------------------------------------------------------------------------------------------
Net earnings (6.3) (9.1) 14.0 17.5 7.1 15.5
Dividend on preferred securities,
net of tax - - - - - -
Revaluation of preferred securities - - - - - -
-------------------------------------------------------------------------------------------------------------------
Net earnings attributable to
common shareholders $ (6.3) $ (9.1) $ 14.0 $ 17.5 $ 7.1 $ 15.5
===================================================================================================================
2002 2001 2000
-------------------------------------------------------------------------------
REVENUE
Revenue $ 4,083.2 $ 3,588.8 $ 3,260.6
-------------------------------------------------------------------------------
Less: royalties (600.3) (580.3) (506.2)
3,482.9 3,008.5 2,754 4
-------------------------------------------------------------------------------
Expenses
Production 933.9 757.9 571.0
Depletion, depreciation
and amortization 1,314.2 903.8 644.6
Administration 61.3 37.6 27.2
Interest 158.9 137.8 162.3
Foreign exchange (gain) loss (31.7) 62.8 15.9
Loss on sale of United States assets - 24.1 -
-------------------------------------------------------------------------------
2,436.6 1,924.0 1,421.0
-------------------------------------------------------------------------------
Earnings before taxes 1,046.3 1,084.5 1,333.4
Taxes other than income tax 62.9 69.1 49.5
Current income tax 7.6 76.9 48.4
Future income tax 401.0 282.5 464.0
-------------------------------------------------------------------------------
Net earnings 574.8 656.0 771.5
Dividend on preferred securities,
net of tax (6.0) (5.9) (2.8)
Revaluation of preferred securities 1.0 (7.5) (1.6)
-------------------------------------------------------------------------------
Net earnings attributable to
common shareholders $ 569.8 $ 642.6 . $ 767.1
===============================================================================
CAPITAL EXPENDITURES
2002
Cash Non-cash Capital Fair Value Capitalized
Consideration Consideration Expenditures Adjustments(1) Costs
Oil and natural gas
North America - business combination 843.2 1,550.0 2,393.2 1,018.6 3,411.8
North America - oil and natural gas 1,026.3 - 1,026.3 - 1,026.3
North Sea 323.3 - 323.3 233.0 556.3
Offshore West Africa 185.3 - 185.3 - 185.3
--------------------------------------------------------------------------------------------------------------------------
2,378.1 1,550.0 3,928.1 1,251.6 5,179.7
Horizon Project 68.1 - 68.1 - 68.1
Midstream 20.4 - 20.4 - 20.4
Abandonments (2) 42.9 - 42.9 - 42.9
Other 9.9 - 9.9 - 9.9
2,519.4 1,550.0 4,069.4 1,251.6 5,321.0
==========================================================================================================================
(1) Future income tax adjustments on non-tax base assets and other fair value
adjustments.
(2) Abandonment expenditures were incurred in the following segments: $31.8
million North America, $8.6 million North Sea and $2.5 million Offshore
West Africa (2001 - $9.4 million North America, $nil North Sea, $nil
Offshore West Africa).
2001
Cash Non-cash Capital Fair Value Capitalized
Consideration Consideration Expenditures Adjustments(1) Costs
Oil and natural gas
North America - business combination - - - - -
North America - oil and natural gas 1,443.2 - 1,443.2 185.4 1,628.6
North Sea 97.5 - 97.5 - 97.5
Offshore West Africa 203.9 - 203.9 - 203.9
--------------------------------------------------------------------------------------------------------------------------
1,744.6 - 1,744.6 185.4 1,930.0
Horizon Project 26.8 - 26.8 - 26.8
Midstream 97.3 - 97.3 5.0 102.3
Abandonments (2) 9.4 - 9.4 - 9.4
Other 6.4 - 6.4 - 6.4
1,884.5 - 1,884.5 190.4 2,074.9
==========================================================================================================================
2002 Annual Report 67
================================================================================
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
SEGMENTED PROPERTY, PLANT AND EQUIPMENT (NET)
2002 2001
--------------------------------------------------------------------------------
Oil and natural gas
North America $ 10,252.0 $ 6,807.6
North Sea 1,277.0 865.6
Offshore West Africa 518.3 409.9
Horizon Project 228.7 160.6
Midstream 195.6 182.8
Other 28.0 16.4
--------------------------------------------------------------------------------
$ 12,499.6 $ 8,442.9
================================================================================
SEGMENTED ASSETS
2002 2001
--------------------------------------------------------------------------------
Oil and natural gas
North America $ 10,916.8 $ 7,216.1
North Sea 1,426.6 941.0
Offshore West Africa 549.4 433.2
Horizon Project 228.7 160.6
Midstream 209.4 199.6
Other 28.0 16.4
--------------------------------------------------------------------------------
$ 13,358.9 $ 8,966.9
================================================================================
16. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED
ACCOUNTING PRINCIPLES
The Company's consolidated financial statements have been prepared in accordance
with generally accepted accounting principles in Canada ("Canadian GAAP"). These
principles conform in all material respects with those in the United States ("US
GAAP") except for those noted below. 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 2002 2001 2000
---------------------------------------------------------------------------------------------------
Net earnings - Canadian GAAP $ 574.8 $ 656.0 $ 771.5
Adjustments, net of tax
Depletion (A) 5.2 5.1 5.1
Derivative financial instruments (B) 29.3 60.9 (6.4)
Dividend on preferred securities (C) (6.0) (5.9) (2.8)
Revaluation of preferred securities (C) 1.0 (7.5) (1.6)
Tax effect of flow-through shares (D) (1.0) - -
---------------------------------------------------------------------------------------------------
Net earnings - US GAAP 603.3 708.6 765.8
===================================================================================================
Net earnings - US GAAP per common share
Basic $ 4.72 $ 5.84 $ 6.56
Diluted $ 4.56 $ 5.70 $ 6.38
Comprehensive income under US GAAP would be as follows:
(millions of Canadian dollars)
NOTES 2002 2001 2000
---------------------------------------------------------------------------------------------------
Net earnings - US GAAP $ 603.3 $ 708.6 $ 765.8
Adoption of FAS 133 (B) - (124.5) -
Amortization of FAS 133 adjustment (B) 31.1 54.1 -
Foreign currency translation adjustment (E) (49.2) 72.8 -
---------------------------------------------------------------------------------------------------
Comprehensive income $ 585.2 $ 711.0 $ 765.8
===================================================================================================
68 Canadian Natural
The application of US GAAP would have the following effects on the consolidated
balance sheets as reported:
---------------------------------------------------------------------------------------------------
2002
---------------------------------------------------------------------------------------------------
CANADIAN INCREASE US
(millions of Canadian dollars) NOTES GAAP (DECREASE) GAAP
---------------------------------------------------------------------------------------------------
Property, plant and equipment (A) $12,499.6 $ (67.5) $12,432.1
Derivative financial instruments (asset) (B) $ - $ (56.4) $ (56.4)
Long-term debt (C) $ 4,074.0 $ 126.4 $ 4,200.4
Future income tax (A,B) $ 3,187.4 $ 4.3 $ 3,191.7
Shareholders' equity $ 4,868.1 $ (141.8) $ 4,726.3
===================================================================================================
---------------------------------------------------------------------------------------------------
2001
---------------------------------------------------------------------------------------------------
CANADIAN INCREASE US
(millions of Canadian dollars) NOTES GAAP (DECREASE) GAAP
---------------------------------------------------------------------------------------------------
Property, plant and equipment (A) $ 8,442.9 $ (76.5) $ 8,366.4
Derivative financial instruments liability (B) - $ 32.2 $ 32.2
Long-term debt (C) $ 2,669.2 $ 127.4 $ 2,796.6
Future income tax (A,B) $ 1,767.3 $ (27.7) $ 1,739.6
Shareholders' equity $ 3,807.0 $ (208.4) $ 3,598.6
===================================================================================================
NOTES:
(A) Using Canadian full cost accounting rules, costs capitalized in each cost
centre, net of future income taxes and future site restoration costs, are
limited to an amount equal to the undiscounted, unescalated future net
revenues from proved reserves plus the lower of cost or estimated fair
market value of unproved properties (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 discounted at 10% and estimated future
financing and administrative expenses are not deducted from net revenues.
(B) The Company uses certain derivative financial instruments to manage its
commodity prices and foreign currency exposure in relation to future firmly
committed and anticipated sales transactions. The Company has also used
interest rate swaps to manage its interest rate exposure. Under Canadian
GAAP, these derivative financial instruments are accounted for as hedges.
Effective January 1, 2001, the Company adopted Statement of Financial
Accounting Standards ("FAS") 133 "Accounting for Derivative Instruments and
Hedging Activities" and FAS 138 "Accounting for Certain Derivative
Instruments and Certain Hedging Activities" to account for its commodity
prices and interest rate swap derivative financial instruments under US
GAAP. Under FAS 133, all derivative financial instruments are recognized in
the consolidated balance sheets at their fair value. Changes in the fair
value of derivative financial instruments are recognized in consolidated
net earnings unless specific criteria for hedging are met. In 2002 and
2001, no derivative financial instruments were designated as hedges for US
GAAP purposes.
In 2001, the adoption of FAS 133 resulted in the Company recognizing a
derivative financial instruments liability of $183.4 million and a charge
to comprehensive income of $124.5 million, net of future income tax
recoveries of $58.9 million. Of the initial liability recognized on January
1, 2001, a loss of $54.1 million, net of future income tax recoveries of
$25.6 million, was reclassified to net earnings during 2001. For 2002, a
loss of $31.1 million, net of future income tax recoveries of $14.5
million, was reclassified to net earnings.
Under US GAAP, foreign currency swap contracts used to hedge foreign
currency exposure to anticipated, but not firmly committed, transactions
cannot be accounted for as hedges under FAS 52, "Foreign Currency
Translation". Accordingly, for US GAAP reporting, gains and losses from
changes in the fair market value of foreign currency swap contracts related
to these anticipated transactions are recognized in net earnings when those
changes in market value occur.
(C) Under Canadian GAAP, the preferred securities are considered to be equity
because the Company has the unrestricted right to pay dividends, principal
and principal prepayments with common shares. Under US GAAP, the Company's
preferred securities would be classified as long-term debt rather than as
equity. Accordingly, the dividend on the preferred securities would be
classified as interest expense rather than as a dividend and the
revaluation of preferred securities would be included in foreign exchange
(gain) loss in determining consolidated net earnings.
(D) Under Canadian GAAP, the future income tax effect of flow-through shares is
deducted from share capital. However, under US GAAP, the future income tax
effect of flow-through shares is expensed immediately.
(E) Under US GAAP, exchange gains and losses arising from the translation of
self-sustaining foreign operations are included in comprehensive income.
(F) The Company has included transportation costs of $293.1 million, $84.2
million and $67.8 million as a reduction of oil and natural gas revenues
for the years ended December 31, 2002, 2001 and 2000, respectively.
2002 Annual Report 69
================================================================================
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
(G) Recently Issued Accounting Standards
ACCOUNTING FOR THE IMPAIRMENT OF LONG-LIVED ASSETS
In January 2003, the Canadian Institute of Chartered Accountants ("CICA")
issued Section 3063 "Impairment of Long-lived Assets"indicates that
impairment losses occur when the carrying value of the asset exceeds the
sum of the undiscounted cash flows expected use and is measured as the
amount by which the carrying amount exceeds its fair value. The effective
date of the Section will be forbeginning on or after April 1, 2003.
Application of the Section is prospective with earlier adoption encouraged.
This Section will Company's midstream operating segment only.
ACCOUNTING FOR THE DISPOSAL OF LONG-LIVED ASSETS AND DISCONTINUED
OPERATIONS
In January 2003, the CICA issued Section 3475 "Disposal of Long-lived
Assets and Discontinued Operations". This Section outlines criteria for
when a long-lived asset may be classified as held for sale and indicates
that the value of such asset be measured at fair value less cost to sell.
The Section also indicates that losses recognized do not include any
expected future operating losses. Discontinued operations will be defined
more broadly than previously. The effective date of the Section will apply
to disposal activities initiated on or after May 1, 2003.
HEDGING
In December 2001, the CICA issued Accounting Guideline 13, "Hedging
Relationships". This Guideline addresses the types of items that qualify
for hedge accounting, the formal documentation required to enable the use
of hedge accounting and the requiremen t to evaluate hedges for
effectiveness. The Guideline does not specify how hedge accounting should
be applied. The CICA has deferred the effective date of this Guideline by
one year to fiscal years beginning on or after July 1, 2003. The Company is
currently evaluating the impact of this Guideline on its consolidated
financial statements.
ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS
In June 2001, the Financial Accounting Standards Board ("FASB") issued FAS
143 "Accounting for Asset Retirement Obligations". FAS 143 requires the
recognition of the fair value of the retirement obligation for related
long-lived tangible assets as a liability. Retirement costs equal to the
retirement liability are capitalized as part of the cost of the related
capital asset and amortized to expense over the life of the asset. This
Standard is effective for fiscal years beginning on or after June 25, 2002.
Adoption of this Standard may result in an adjustment to the future site
restoration liability and to property, plant and equipment on the Company's
consolidated balance sheets. The Canadian Accounting Standards Board (AcSB)
has proposed a similar standard, which will be applicable for fiscal years
beginning on or after January 1, 2004.
ACCOUNTING FOR COSTS ASSOCIATED WITH EXIT OR DISPOSAL ACTIVITIES
In July 2002, the FASB issued FAS 146, "Accounting for Costs Associated
with Exit or Disposal Activities" to replace Emerging Issues Task Force
Issue No. 94-3, "Liability Recognition for Certain Employee Termination
Benefits and Other Costs to Exit an A ctivity (Including Certain Costs
Incurred in a Restructuring)". FAS 146 requires companies to recognize
costs associated with exit or disposal activities when they are incurred
rather than at the date of commitment to an exit or disposal plan. The Stan
dard is effective for exit or disposal activities initiated after December
31, 2002.
ACCOUNTING GUIDANCE TO IMPROVE DISCLOSURE REQUIREMENTS FOR GUARANTEES
In November 2002, the FASB published Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others". The Interpretation expands on FAS 5,
"Accounting for Contingencies", FAS 57, "Related Party Disclosures" and FAS
107, "Disclosures about Fair Value of Financial Instruments". It also
incorporates, without change, Interpretation No. 34, "Disclosure of
Indirect Guarantees". The Interpretation elaborates on the existing
disclosure requirements for most guarantees. It also clarifies that at the
time a company issues a guarantee, the company must recognize an initial
liability for the fair value, or market value, of the obligations it
assumes under that guarantee and must disclose that information in its
interim and annual financial statements. The Interpretation is to be
applied on a prospective basis to guarantees issued or modified after
December 31, 2002, except for the disclosure requirements that are
effective for interim or annual financial statements with periods ending
after December 15, 2002. The Company is currently evaluating the impact of
this Interpretation on its consolidated financial statements.
70 Canadian Natural