EXHIBIT 2
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MANAGEMENT'S DISCUSSION AND ANALYSIS
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Canadian Natural Resources Limited 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.
[PICTURES OMITTED]
[OIL RIGS AND EQUIPMENT]
38 CANADIAN NATURAL
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MANAGEMENT'S DISCUSSION AND ANALYSIS
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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements in this document or documents incorporated herein by
reference 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: 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 crude
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.
SPECIAL NOTE REGARDING NON-GAAP FINANCIAL MEASURES
Management's discussion and analysis includes references to financial measures
commonly used in the oil and gas industry, such as cash flow, cash flow per
share and EBITDA. These financial measures are not defined by generally accepted
accounting principles ("GAAP") and therefore are referred to as non-GAAP
measures. The non-GAAP measures used by the Company may not be comparable to
similar measures presented by other companies. The Company uses these non-GAAP
measures to evaluate the performance of the Company and its business segments.
The non-GAAP measures should not be considered an alternative to or more
meaningful than net earnings, as determined in accordance with Canadian GAAP, as
an indication of the Company's performance.
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, 2003. The consolidated financial statements have been prepared in
accordance with Canadian GAAP. A reconciliation of Canadian GAAP to United
States GAAP is included in note 16 to the consolidated financial statements. All
dollar amounts are referenced in Canadian dollars, except where 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. Production volumes are the Company's interest before
royalties, and realized prices include the effect of derivative financial
instruments gains and losses, except where noted otherwise. This conversion may
be misleading, particularly when used in isolation, since the 6 mcf:1 bbl ratio
is based on an energy equivalency at the burner tip and does not represent the
value equivalency at the well head.
The following discussion details the Company's 2003 financial results compared
to 2002 and 2001, including its capital program, and its outlook for 2004.
39 ANNUAL REPORT 2003
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MANAGEMENT'S DISCUSSION AND ANALYSIS
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OBJECTIVE AND STRATEGY
The Company's objective is to increase cash flow, net earnings, crude oil and
natural gas production, reserves and net asset value on a per common share basis
through the development of its existing crude 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 takes a measured approach to growth and investments
and focuses on creating long-term shareholder wealth. 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.
(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.
Strategic acquisitions, such as Rio Alto Exploration Ltd. ("Rio Alto") in 2002,
are a key component of the Company's strategy.
The Company`s crude oil marketing strategy includes displacing medium sour crude
oil from PADD II, supporting and participating in pipeline additions, and
encouraging the development of projects that add conversion capacity.
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 area knowledge, by core area
domination and by operating at a high working interest.
The year ended December 31, 2003, was another successful year in the execution
of the Company's strategy. Highlights are as follows:
o Achieved record levels of cash flow and net earnings;
o Reduced long-term debt by $1,269 million through repayments of $740 million
and foreign exchange gains of $529 million from the strengthening Canadian
dollar;
o Achieved the Company's annual production guidance for both natural gas and
crude oil and NGLs;
o Continued consolidation of the Company's North Sea interests. The Company
now operates 99% of its production and owns an average working interest of
approximately 80% in its North Sea properties. This provides the Company
with the level of operatorship and working interests in the North Sea
necessary to effectively control costs;
o Awarded major contracts for the Baobab Project, Offshore West Africa;
o Completed the Design Basis Memorandum ("DBM") phase of engineering for the
Horizon Oil Sands Project ("Horizon Project") and commenced the third and
final phase of pre-construction engineering, Engineering Design
Specifications ("EDS");
o Completed the Joint Panel review for regulatory approvals of the Horizon
Project; and
o Purchased 2,734,800 common shares for a total cost of $144 million under
the Company's Normal Course Issuer Bid.
ACQUISITION OF RIO ALTO
In 2002, the Company paid cash of $850 million and issued 10,008,218 common
shares to acquire all of the issued and outstanding common shares of Rio Alto by
way of a plan of arrangement. This was a strategic acquisition as it increased
the Company's natural gas production and added a new natural gas core region in
Northwest Alberta. The Rio Alto acquisition is included in the results of
operations commencing July 1, 2002.
40 CANADIAN NATURAL
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MANAGEMENT'S DISCUSSION AND ANALYSIS
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CASH FLOW AND NET EARNINGS
FINANCIAL HIGHLIGHTS ($ millions, except per common share amounts) 2003 2002 2001
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Revenue (1) $ 5,972 $ 4,342 $ 3,757
Cash flow from operations attributable to common shareholders (2) $ 3,160 $ 2,254 $ 1,920
Per common share - basic $ 23.54 $ 17.63 $ 15.83
- diluted $ 23.06 $ 16.99 $ 15.23
Net earnings attributable to common shareholders (3) $ 1,407 $ 570 $ 642
Per common share - basic $ 10.48 $ 4.46 $ 5.30
- diluted $ 10.14 $ 4.31 $ 5.17
Business combinations $ -- $ 2,393 $ --
Capital expenditures, net of dispositions $ 2,506 $ 1,676 $ 1,885
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(1) Restated to conform to current year presentation.
(2) Cash flow from operations attributable to common shareholders is a non-GAAP
term that represents net earnings attributable to common shareholders
adjusted for non-cash items. The Company evaluates its performance and that
of its business segments based on net earnings and cash flow from
operations. The Company considers cash flow a key measure as it
demonstrates the Company's ability and the ability of its business segments
to generate the cash flow necessary to fund future growth through capital
investment and to repay debt.
($ millions) 2003 2002 2001
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Net earnings attributable to common shareholders $ 1,407 $ 570 $ 642
Non-cash items:
Future tax on dividend on preferred securities (4) (4) (4)
Revaluation of preferred securities, net of tax (18) (1) 8
Stock-based compensation expense 200 -- --
Depletion, depreciation and amortization 1,565 1,314 903
Unrealized foreign exchange (gain) loss (320) (35) 64
Loss on sale of United States assets -- -- 24
Deferred petroleum revenue tax (9) 10 --
Future income tax expense 339 400 283
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Cash flow from operations attributable to common shareholders $ 3,160 $ 2,254 $ 1,920
===================================================================================================================
(3) After dividend and revaluation of preferred securities.
Cash flow from operations attributable to common shareholders reached record
levels in 2003. Cash flow from operations attributable to common shareholders
increased 40% to $3,160 million ($23.54 per common share), up from $2,254
million ($17.63 per common share) in 2002 and $1,920 million ($15.83 per common
share) in 2001. The increase in cash flow resulted primarily from higher product
prices and increased production volumes. In 2003, the Company's average price
per barrel of crude oil and NGLs increased 6% to $31.59 from $29.76 in 2002
(2001 - $24.31). The Company's average natural gas price increased 60% to $6.02
per mcf from $3.76 per mcf in 2002 (2001 - $5.16 per mcf). Production volumes
increased 9% to 458,814 boe/d from 420,722 boe/d in 2002 (2001- 359,347 boe/d).
The increase in production volumes was primarily associated with an active
capital expenditure program, the consolidation of working interests in the North
Sea, and the impact of a full year of results relating to the acquisition of Rio
Alto on July 1, 2002.
Net earnings attributable to common shareholders also reached record levels in
2003. Net earnings attributable to common shareholders increased 147% in 2003 to
$1,407 million ($10.48 per common share), up from $570 million ($4.46 per common
share) in 2002 and $642 million ($5.30 per common share) in 2001. Net earnings
attributable to common shareholders in 2003 was impacted by the reduction in the
Canadian federal and Alberta provincial corporate income tax rates, the
strengthening Canadian dollar, which resulted in increased unrealized foreign
exchange gains on the Company's US dollar denominated debt, and the recognition
of stock-based compensation expense associated with the Company's Stock Option
Plan.
[GRAPHIC OMITTED - LINE CHART] [GRAPHIC OMITTED - LINE CHART]
CASH FLOW FROM OPERATIONS NET EARNINGS ATTRIBUTABLE TO
ATTRIBUTABLE TO COMMON SHAREHOLDERS COMMON SHAREHOLDERS PER SHARE
$millions $per share
99 724 99 2.11
00 1,884 00 6.57
01 1,920 01 5.30
02 2,254 02 4.46
03 3,160 03 10.48
[GRAPHIC OMITTED - LINE CHART] [GRAPHIC OMITTED - LINE CHART]
NET EARNINGS ATTRIBUTABLE RETURN ON AVERAGE COMMON
TO COMMON SHAREHOLDERS SHAREHOLDER'S EQUITY
$millions percent
99 220 99 14.5
00 767 00 31.6
01 642 01 18.8
02 570 02 13.8
03 1,407 03 25.7
41 ANNUAL REPORT 2003
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MANAGEMENT'S DISCUSSION AND ANALYSIS
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OPERATING HIGHLIGHTS 2003 2002 2001
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CRUDE OIL AND NGLS ($/bbl, except daily production)
Daily production, before royalties (bbl/d) 242,392 215,335 206,323
Sales price (1) $ 31.59 $ 29.76 $ 24.31
Royalties 2.77 3.16 2.17
Production expense 10.28 8.45 7.64
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Netback $ 18.54 $ 18.15 $ 14.50
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NATURAL GAS ($/mcf, except daily production)
Daily production, before royalties (mmcf/d) 1,299 1,232 918
Sales price (1) $ 6.02 $ 3.76 $ 5.16
Royalties 1.32 0.78 1.25
Production expense 0.60 0.57 0.51
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Netback $ 4.10 $ 2.41 $ 3.40
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BARREL OF OIL EQUIVALENT ($/boe, except daily production)
Daily production, before royalties (boe/d) 458,814 420,722 359,347
Sales price (1) $ 33.75 $ 26.25 $ 27.15
Royalties 5.20 3.91 4.42
Production expense 7.15 5.99 5.69
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Netback $ 21.40 $ 16.35 $ 17.04
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(1) Including financial instruments and transportation costs.
BUSINESS ENVIRONMENT 2003 2002 2001
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WTI benchmark price (US$/bbl) $ 31.02 $ 26.11 $ 25.91
Differential to LLB blend (US$/bbl) $ 8.55 $ 6.50 $ 10.73
Condensate benchmark price (US$/bbl) $ 31.42 $ 26.00 $ 28.12
NYMEX benchmark price (US$/mmbtu) $ 5.44 $ 3.25 $ 4.38
AECO benchmark price (C$/GJ) $ 6.35 $ 3.86 $ 5.92
US/Canadian dollar average exchange rate (US$) 0.71 0.64 0.65
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World crude oil prices remained strong throughout 2003 due to concerns over
supply relating to the war in Iraq, the strike in Venezuela, the unrest in
Nigeria and rising worldwide demand. West Texas Intermediate ("WTI") prices
increased 19% to average US$31.02 per bbl, up from US$26.11 per bbl in 2002
(2001 - US$25.91 per bbl). In 2003, the heavy oil differential averaged US$8.55
per bbl, up from US$6.50 per bbl in 2002 (2001 - US$10.73 per bbl). Natural gas
prices increased in 2003 due to market forces of supply and demand. AECO natural
gas price increased 65% to average $6.35 per GJ in 2003 compared to $3.86 per GJ
in 2002 (2001 - $5.92 per GJ). NYMEX natural gas spot price increased 67% to
average US$5.44 per mmbtu compared to US$3.25 per mmbtu in 2002 (2001 - US$4.38
per mmbtu).
REVENUE
PRODUCT PRICES (1) 2003 2002 2001
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CRUDE OIL AND NGLS ($/bbl)
North America $ 27.77 $ 27.04 $ 21.00
North Sea $ 42.43 $ 39.79 $ 38.66
Offshore West Africa $ 36.47 $ 40.10 $ 33.57
Company average $ 31.59 $ 29.76 $ 24.31
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NATURAL GAS ($/mcf)
North America $ 6.14 $ 3.78 $ 5.19
North Sea $ 3.03 $ 2.75 $ 2.51
Offshore West Africa $ 4.37 $ 4.82 $ --
Company average $ 6.02 $ 3.76 $ 5.16
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PERCENTAGE OF REVENUE (excluding midstream revenue)
Crude oil and NGLs 49% 58% 52%
Natural gas 51% 42% 48%
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(1) Including financial instruments and transportation costs.
42 CANADIAN NATURAL
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MANAGEMENT'S DISCUSSION AND ANALYSIS
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ANALYSIS OF CHANGES IN REVENUE
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Changes due to CHANGES DUE TO
($ millions) 2001 Volumes Prices Other 2002 VOLUMES PRICES OTHER 2003
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NORTH AMERICA
Crude oil and NGLs $ 1,339 $ 23 $ 386 $ -- $ 1,748 $ 52 $ 49 $ -- $ 1,849
Natural gas 1,824 565 (527) -- 1,862 56 1,062 -- 2,980
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3,163 588 (141) -- 3,610 108 1,111 -- 4,829
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NORTH SEA
Crude oil and NGLs 523 37 24 -- 584 261 36 -- 881
Natural gas 11 14 3 -- 28 19 33 -- 80
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534 51 27 -- 612 280 69 -- 961
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OFFSHORE WEST AFRICA
Crude oil and NGLs 42 42 16 -- 100 56 (14) -- 142
Natural gas -- 2 -- -- 2 13 (1) -- 14
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42 44 16 -- 102 69 (15) -- 156
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SUBTOTAL
Crude oil and NGLs 1,904 102 426 -- 2,432 369 71 -- 2,872
Natural gas 1,835 581 (524) -- 1,892 88 1,094 -- 3,074
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3,739 683 (98) -- 4,324 457 1,165 -- 5,946
MIDSTREAM 27 -- -- 25 52 -- -- 9 61
INTERSEGMENT ELIMINATIONS (1) (9) -- -- (25) (34) -- -- (1) (35)
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TOTAL $ 3,757 $ 683 $ (98) $ -- $ 4,342 $ 457 $ 1,165 $ 8 $ 5,972
====================================================================================================================================
(1) Eliminates internal transportation and electricity charges.
Revenue rose 38% to $5,972 million in 2003, up from $4,342 million in 2002 (2001
- - $3,757 million). In 2003, 19% of the Company's crude oil and natural gas
revenue was generated outside of North America, up from 16% in 2002 (2001 -
15%). North Sea accounted for 16% of revenue in 2003 and 14% in 2002 (2001 -
14%), and Offshore West Africa accounted for 3% of revenue in 2003 and 2% in
2002 (2001 - 1%).
Crude oil and NGLs pricing realized by the Company is directly correlated with
fluctuations in world oil pricing and heavy oil differentials. The realized
crude oil and NGLs price earned by the Company in 2003 increased 6% to average
$31.59 per bbl for the year, up from $29.76 per bbl in 2002 (2001 - $24.31 per
bbl). The Company's realized crude oil price was impacted by the increase in
world oil prices, the higher heavy oil differential, and the strengthening
Canadian dollar (see Sensitivity Analysis).
Natural gas prices increased 60% to average $6.02 per mcf, up from $3.76 per mcf
in 2002 (2001 - $5.16 per mcf), due to market forces of supply and demand in
2003. Lower demand and higher storage levels in the first half of the year
impacted natural gas prices in 2002.
The Company uses certain financial instruments to protect against downside
commodity prices received on the sale of certain crude oil and natural gas
production to ensure adequate resources are available for its capital program.
The price realized from the sale of crude oil was reduced by $1.07 per bbl in
2003 compared to $1.46 per bbl in 2002 (2001 - increase of $0.86 per bbl) due to
the impact of financial instruments. In addition, the price realized from the
sale of natural gas was reduced by $0.19 per mcf in 2003 compared to a reduction
of $0.01 per mcf in 2002 (2001 - reduction of $0.29 per mcf) due to the impact
of financial instruments. The financial instruments as at December 31, 2003, are
summarized in note 10 to the consolidated financial statements.
A comparison of the price received for the Company's North America production is
as follows:
2003 2002 2001
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Wellhead Price (1)
Light crude oil and NGLs (C$/bbl) $ 35.92 $ 32.88 $ 34.73
Pelican Lake crude oil (C$/bbl) $ 26.31 $ 25.92 $ 19.46
Primary heavy crude oil (C$/bbl) $ 24.70 $ 25.40 $ 17.64
Thermal heavy crude oil (C$/bbl) $ 23.85 $ 24.12 $ 15.20
Natural gas (C$/mcf) $ 6.14 $ 3.78 $ 5.19
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(1) Including financial instruments and transportation costs.
43 Annual Report 2003
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MANAGEMENT'S DISCUSSION AND ANALYSIS
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DAILY PRODUCTION, BEFORE ROYALTIES
2003 2002 2001
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CRUDE OIL AND NGLS (bbl/d)
North America 174,895 169,675 166,675
North Sea 56,869 38,876 36,252
Offshore West Africa 10,628 6,784 3,396
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Total 242,392 215,335 206,323
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NATURAL GAS (mmcf/d)
North America 1,245 1,204 906
North Sea 46 27 12
Offshore West Africa 8 1 --
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Total 1,299 1,232 918
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PRODUCT MIX
Light crude oil and NGLs 25% 21% 21%
Pelican Lake crude oil 5% 7% 9%
Primary heavy crude oil 15% 14% 16%
Thermal heavy crude oil 8% 9% 11%
Natural gas 47% 49% 43%
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The Company's daily crude oil and NGLs production increased 13% or 27,057 bbl/d
to average 242,392 bbl/d in 2003, up from 215,335 bbl/d in 2002 (2001 - 206,323
bbl/d). Crude oil and NGLs production in 2003 increased in all segments from the
previous year and was in line with production guidance provided.
Crude oil and NGLs production in North America for the year ended December 31,
2003 increased 3% or 5,220 bbl/d to average 174,895 bbl/d, up from 169,675 bbl/d
in 2002 (2001 - 166,675 bbl/d). The increase in North America production is
attributable to heavy oil drilling and recompletion activity in 2003, property
acquisitions in its core operating regions in 2002, and the impact of a full
year production from the properties acquired in the Rio Alto acquisition. Crude
oil production from the Pelican Lake Field declined as a result of the
implementation of the water flood program, which required producing wells to be
converted to injectors.
Crude oil production from the North Sea for the year ended December 31, 2003
increased 46% or 17,993 bbl/d to average 56,869 bbl/d, up from 38,876 bbl/d in
2002 (2001 - 36,252 bbl/d). The increase was a result of drilling activities,
which focused on unswept oil reserves within the Ninian, Murchison and Columba
Fields, recompletion activities where a number of wells were re-entered to
access behind pipe reserves, and the continued consolidation of the Company's
working interests in the North Sea. Crude oil production from the North Sea in
2003 was also impacted by two unscheduled turnarounds on the Ninian South
Platform. Production from the Ninian South Platform was shut in from late March
2003 to late April 2003 in order to replace critical pipework to significantly
increase the reliability and integrity of the Platform.
Offshore West Africa crude oil production for the year ended December 31, 2003,
increased 57% or 3,844 bbl/d to average 10,628 bbl/d, up from 6,784 bbl/d in
2002 (2001 - 3,396 bbl/d). The increase in crude oil production is due to the
commencement of production from the Company's operated Espoir Field, located
offshore Cote d'Ivoire, in 2002. In addition, crude oil production increased due
to the perforation of the upper zone of the East Espoir structure in the second
quarter of 2003, and the completion of the fourth water injection well and two
additional producing wells in 2003.
The Company continues to look for opportunities to expand its heavy oil markets.
In particular, the Company is testing a 50/50 blend of bitumen and synthetic
crude oil called "Synbit". Synbit has similar properties to medium sour crude
oil and is expected to decrease the demand for supplies of condensate currently
blended with bitumen. The Company is currently marketing 34,000 bbl/d of Synbit
to refiners located in the US Midwest and plans to expand this effort throughout
2004 to build a solid new market for both heavy and synthetic crude oil.
[GRAPHIC OMITTED - LINE CHART] [GRAPHIC OMITTED - LINE CHART]
NATURAL GAS PRODUCTION CRUDE OIL AND NGLs
BEFORE ROYALTIES PRODUCTION BEFORE ROYALTIES
mmcf/d mbbl/d
99 721 99 87
00 794 00 174
01 918 01 206
02 1,232 02 215
03 1,299 03 242
44 CANADIAN NATURAL
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MANAGEMENT'S DISCUSSION AND ANALYSIS
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Natural gas continues to represent the Company's largest product offering,
accounting for 47% of the Company's total production in 2003 compared to 49% of
total production in 2002 (2001 - 43%). Natural gas production increased 5% or 67
mmcf/d to average 1,299 mmcf/d, up from 1,232 mmcf/d in 2002 (2001 - 918
mmcf/d). Annual natural gas production was in line with the production guidance
provided.
North America accounts for 96% of the Company's natural gas production in 2003,
down from 98% in 2002 (2001 - 99%). Overall, natural gas production in North
America increased 3% or 41 mmcf/d to average 1,245 mmcf/d, up from 1,204 mmcf/d
in 2002 (2001 - 906 mmcf/d). The increase in natural gas production was due to
ongoing drilling activities and the acquisition of Rio Alto on July 1, 2002.
Natural gas production in 2003 was impacted by steep production declines from
the Ladyfern Field. Ladyfern natural gas production decreased 67% or 112 mmcf/d
to average 56 mmcf/d, down from 168 mmcf/d in 2002 (2001 - 40 mmcf/d).
Production of natural gas was also impacted by the shut in of approximately 11
mmcf/d of the Company's natural gas production in the Athabasca
Wabiskaw-McMurray oilsands area pursuant to the decision of the Alberta Energy
and Utilities Board ("EUB") effective September 1, 2003.
North Sea natural gas production increased 70% or 19 mmcf/d to average 46
mmcf/d, up from 27 mmcf/d in 2002 (2001 - 12 mmcf/d). The increase was due to
the acquisition of additional interests in the Banff Field. Natural gas
production from the North Sea in 2004 is expected to decrease due to the
implementation of the natural gas re-injection program on the Banff Field to
maximize recovery from the reservoir.
Natural gas production in Offshore West Africa increased 7 mmcf/d to average 8
mmcf/d, up from 1 mmcf/d in 2002 (2001 - nil). Production increased due to the
completion of the natural gas pipeline in the Espoir Field in the third quarter
of 2002. Natural gas production also increased from the previous year due to the
perforation of the upper zone of the East Espoir structure in the second quarter
of 2003 and the drilling of additional production and injection wells in 2003.
ROYALTIES
2003 2002 2001
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CRUDE OIL AND NGLS ($/bbl)
North America $ 3.79 $ 3.42 $ 2.22
North Sea $ (0.03) $ 2.30 $ 2.10
Offshore West Africa $ 1.08 $ 1.35 $ 0.93
Company average $ 2.77 $ 3.16 $ 2.17
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NATURAL GAS ($/mcf)
North America $ 1.38 $ 0.80 $ 1.26
Offshore West Africa $ 0.13 $ 0.15 $ --
Company average $ 1.32 $ 0.78 $ 1.25
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COMPANY AVERAGE ($/boe) $ 5.20 $ 3.91 $ 4.42
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PERCENTAGE OF REVENUE (1)(2)
Crude oil and NGLs 9% 10% 9%
Natural gas 21% 21% 23%
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(1) Excludes the impact of financial instruments.
(2) Transportation costs netted against revenue.
Crude oil and NGLs royalties in North America increased to $3.79 per bbl, up
from $3.42 per bbl in 2002 (2001 - $2.22 per bbl), due to certain primary and
thermal heavy oil projects 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.
Effective January 1, 2003, government royalties in the North Sea were
eliminated. In 2003, the Company received a refund of royalties related to the
Ninian Field. As a result North Sea crude oil royalties recovered $0.03 per bbl
as opposed to an expense of $2.30 per bbl in 2002 (2001 - $2.10 per bbl).
Offshore West Africa crude oil royalties decreased to $1.08 per bbl, down from
$1.35 per bbl in 2002 (2001 - $0.93 per bbl) due to fluctuations in realized
crude oil prices.
Natural gas royalties for the Company increased to $1.32 per mcf, up from $0.78
per mcf in 2002 (2001 - $1.25 per mcf), due to the overall increase in natural
gas prices. North America natural gas royalties have a strong correlation to
changes in natural gas prices.
45 ANNUAL REPORT 2003
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MANAGEMENT'S DISCUSSION AND ANALYSIS
- --------------------------------------------------------------------------------
PRODUCTION EXPENSE
2003 2002 2001
- --------------------------------------------------------------------------------
CRUDE OIL AND NGLS ($/bbl)
North America $ 9.14 $ 6.73 $ 7.05
North Sea $ 14.07 $ 15.06 $ 9.00
Offshore West Africa $ 8.68 $ 13.63 $ 21.77
Company average $ 10.28 $ 8.45 $ 7.64
- --------------------------------------------------------------------------------
NATURAL GAS ($/mcf)
North America $ 0.57 $ 0.55 $ 0.50
North Sea $ 1.33 $ 1.53 $ 0.94
Offshore West Africa $ 1.39 $ 1.81 $ --
Company average $ 0.60 $ 0.57 $ 0.51
- --------------------------------------------------------------------------------
COMPANY AVERAGE ($/boe) $ 7.15 $ 5.99 $ 5.69
- --------------------------------------------------------------------------------
Production expense increased to $7.15 per boe, up from $5.99 per boe in 2002
(2001 - $5.69 per boe). The increase was primarily related to higher costs
associated with operations in North America. North America crude oil and NGLs
production expense increased to $9.14 per bbl from $6.73 per bbl in 2002 (2001 -
$7.05 per bbl). The increase was mainly a result of higher repair and
maintenance costs incurred with regard to property acquisitions as well as costs
associated with the conversion and implementation of the Pelican Lake water
flood pilots. The increase was also impacted by the cost of fuel gas used in the
generation of steam in the Company's thermal oil operations.
North Sea crude oil production expense decreased in 2003 to $14.07 per bbl from
$15.06 per bbl in 2002 (2001 - $9.00 per bbl), due to the timing of maintenance
work and changes in production volumes on a relatively fixed cost base.
Production expense in the North Sea was higher than normal in 2002 due to costs
associated with rectifying a natural gas pipeline blockage in the Kyle Field.
Offshore West Africa crude oil production expense decreased to $8.68 per bbl
from $13.63 per bbl in 2002 (2001 - $21.77 per bbl) resulting from production
increases in the Espoir Field. The Espoir Field commenced operations in the
first quarter of 2002. Production expenses are largely fixed in nature and
therefore decreased on a per barrel basis as production increased. The higher
production expense in 2001 was related to costs associated with the Kiame Field,
located offshore Angola, which ceased operations early in 2002.
Natural gas production expense for the year 2003 increased to $0.60 per mcf, up
from $0.57 per mcf in 2002 (2001 - $0.51 per mcf). North America natural gas
production expense increased to $0.57 per mcf, up from $0.55 per mcf in 2002
(2001 - $0.50 per mcf), as a result of a general increase in service costs
associated with increased industry activity.
MIDSTREAM
($ millions) 2003 2002 2001
- --------------------------------------------------------------------------------
Revenue $ 61 $ 52 $ 27
Operating costs 15 14 11
- --------------------------------------------------------------------------------
Operating cash flow 46 38 16
Depreciation 7 8 4
- --------------------------------------------------------------------------------
Segment earnings before taxes $ 39 $ 30 $ 12
- --------------------------------------------------------------------------------
The Company's midstream assets consist of three crude oil pipeline systems and
an 84-megawatt cogeneration plant at Primrose where the Company has a 50%
working interest. Approximately 85% of the Company's heavy oil production was
transported to international liquid pipelines via the 100% owned and operated
ECHO Pipeline, the 62% owned and operated Pelican Lake Pipeline and the 15%
owned Cold Lake Pipeline, which commenced operations in late 2001. The midstream
pipeline assets allow the Company to transport its own production volumes at
reduced costs compared to other transportation alternatives as well as earn
third party revenue. This transportation control enhances the Company's ability
to control the full range of costs associated with the development and marketing
of its heavy oil.
Revenue from the midstream assets increased 17% to $61 million, up from $52
million in 2002 (2001 - $27 million). The increase in revenue, operating
cashflow and segment earnings before taxes was due to higher electricity prices
received in the first quarter of 2003 and increased revenue generated as a
result of the expansion of the ECHO Pipeline. The expansion of the ECHO Pipeline
was completed in October 2003 and increased capacity to 72 mbbl/d from 58
mbbl/d.
46 CANADIAN NATURAL
- --------------------------------------------------------------------------------
MANAGEMENT'S DISCUSSION AND ANALYSIS
- --------------------------------------------------------------------------------
The Cold Lake Pipeline Limited Partnership, in which the Company has a 15%
working interest, will be investing $16 million in 2004 to construct new
facilities to allow shipment of up to 60,000 bbl/d of Synbit product. The new
Synbit product will include light synthetic oil as a blending component to
dilute the heavy, tar-like Cold Lake bitumen. The Synbit project will involve
construction of two 80,000 barrel storage tanks, pumping facilities and metering
equipment on the Cold Lake system. Regulatory approvals have been obtained and
construction activity is currently underway.
DEPLETION, DEPRECIATION AND AMORTIZATION (1)
($ millions, except per boe amounts) 2003 2002 2001
- --------------------------------------------------------------------------------
North America $1,248 $1,033 $746
North Sea 268 193 129
Offshore West Africa 42 80 24
Expense $1,558 $1,306 $899
- --------------------------------------------------------------------------------
$/boe $9.30 $8.51 $6.86
- --------------------------------------------------------------------------------
(1) DD&A excludes depreciation on midstream assets.
Depletion, depreciation and amortization ("DD&A") increased in total and per boe
to $1,558 million or $9.30 per boe from $1,306 million or $8.51 per boe in 2002
(2001 - $899 million or $6.86 per boe). These increases were 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. In addition, DD&A included the write-off of $12 million of
costs associated with the Company's exploration activity in offshore France in
2003. In 2002, DD&A included the write-off of $51 million as a result of the
Company's decision to exit from its interests in Block 19, Angola, and from the
Aje Field, Nigeria.
ADMINISTRATION EXPENSE
($ millions, except per boe amounts) 2003 2002 2001
- --------------------------------------------------------------------------------
Gross cost $ 262 $ 147 $ 110
$/boe $ 1.57 $ 0.96 $ 0.84
Net expense $ 87 $ 61 $ 38
$/boe $ 0.52 $ 0.40 $ 0.29
Gross administration expense increased to $1.57 per boe from $0.96 per boe in
2002 (2001 - $0.84 per boe) mainly due to higher staffing levels associated with
the Company's expanding asset base and costs associated with the Horizon
Project. Gross administration expense also increased as a result of higher costs
related to the assumption of operatorship of certain fields in the North Sea.
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 $0.52 per boe in 2003 from
$0.40 per boe in 2002 (2001 - $0.29 per boe).
STOCK-BASED COMPENSATION
($ millions, except per boe amounts) 2003 2002 2001
- --------------------------------------------------------------------------------
Stock-based compensation expense $ 200 $ -- $ --
$/boe $ 1.20 $ -- $ --
- --------------------------------------------------------------------------------
In June 2003, the Board of Directors approved an amendment to the Company's
Stock Option Plan (the "Option Plan") that provides current employees, officers
and directors (the "option holders") with the right to elect to receive common
shares or a direct cash payment in exchange for options surrendered. Amendments
to the Option Plan balance the need for a long-term compensation program to
retain employees with reducing the impact of dilution on current shareholders
and the reporting of the expense associated with stock options. Transparency of
the cost of the Option Plan is increased since changes in the intrinsic value of
outstanding stock options are expensed. The cash payment feature provides option
holders with substantially the same benefits and allows them to realize the
value of their options through a simplified administration process.
As a result of the amendment to the Option Plan, the Company has recorded a
liability at December 31, 2003, of $171 million for expected cash settlements
based on the intrinsic value of the outstanding stock options (the difference
between the exercise price of the stock options and the market price of the
Company's common shares). Compensation expense for 2003 is $200 million ($136
million net of tax). The liability is revalued quarterly to reflect changes in
the market price of the Company's common shares and the net change is recognized
in net earnings. In 2003, the Company paid $31 million in cash settlements for
stock options surrendered.
INTEREST EXPENSE
($ millions, except per boe amounts) 2003 2002 2001
- --------------------------------------------------------------------------------
Interest expense $ 157 $ 159 $ 138
$/boe $ 0.94 $ 1.03 $ 1.05
Average effective interest rate 4.7% 4.5% 5.4%
- --------------------------------------------------------------------------------
47 ANNUAL REPORT 2003
- --------------------------------------------------------------------------------
MANAGEMENT'S DISCUSSION AND ANALYSIS
- --------------------------------------------------------------------------------
Interest expense decreased to $157 million in 2003 from $159 million in 2002
(2001 - $138 million) due to lower average outstanding debt levels as the
Company used excess cash flow generated to repay $740 million of long-term debt
in 2003. The impact of the lower debt levels was partially offset by the higher
average effective interest rate of 4.7%, up from 4.5% in 2002 (2001 - 5.4%). In
addition, the strengthening Canadian dollar reduced the Canadian equivalent
interest expense on the Company's US dollar denominated debt. Interest expense
decreased to $0.94 per boe in 2003 compared to $1.03 per boe in 2002 (2001 -
$1.05 per boe) as a result of the lower average outstanding debt levels and
higher production. The Company continues to benefit from the lower short-term
interest rates as its fixed-rate debt accounts for only 38% of total debt
outstanding after interest rates swaps (see note 10 to the consolidated
financial statements) as at December 31, 2003 (2002 - 40%, 2001 - 21%).
FOREIGN EXCHANGE
($ millions) 2003 2002 2001
- --------------------------------------------------------------------------------
Realized foreign exchange loss (gain) $ 8 $ 4 $ (1)
Unrealized foreign exchange (gain) loss (320) (35) 64
- --------------------------------------------------------------------------------
Total $(312) $ (31) $ 63
- --------------------------------------------------------------------------------
The Canadian dollar increased to US$0.77 at December 31, 2003, compared to
US$0.63 at January 1, 2003, resulting in an unrealized foreign exchange gain on
the Company's US dollar denominated debt. The Canadian dollar averaged US$0.71
in 2003, up from US$0.64 in 2002 (2001 - US$0.65).
The majority of the Company's borrowings are denominated in US dollars. At
December 31, 2003, the Company's US dollar denominated debt amounted to US$1,965
million compared to US$1,968 million in 2002 (2001 - US$899 million). US dollar
denominated debt represented 91% of total debt outstanding at December 31, 2003
(2002 - 76%, 2001 - 53%). Due to the higher proportion of US dollar denominated
debt outstanding, the Company's net earnings are more sensitive to fluctuations
in the Canadian dollar.
In order to mitigate a portion of the volatility associated with the Canadian
dollar, the Company has designated certain US dollar denominated debt as a hedge
against its net investment in US dollar based self-sustaining foreign
operations. Accordingly, translation gains and losses on this US dollar
denominated debt are included in the foreign currency translation adjustment in
shareholders' equity in the consolidated balance sheets.
The Company's realized product prices are sensitive to currency exchange rates.
Recent increases in the value of the Canadian dollar in relation to the US
dollar had a negative impact on the Company's commodity price realized (see
Sensitivity Analysis).
TAXES
($ millions, except income tax rates) 2003 2002 2001
- --------------------------------------------------------------------------------
Taxes other than income tax
Current $ 116 $ 53 $ 69
Deferred (9) 10 --
- --------------------------------------------------------------------------------
Total $ 107 63 69
- --------------------------------------------------------------------------------
Current income tax
North America - Current income tax $ 43 $ -- $ --
North America - Large Corporations Tax 16 21 15
North Sea 23 (19) 62
Offshore West Africa 10 6 --
- --------------------------------------------------------------------------------
Total $ 92 $ 8 $ 77
- --------------------------------------------------------------------------------
Future income tax $ 339 $ 400 $ 283
- --------------------------------------------------------------------------------
Effective income tax rate 23.6% 41.6% 35.4%
- --------------------------------------------------------------------------------
Taxes other than income tax consist of current and deferred petroleum revenue
tax ("PRT"), other international taxes and provincial capital taxes and
surcharges. 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 increased to $107 million or $0.64 per
boe in 2003, up from $63 million or $0.41 per boe in 2002 (2001 - $69 million or
$0.53 per boe). The increase in taxes other than income tax was mainly due to
the higher netback earned in the North Sea as a result of higher crude oil
prices and higher production levels. North Sea PRT accounts for $97 million or
$0.58 per boe in 2003 compared to $51 million or $0.33 per boe in 2002 (2001 -
$59 million or $0.45 per boe).
Current income tax in the North Sea increased to $23 million or $0.14 per boe,
up from a recovery of $19 million or $0.13 per boe in 2002 (2001 - expense of
$62 million or $0.47 per boe). The increase in the current income tax expense
was a result of increased production and higher crude oil prices. The North Sea
current income tax was also impacted by changes in the tax rules in the North
Sea. In 2002, a supplementary charge of 10% on
48 CANADIAN NATURAL
- --------------------------------------------------------------------------------
MANAGEMENT'S DISCUSSION AND ANALYSIS
- --------------------------------------------------------------------------------
profits from UK North Sea crude oil and natural gas production was introduced.
The North Sea supplementary charge, which took effect April 17, 2002, is in
addition to the corporate income tax rate of 30% and excludes any deduction for
financing costs. In addition, the first year capital allowance rate for plant
and machinery expenditures was increased to 100% from the previous rate of 25%.
Taxable income from the conventional crude oil and natural gas business in
Canada is generated by partnerships and the related income taxes will be payable
in the following year. Current income taxes have been provided on the basis of
the corporate structure and available income tax deductions. No current income
tax provision was required for North America in 2002 and 2001.
The Company is liable for the payment of Federal LCT. LCT decreased to $16
million or $0.09 per boe from $21 million or $0.14 per boe (2001 - $15 million
or $0.11 per boe) as a result of the Company being taxable and paying the
Federal corporate surtax.
In 2003, the Canadian Federal Government passed legislation to eliminate the
federal Large Corporations Tax ("LCT") over a five-year period starting January
1, 2004. The LCT was levied at a rate of 0.225% of the Company's taxable capital
employed in Canada in 2003 (2004 - 0.2%). The Federal Government also passed
legislation to reduce the corporate income tax rate on income from resource
activities from 28% to 21% over a five-year period starting January 1, 2003,
bringing the resource industry in line with the general corporate income tax
rate. As part of the corporate income tax rate reduction, the legislation also
provides for the elimination of the existing 25% resource allowance and the
introduction of a deduction for actual provincial and other crown royalties
paid. As a result of these changes, the future income tax liability in North
America was decreased by $247 million in 2003. In 2003 the North America future
income tax liability was also reduced by $31 million as a result of a reduction
in the Alberta corporate income tax rate (2002 - $21 million, 2001 - $63
million).
The Company's future income tax provision for 2003 decreased to $339 million
($2.02 per boe), down from $400 million ($2.61 per boe) in 2002 (2001 - $283
million or $2.02 per boe) due to changes noted above. In 2002, the future income
tax liability in the North Sea was increased by $34 million as a result of the
introduction in the UK of a 10% supplementary charge on profits from North Sea
crude oil and natural gas production. The increase in the North Sea future
income tax liability was partially offset by a $21 million decrease in the North
America future income tax liability as a result of a reduction in the Alberta
provincial corporate income tax rate in the second quarter of 2002. 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.
The Company's effective tax rate decreased to 23.6% for 2003 from 41.6% for 2002
(2001 - 35.4%) as a result of the reductions in the Federal and Alberta
corporate income tax rates in 2003.
It is anticipated that, based on the current availability of approximately $4
billion of tax pools in Canada at the end of 2003 and current commodity strip
prices, the Company will be cash taxable in Canada in 2004 in the amount of $100
million to $175 million.
LIQUIDITY AND CAPITAL RESOURCES
($ millions, except ratios) 2003 2002 2001
- --------------------------------------------------------------------------------------------------------
Working capital deficit (1) $ 505 $ 14 $ 6
Long-term debt 2,645 4,074 2,669
- --------------------------------------------------------------------------------------------------------
Net debt $3,150 $4,088 $2,675
- --------------------------------------------------------------------------------------------------------
Shareholders' equity
Preferred securities $ 103 $ 126 $ 127
Share capital 2,353 2,304 1,698
Retained earnings 3,644 2,414 1,908
Foreign currency translation adjustment 17 24 73
- --------------------------------------------------------------------------------------------------------
Total $6,117 $4,868 $3,806
- --------------------------------------------------------------------------------------------------------
Debt to cash flow (1) 0.9X 1.8x 1.4x
Debt to EBITDA (1)(2)(3) 0.8X 1.6x 1.3x
Debt to book capitalization (1) 31.6% 45.6% 41.2%
Debt to market capitalization (1) 24.2% 38.9% 34.9%
After tax return on average common shareholders' equity (2) 25.7% 13.8% 18.8%
After tax return on average capital employed (2) 16.7% 8.9% 12.0%
========================================================================================================
(1) Includes current portion of long-term debt.
(2) Based on trailing 12-month activity.
(3) Earnings before interest, taxes, depletion, depreciation and amortization.
The Company recognizes the need for a strong financial position in order to
withstand volatile crude oil and natural gas commodity prices and the
operational risks inherent in the crude oil and natural gas business
environment.
49 ANNUAL REPORT 2003
- --------------------------------------------------------------------------------
MANAGEMENT'S DISCUSSION AND ANALYSIS
- --------------------------------------------------------------------------------
LONG-TERM DEBT
Long-term debt including current portion at December 31, 2003, decreased $1,269
million from the prior year. The decrease resulted in a debt to EBITDA ratio of
0.8x and a debt to book capitalization of 31.6% compared to a debt to EBITDA
ratio of 1.6x and a debt to book capitalization of 45.6% in 2002. These ratios
are currently below the Company's guidelines for balance sheet management of
debt to EBITDA of 1.5x to 2.0x and debt to book capitalization of 40% to 45%.
At December 31, 2003, the Company had:
o Approximately $1.6 billion of available unused bank credit facilities;
o A fixed / floating interest rate mix of 38% / 62%;
o An average cost of borrowing of approximately 4.7%;
o 91% of borrowings denominated in US dollars; and
o 91% of total long-term debt as non-bank-based borrowing with an average
maturity of 14.6 years.
In 2003, $740 million of long-term debt was repaid. Long-term debt was also
reduced by an additional $529 million as a result of foreign exchange gains on
US dollar denominated debt. Higher than budgeted prices received for the
Company's products during 2003 resulted in increased cash flow over the budget
established in late 2002. Early in 2003, the Company decided to allocate a
minimum of 50% of its cash flow surplus toward debt repayment. The remaining
excess was directed to the Company's authorized share buy-back program and
additional expenditures on conventional crude oil and natural gas opportunities.
The largest portion of the additional capital expenditures took place in the
fourth quarter of 2003 and accordingly did not add materially to the Company's
2003 average production volumes.
In May 2003, the Company filed a short form prospectus that allows for the issue
of up to US$2 billion of debt securities in the United States until June 2005.
If issued, these securities will bear interest as determined at the date of
issuance. 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.
In May 2003, the Company prepaid the US$50 million, 6.50% senior unsecured notes
due May 1, 2008. The final principal repayment on the 6.95% senior unsecured
notes was made September 30, 2003.
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 maintain
a strong 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, 2003, the Company had unsecured bank credit facilities of $1,925
million compared to $2,275 million at the close of 2002 (2001 - $1,840 million).
During 2003, the Company repaid and cancelled a $500 million acquisition term
credit facility.
With respect to the Horizon Project, financing of the first phase of development
will be guided by the competing principles of retaining as much direct ownership
interest as possible while maintaining current strong debt ratings and not
issuing additional equity in common shares. The Company is also investigating
the use of long-term commodity hedges in order to reduce cash flow risks during
the construction phase. The Company could also look to offload capital
commitments through the acceptance of complementary business partners, or
potentially, project joint venture partners. Recent commodity price increases
have significantly strengthened the balance sheet of the Company, thereby
placing it in a better position to achieve all three of its guiding principles.
SHARE CAPITAL
The Company is authorized to issue an unlimited number of common shares. As at
December 31, 2003 and 2002, there were 134 million common shares outstanding. In
addition, the Company is also authorized to issue 200,000 Class 1 preferred
shares. There were no preferred shares outstanding during these periods.
During 2003, the Company issued 2,690 thousand common shares from the exercise
of stock options for proceeds of $89 million. In addition, 2,735 thousand common
shares were purchased for cancellation under the Normal Course Issuer Bid for a
total cost of $144 million, resulting in 45 thousand fewer outstanding common
shares than at the beginning of the year.
In 2002, the Company issued 10 million common shares at an attributed value of
$522 million as part of the consideration to acquire Rio Alto. A further 2,523
thousand common shares were issued from the exercise of stock options throughout
2002 for proceeds of $82 million. 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 million net of tax. The value of the flow-through 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.
50 CANADIAN NATURAL
- --------------------------------------------------------------------------------
MANAGEMENT'S DISCUSSION AND ANALYSIS
- --------------------------------------------------------------------------------
In January 2004, the Company renewed its Normal Course Issuer Bid allowing it to
purchase up to 6,690,385 common shares or 5% of the Company's outstanding common
shares on the date of announcement, during the 12-month period beginning January
24, 2004, and ending January 23, 2005. As at February 19, 2004, the Company has
not purchased any additional shares under the renewed Normal Course Issuer Bid.
The Company's Board of Directors has approved an increase in the annual dividend
paid by the Company to $0.80 per common share in 2004, up from the previous
level of $0.60 per common share. The 33% increase recognizes the stability of
the Company's increased cash flow and provides a further return to shareholders.
This is the fourth consecutive year in which the Company has paid dividends and
the third consecutive year of an increase in the distribution paid to its
shareholders. The increased dividend will become effective with the quarterly
payment of $0.20 per common share to be paid on April 1, 2004.
The Company declared dividends on common shares in the amount of $81 million or
$0.60 per common share during the year ended December 31, 2003, up from $64
million or $0.50 per common share in 2002 (2001 - $49 million, $0.40 per common
share).
In order to increase the liquidity of its common shares, the Board of Directors
will recommend to its shareholders to subdivide the Company's common shares on a
two for one basis, which will result in an increase in the Company's total
outstanding common shares to approximately 268 million common shares. This
recommendation will be voted on by the shareholders at the Annual and Special
Meeting of Shareholders to be held on May 6, 2004. As at February 19, 2004, the
Company has 134,063,267 common shares outstanding.
OFF BALANCE SHEET ARRANGEMENTS AND FINANCIAL INSTRUMENTS
The Company has operating leases in place on a variety of equipment. These
operating leases require periodic lease payments, which are recorded as
production expenses. The Company also utilizes various 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.
The Company enters into commodity price contracts to hedge anticipated sales of
crude oil and natural gas production in order to protect cash flow for capital
expenditure programs. Gains or losses on these contracts are included in crude
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 future US dollar denominated crude oil and natural gas
sales are recognized in revenue at the time of sale of the related product. The
Company inherited a foreign currency swap agreement from Rio Alto 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. 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 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 unrealized gain or loss is recognized in net earnings. The fair
value of these financial instruments is disclosed in note 10 to the consolidated
financial statements.
COMMITMENTS
The Company has various commitments primarily related to debt, operating leases
and demand charges on firm transportation agreements. The following table
summarizes the Company's commitments as at December 31, 2003.
($ millions) 2004 2005 2006 2007 2008 Thereafter
- -----------------------------------------------------------------------------------------------------------------------------
Natural gas transportation $ 180 $ 169 $ 143 $ 103 $ 77 $ 194
Crude oil transportation and pipeline $ 15 $ 13 $ 13 $ 15 $ 13 $ 167
Offshore equipment operating lease $ 169 $ 129 $ 75 $ 75 $ 75 $ 367
Electricity $ 28 $ 27 $ 27 $ -- $ -- $ --
Office lease $ 20 $ 20 $ 19 $ 17 $ 16 $ 50
Processing $ 6 $ 5 $ 2 $ -- $ -- $ --
Preferred securities $ -- $ -- $ -- $ -- $ -- $ 103
Long-term debt $ 184 $ 194 $ -- $ 165 $ 40 $1,978
- -----------------------------------------------------------------------------------------------------------------------------
51 ANNUAL REPORT 2003
- --------------------------------------------------------------------------------
MANAGEMENT'S DISCUSSION AND ANALYSIS
- --------------------------------------------------------------------------------
CAPITAL EXPENDITURES
($ millions) 2003 2002 2001
- ----------------------------------------------------------------------------------------------------------------
BUSINESS COMBINATIONS $ -- $2,393 $ --
- ----------------------------------------------------------------------------------------------------------------
EXPENDITURES ON PROPERTY, PLANT AND EQUIPMENT
Net property acquisitions $ 336 $ 440 $ 519
Land acquisition and retention 154 114 101
Seismic evaluations 77 63 95
Well drilling, completion and equipping 1,194 626 635
Pipeline and production facilities 522 292 395
- ----------------------------------------------------------------------------------------------------------------
TOTAL NET RESERVE REPLACEMENT EXPENDITURES 2,283 1,535 1,745
Horizon Oil Sands Project 152 68 27
Midstream 11 20 97
Abandonments 40 43 10
Head office 20 10 6
- ----------------------------------------------------------------------------------------------------------------
TOTAL NET CAPITAL EXPENDITURES $2,506 $1,676 $1,885
- ----------------------------------------------------------------------------------------------------------------
BY SEGMENT (excluding business combinations)
North America $1,815 $1,065 $1,459
North Sea 342 333 98
Offshore West Africa 186 190 204
Horizon Project 152 68 27
Midstream 11 20 97
- ----------------------------------------------------------------------------------------------------------------
Total $2,506 $1,676 $1,885
- ----------------------------------------------------------------------------------------------------------------
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 were $2,506 million in 2003 compared to $1,676 million in
2002, excluding the acquisition of Rio Alto (2001 - $1,885 million). North
America accounted for 79% of total capital expenditures, up from 69% in 2002
(2001 - 84%). In 2003, the Company's drilling activity increased 199% with the
drilling of 1,353 net wells (excluding stratigraphic test/service wells), up
from 453 net wells drilled in 2002 (2001 - 739 net wells). The Company drilled
777 net natural gas wells, up 380% from the 162 net wells in 2002 (2001 - 476
net wells) and 458 net crude oil wells, up 73% from the 264 net wells in 2002
(2001 - 231 net wells). In addition, during 2003 the Company drilled 440 net
stratigraphic test/service wells on the oil sands leases in the Horizon Project
and in North Alberta.
North America 2003 drilling was focused in the Company's heavy crude oil areas
of North Alberta (315 net wells), its shallow natural gas area in South Alberta
(417 net wells) and its natural gas area in Northwest Alberta (98 net wells).
North America capital expenditures also included the expansion of the Company's
Primrose properties, where 41 wells were drilled in 2003. Steaming commenced in
early 2004 and production from these wells is expected in mid-2004.
North America capital expenditures include the acquisition of the West Stoddart
natural gas plant. The West Stoddart natural gas plant is located 50 kilometres
northwest of Fort St. John, British Columbia and has a processing capacity of
120 mmcf/d.
Capital expenditures also included work on the Horizon Project, where the DBM
was completed. The Company also completed construction work on the access road
and three bridges. Work on the EDS, the third and final stage of engineering
work, has commenced and is expected to be completed by mid-2004. The Alberta
Energy and Utilities Board and Alberta Environment, in co-operation with other
provincial and federal regulatory agencies, have deemed the application for the
Horizon Project as being complete.
In 2003, North Sea capital expenditures included the drilling of 18 wells
focusing on targeting reserves stranded against faults within the Ninian and
Murchison Fields. The Company further consolidated its ownership interests to
87.6% in the Banff Field, located in the Central North Sea, by acquiring an
additional 31.7% working interest and assuming operatorship. In addition, the
Company was the successful bidder on six new exploration licenses at the UK
Government's 21st Seaward Licensing Round. These blocks provide for additional
exploration lands adjacent to the Ninian hub in the northern North Sea. In 2003,
a satellite pool was drilled off the Murchison platform but encountered no
hydrocarbons and an unsuccessful exploration well was drilled offshore France.
52 ANNUAL REPORT 2003
- --------------------------------------------------------------------------------
MANAGEMENT'S DISCUSSION AND ANALYSIS
- --------------------------------------------------------------------------------
Offshore West Africa capital expenditures included the continued development of
the Espoir Field located offshore Cote d'Ivoire with the perforation of the
upper zone of the East Espoir structure during the second quarter of 2003. Also
in the second quarter of 2003, a successful well was drilled in the Acajou
satellite pool. Development of the Baobab Field continues with four major
contracts being awarded in 2003 for the drilling; supply of subsea Xmas trees,
manifolds, flowlines, controls and associated equipment; supply of pipelines,
risers and installation of all of the subsea equipment; and the supply and
operation of a floating production, storage and offtake vessel. The drilling of
the water injection and production wells commenced in the fourth quarter of 2003
and production from the Baobab Field is expected to commence in mid-2005.
Construction of the floating production, storage and offtake vessel is currently
underway. In 2003, the first of several potential exploration targets located on
Block 16, offshore Angola was drilled. The well, Zenza-1, in which the Company
has a 50% working interest, was drilled for a total cost of US$17 million, and
although the well encountered reservoir quality sands and shows of hydrocarbons,
it was not in sufficient amounts to be commercial. Accordingly, the well has
been plugged and abandoned. The results of the well will be integrated into the
geological model for Block 16 and a second exploratory well will be drilled in
2005.
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 that 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 decommissioning 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;
o A solution gas reduction and conservation program; and
o A program to replace all fresh water for steaming with brackish water.
The Company has also established stringent operating standards in four areas:
o Using water-based, environmentally friendly drilling muds whenever
possible;
o Implementing cost effective ways of reducing 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 2003, the Company's capital expenditures included $40 million of abandonment
expenditures, down from $43 million in 2002 (2001 - $10 million).
ESTIMATED FUTURE SITE RESTORATION LIABILITY ($ millions) 2003 2002
- --------------------------------------------------------------------------------
North America $ 1,491 $ 1,206
North Sea 764 745
Offshore West Africa 26 35
- --------------------------------------------------------------------------------
2,281 1,986
North Sea PRT recovery (331) (305)
- --------------------------------------------------------------------------------
$ 1,950 $ 1,681
- --------------------------------------------------------------------------------
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 present
legislation and industry practice. It is important to note that the future
abandonment costs to be incurred by the Company in the North Sea will result in
an estimated recovery of PRT of $331 million (2002 - $305 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 $1,950 million (2002 - $1,681 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.
53 ANNUAL REPORT
- --------------------------------------------------------------------------------
MANAGEMENT'S DISCUSSION AND ANALYSIS
- --------------------------------------------------------------------------------
KYOTO PROTOCOL
In December 2002, the Canadian Federal Government ratified the Kyoto Protocol
("Kyoto"). The Company continues to work with departments of the Federal and
Provincial governments as legislation and regulatory mechanisms to address the
issue of climate change develop. There continues to be uncertainty about the
ratification of Kyoto, as certain countries have not yet committed to this
treaty. The Company plans to proceed on the assumption that new Canadian
legislative and regulatory climate change frameworks will be implemented
regardless of the fate of Kyoto. The Federal Government has addressed the
uncertainty around the ratification and implementation of Kyoto by providing the
oil and gas sector with limits on the cost for large industrial emitters until
2012. For long-term, capital intensive investments, such as the Horizon Project,
it is essential for the Company to understand the cost implications associated
with the climate change policies beyond 2012. To address these concerns, the
Federal Government outlined eight principles that would guide them in its
negotiations and policies for the post 2012 years. On the basis of these
principles, the Company will continue to work on the development plan of the
Horizon Project. Accordingly, the Company will continue to develop strategies
that will enable it to deal with the risks and opportunities associated with new
climate change policies. In addition, the Company will work with relevant
parties to ensure that new policies encourage innovation, energy efficiency,
targeted research and development while not impacting Canada's competitive
position.
OIL AND NATURAL GAS RESERVES
The Company retains qualified independent petroleum engineering consultants,
Sproule Associates Limited ("Sproule"), to evaluate 100% of the Company's proved
and probable crude oil and natural gas reserves and prepare Evaluation Reports
on the Company's total reserves. The Company has been granted an exemption from
the recently adopted National Instrument 51-101 -- Standards of Disclosure for
Oil and Gas Activities ("NI 51-101") which prescribes standards for the
preparation and disclosure of reserves and related information for companies
listed in Canada. This exemption allows the Company to substitute United States
Securities and Exchange Commission ("SEC") requirements for certain disclosures
required under NI 51-101. The primary difference between the two standards is
the additional requirement under NI 51-101 to disclose proved and probable
reserves and future net revenues using forecast prices and costs. The Company
has elected to disclose proved reserves using constant prices and costs as
mandated by the SEC and has also provided proved and probable reserves under the
same parameters as voluntary additional information. Another difference between
the two standards is in the definition of proved reserves. As discussed in the
Canadian Oil and Gas Evaluation Handbook ("COGEH"), the standards which NI
51-101 employs, the difference in estimated proved reserves based on constant
pricing and costs between the NI 51-101 and SEC standards is not material.
The Company's Reserves Committee has met with Sproule and carried out
independent due diligence procedures with Sproule as to the Company's reserves.
Additional reserve disclosure is contained in the supplementary oil and gas
information and the Company's Annual Information Form.
SUBSEQUENT EVENT
In February 2004, the Company announced the acquisition of certain resource
properties in its North Alberta core region, collectively known as the Petrovera
Partnership ("Petrovera"), for $467 million. Current production from the
acquired properties is approximately 27,500 bbl/d of heavy oil and 9 mmcf/d of
natural gas. Strategically, the acquisition fits with the Company's objective of
dominating its core areas and related infrastructure. The Company expects to
achieve operating cost reductions through synergies with its existing facilities
including additional throughput in its 100% owned ECHO Pipeline.
RISKS AND UNCERTAINTIES
The Company is exposed to several operational risks inherent in exploring,
developing, producing and marketing crude 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 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 crude oil of
various grades. The Company believes this diversification reduces price risk
when compared with over-leverage to one commodity. Sales of crude 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 10 to the 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.
54 CANADIAN NATURAL
- --------------------------------------------------------------------------------
MANAGEMENT'S DISCUSSION AND ANALYSIS
- --------------------------------------------------------------------------------
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.
CRITICAL ACCOUNTING ESTIMATES
Management is often required to make judgements, assumptions and estimates in
the application of generally accepted accounting principles that have a
significant impact on the financial results of the Company. 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 ("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. The capitalized costs and future capital costs
related to each cost centre from which there is production are depleted on the
unit-of-production method based on the estimated proved reserves of that
country. Capitalized costs in each cost centre may not exceed the sum of
undiscounted 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 to
evaluate the Company's proved and probable oil and natural gas reserves. In
2003, Sproule evaluated 100% of the Company's reserves.
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 depletion, depreciation 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. Future site restoration costs for processing and
production facilities are provided for using the straight-line method over their
estimated lives. The annual provision is included in depletion, depreciation and
amortization. The estimated site restoration costs are based on engineering
estimates using current costs and technology in accordance with existing
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 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. In June 2003, the Company approved a
modification to its Option Plan. In lieu of receiving common shares, the stock
option holder has the right to elect to receive a cash payment equal to the
difference between the exercise price of the stock option and the market price
of the Company's common shares on the date of surrender, multiplied by the
number of common shares covered by the stock options surrendered.
55 ANNUAL REPORT 2003
- --------------------------------------------------------------------------------
MANAGEMENT'S DISCUSSION AND ANALYSIS
- --------------------------------------------------------------------------------
The modification to the Option Plan was accounted for prospectively and for the
year ended December 31, 2003, the Company recorded compensation expense of $200
million. As at December 31, 2003, the total liability for expected cash
settlements under the Option Plan is $171 million, of which $130 million is
included as a current liability. During the year ended December 31, 2003, cash
payments of $31 million were made for 1,337,398 stock options surrendered.
NEW ACCOUNTING STANDARDS
FULL COST ACCOUNTING
In September 2003, the CICA issued Accounting Guideline 16 "Oil and Gas
Accounting - Full Cost". The Guideline modifies the ceiling test, which limits
the aggregate capitalized costs that may be carried forward to future periods.
Specific new guidance was provided on several issues, including the frequency of
conducting cost centre impairment tests, the testing for cost centre
recoverability and the method of determining fair value. The Guideline
recommends that cost centre impairment tests should be conducted at each annual
balance sheet date. Recovery of costs is tested by comparing the carrying amount
of the oil and natural gas assets to the undiscounted cash flows from those
assets using proved reserves and expected future prices and costs. If the
carrying amount exceeds the recoverable amount, then impairment should be
recognized on the amount by which the carrying amount of the assets exceeds the
present value of expected cash flows using proved and probable reserves and
expected future prices and costs. The effective date of the Guideline is for
fiscal years beginning on or after January 1, 2004, with early adoption
recommended. This guideline will apply to the ceiling test relating to the
impairment of the Company's property, plant and equipment. Adoption of this
standard would not have had an impact on the Company's consolidated financial
statements for the year ended December 31, 2003.
ASSET RETIREMENT OBLIGATIONS
In January 2003, the CICA issued Section 3110 "Asset Retirement Obligations".
The Section requires the recognition of the fair value of the retirement
obligation for related long-term assets as a liability. Retirement costs equal
to the retirement obligation are capitalized as part of the cost of the
associated capital asset and amortized to expense through depletion over the
life of the asset. In subsequent periods, the liability is adjusted for the
passage of time and any changes in the amount or timing of the underlying future
cash flows. This standard will be adopted retroactively effective January 1,
2004, and prior period comparative balances will be restated. Adoption of the
standard will have the following effects on the Company's financial statements:
($ millions) January 1, 2004
- --------------------------------------------------------------------------------
Consolidated balance sheet
Increase property, plant and equipment $ 445
Increase asset retirement obligation $ 450
Increase future income tax liability $ 3
Decrease foreign currency translation adjustment $ (14)
Increase retained earnings $ 6
- --------------------------------------------------------------------------------
The Company's pipelines and co-generation plant have indeterminant lives and
therefore the fair values of the related asset retirement obligations cannot be
reasonably determined. The asset retirement obligation for these assets will be
recorded in the year in which the lives of the assets are determinable.
HEDGING RELATIONSHIPS
In December 2001, the CICA issued Accounting Guideline 13, "Hedging
Relationships". The effective date of this Guideline was deferred to fiscal
years beginning on or after July 1, 2003. The Guideline addresses the types of
items that qualify for hedge accounting, the formal documentation required to
enable the use of hedge accounting and the requirement to evaluate hedges for
effectiveness. The Guideline does not specify how hedge accounting should be
applied but does require financial instruments that are not designated as hedges
be recorded at fair value on the Company's consolidated balance sheet, with
changes in fair value recorded in earnings. This Guideline will be adapted
prospectively effective January 1, 2004 and will have the following effects on
the Company's financial statements:
($ millions) January 1, 2004
- --------------------------------------------------------------------------------
Consolidated balance sheet
Increase derivative financial instruments asset $ 16
Increase future income tax liability $ 7
Increase deferred revenue $ 9
- --------------------------------------------------------------------------------
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.
The Company expects production levels in 2004 to average 1,320 to 1,395 mmcf/d
of natural gas and 245,000 to 265,000 bbl/d of crude oil and NGLs, taking into
account the Petrovera acquisition. First quarter 2004 production guidance for
natural gas is 1,285 to 1,315 mmcf/d of natural gas and 263,000 to 283,000 bbl/d
of crude oil and NGLs.
56 CANADIAN NATURAL
- --------------------------------------------------------------------------------
MANAGEMENT'S DISCUSSION AND ANALYSIS
- --------------------------------------------------------------------------------
The budgeted capital expenditures in 2004 are currently expected to be as
follows:
($ millions) 2004 Budget
- --------------------------------------------------------------------------------
North America natural gas $ 900
North America crude oil and NGLs 550
North Sea crude oil and NGLs 300
Offshore West Africa crude oil and NGLs 290
Property acquisitions and midstream 510
- --------------------------------------------------------------------------------
2,550
Horizon Project (1) 200 - 400
- --------------------------------------------------------------------------------
Total $ 2,750 - 2,950
- --------------------------------------------------------------------------------
(1) Expenditure level is dependent upon timing of regulatory and Board of
Director approvals.
In 2004, the Company expects to drill approximately 706 net natural gas wells,
274 net crude oil wells and 321 stratigraphic test/service wells. The 2004 North
America natural gas program will be highlighted by expanded drilling programs in
the Northwest Alberta and Northeast British Columbia core regions as follows:
(number of wells) 2004 Budget
- --------------------------------------------------------------------------------
Northeast British Columbia 172
Northwest Alberta 145
North Alberta 183
South Alberta 206
- --------------------------------------------------------------------------------
Total 706
- --------------------------------------------------------------------------------
The Company continues the disciplined development of its heavy crude oil
resources. These reserves will be developed as heavy crude oil markets permit.
The 2004 drilling program consists of 110 conventional heavy crude oil wells, 51
thermal heavy crude oil wells, 43 light crude oil wells and 43 Pelican Lake
crude oil wells. At Pelican Lake, the Enhanced Oil Recovery waterflood test
program was a success and as such, the Company will begin the phased roll out of
the waterflood with approximately 20% of the field being under waterflood by the
end of 2004. The waterflood will stabilize production, but will require a
further 63 Pelican Lake productive wells to be converted from producers to water
injectors.
Based upon the capital expenditure budget, the Company expects to incur Canadian
current income tax expense in 2004 of $100 to $175 million.
The 100% owned and operated Horizon Project is expected to be built in three
phases and produce approximately 232,000 bbl/d of light, sweet synthetic crude
oil. In 2004, the third phase of engineering, EDS, is expected to be completed.
In addition, the financing plan will be optimized and finalized by the third
quarter of 2004. The 2004 capital budget for the Horizon Project will be phased
in over the year and is dependent upon regulatory approval and cost estimates.
Regulatory review for the environmental assessment of the Horizon Project was
conducted in September 2003 and the Company received approval from the review
panel in January 2004. Final regulatory approvals are expected in the first half
of 2004. With final regulatory approval, the completion of the EDS and
confirmation of cost estimates, Board of Director approval will be sought in
late 2004. Depending upon the timing of final approval, a total of $200 to $400
million is budgeted for the Horizon Project in 2004. The Company anticipates
that 80% of the detailed engineering will be completed before it commits to the
construction of the Horizon Project.
The capital budget in 2004 for the North Sea is $300 million and includes the
drilling of approximately 13 crude oil wells, implementing a secondary recovery
natural gas injection scheme at Banff, optimizing Ninian and Murchison
waterfloods, and building on the successful 2003 recompletion program. Average
crude oil production is expected to remain relatively consistent with current
production levels; however, natural gas volumes will be lower as natural gas
sales at Banff are diverted to reinjection.
In 2004, the capital budget for Offshore West Africa is set at $290 million, of
which the Company anticipates $220 million to be spent on the continuing
development of the Baobab Field in Cote d'Ivoire. The remainder will be spent on
the pre-development work associated with the West Espoir development and various
exploration activities.
The original budget was based on an average natural gas price of $5.50 per GJ at
AECO, an oil price of US$26.00 per bbl for WTI and a heavy oil differential of
US$8.50 per bbl. The current price-deck for our products, if maintained, could
result in a significant increase in cash flow over the budget. The Company will
monitor its expected cash flow excess and intends to allocate a minimum of 50%
of such excess towards debt repayment. The remaining excess will be directed to
the Company's authorized share buy-back program and additional expenditures on
conventional crude oil and natural gas opportunities. Such expenditures will
only be incurred as excess cash flows are realized and will be subject to the
same economic tests as regular budgeted expenditures. It is expected that the
largest portion of the additional capital expenditures will take place late in
the third and fourth quarters of 2004 and accordingly will not add materially to
the Company's 2004 average production volumes. Should additional economic
opportunities for share buy-backs or capital activities not present themselves
to the extent allocated, such allocations of excess cash flow would revert to
debt repayment.
57 ANNUAL REPORT 2003
- --------------------------------------------------------------------------------
MANAGEMENT'S DISCUSSION AND ANALYSIS
- --------------------------------------------------------------------------------
SENSITIVITY ANALYSIS (1) CASH FLOW FROM CASH FLOW FROM
OPERATIONS (2) OPERATIONS (2) NET EARNINGS (2) NET EARNINGS (2)
($ millions) ($/share, basic) ($ millions) ($/share, basic)
- ----------------------------------------------------------------------------------------------------------------------------------
PRICE CHANGES
Crude oil - WTI US$1.00/bbl (3)
Excluding financial derivatives $ 88 $ 0.66 $ 63 $ 0.47
Including financial derivatives $ 65 - 88 $ 0.48 - 0.66 $ 46 - 63 $ 0.34 - 0.47
Natural gas - AECO C$0.10/mcf (3)
Excluding financial derivatives $ 35 $ 0.26 $ 21 $ 0.16
Including financial derivatives $ 32 - 34 $ 0.24 - 0.25 $ 19 - 21 $ 0.14 - 0.16
VOLUME CHANGES
Crude oil - 10,000 bbl/d $ 50 $ 0.37 $ 17 $ 0.12
Natural gas - 10 mmcf/d $ 13 $ 0.10 $ 5 $ 0.04
FOREIGN CURRENCY RATE CHANGE
$0.01 change in C$ in relation to US$ (3)
Excluding financial derivatives $ 48 $ 0.36 $ 15 $ 0.11
Including financial derivatives $ 41 - 44 $ 0.31 - 0.33 $ 10 - 13 $ 0.08 - 0.09
INTEREST RATE CHANGE - 1% $ 10 $ 0.08 $ 10 $ 0.08
- ----------------------------------------------------------------------------------------------------------------------------------
(1) The sensitivities are calculated based on 2003 fourth quarter results.
(2) Attributable to common shareholders.
(3) For details of financial instruments in place, see consolidated financial
statements note 10.
DAILY PRODUCTION BY SEGMENT, BEFORE ROYALTIES
Q1 Q2 Q3 Q4 2003 2002 2001
- ----------------------------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS (bbl/d)
North America 173,045 175,232 174,838 176,429 174,895 169,675 166,675
North Sea 56,963 55,781 60,193 54,529 56,869 38,876 36,252
Offshore West Africa 7,552 9,594 11,985 13,304 10,628 6,784 3,396
- ----------------------------------------------------------------------------------------------------------------------------------
Total 237,560 240,607 247,016 244,262 242,392 215,335 206,323
- ----------------------------------------------------------------------------------------------------------------------------------
NATURAL GAS (mmcf/d)
North America 1,265 1,278 1,229 1,206 1,245 1,204 906
North Sea 41 40 49 52 46 27 12
Offshore West Africa 4 7 11 12 8 1 --
- ----------------------------------------------------------------------------------------------------------------------------------
Total 1,310 1,325 1,289 1,270 1,299 1,232 918
- ----------------------------------------------------------------------------------------------------------------------------------
BARRELS OF OIL EQUIVALENT (boe/d)
North America 383,952 388,210 379,751 377,448 382,315 370,337 317,658
North Sea 63,764 62,507 68,323 63,246 64,469 43,391 38,293
Offshore West Africa 8,236 10,738 13,808 15,241 12,030 6,994 3,396
- ----------------------------------------------------------------------------------------------------------------------------------
Total 455,952 461,455 461,882 455,935 458,814 420,722 359,347
- ----------------------------------------------------------------------------------------------------------------------------------
PER UNIT RESULTS Q1 Q2 Q3 Q4 2003 2002 2001
- ----------------------------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS ($/bbl)
Sales price $35.26 $30.27 $30.97 $30.02 $31.59 $29.76 $24.31
Royalties 3.56 2.78 2.56 2.22 2.77 3.16 2.17
Production expense 10.79 10.80 10.14 9.45 10.28 8.45 7.64
- ----------------------------------------------------------------------------------------------------------------------------------
Netback $20.91 $16.69 $18.27 $18.35 $18.54 $18.15 $14.50
- ----------------------------------------------------------------------------------------------------------------------------------
NATURAL GAS ($/mcf)
Sales price $ 7.25 $ 6.12 $ 5.50 $ 5.23 $ 6.02 $ 3.76 $5.16
Royalties 1.78 1.35 1.11 1.05 1.32 0.78 1.25
Production expense 0.57 0.59 0.63 0.63 0.60 0.57 0.51
- ----------------------------------------------------------------------------------------------------------------------------------
Netback $ 4.90 $ 4.18 $ 3.76 $ 3.55 $ 4.10 $ 2.41 $3.40
- ----------------------------------------------------------------------------------------------------------------------------------
BARRELS OF OIL EQUIVALENT ($/boe)
Sales price $39.24 $33.32 $31.94 $30.64 $33.75 $26.25 $27.15
Royalties 6.96 5.32 4.46 4.12 5.20 3.91 4.42
Production expense 7.27 7.34 7.17 6.81 7.15 5.99 5.69
- ----------------------------------------------------------------------------------------------------------------------------------
Netback $25.01 $20.66 $20.31 $19.71 $21.40 $16.35 $17.04
- ----------------------------------------------------------------------------------------------------------------------------------
58 CANADIAN NATURAL
- --------------------------------------------------------------------------------
MANAGEMENT'S DISCUSSION AND ANALYSIS
- --------------------------------------------------------------------------------
NETBACK ANALYSIS
($/boe, except daily production) 2003 2002 2001
- ---------------------------------------------------------------------------------------------------------
Daily production, before royalties (boe/d) 458,814 420,722 359,347
Sales price $ 33.75 $ 26.25 $ 27.15
Royalties 5.20 3.91 4.42
Production expense 7.15 5.99 5.69
- ---------------------------------------------------------------------------------------------------------
NETBACK 21.40 16.35 17.04
Midstream contribution (0.28) (0.25) (0.12)
Administration 0.52 0.40 0.29
Interest 0.94 1.03 1.05
Realized foreign exchange loss (gain) 0.05 0.02 (0.01)
Taxes other than income tax (current) 0.69 0.35 0.53
Current income tax (North Sea) 0.14 (0.13) 0.47
Current income tax (Offshore West Africa) 0.06 0.04 --
Current income tax (North America) 0.26 -- --
Current income tax (Large Corporations Tax) 0.09 0.14 0.11
- ---------------------------------------------------------------------------------------------------------
Cash flow $ 18.93 $ 14.75 $ 14.72
- ---------------------------------------------------------------------------------------------------------
QUARTERLY FINANCIAL INFORMATION
($ millions, except per share amounts) Q1 Q2 Q3 Q4 TOTAL
- ------------------------------------------------------------------------------------------------------------------------------------
2003
Revenue $ 1,693.00 $ 1,477.00 $ 1,434.00 $ 1,368.00 $ 5,972.00
Cash flow from operations attributable
to common shareholders $ 906.00 $ 762.00 $ 758.00 $ 734.00 $ 3,160.00
Per common share - basic $ 6.76 $ 5.68 $ 5.62 $ 5.48 $ 23.54
- diluted $ 6.53 $ 5.57 $ 5.56 $ 5.42 $ 23.06
Net earnings attributable to common shareholders $ 428.00 $ 525.00 $ 203.00 $ 251.00 $ 1,407.00
Per common share - basic $ 3.19 $ 3.91 $ 1.51 $ 1.87 $ 10.48
- diluted $ 3.03 $ 3.78 $ 1.49 $ 1.83 $ 10.14
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2002
Revenue $ 782.00 $ 924.00 $ 1,239.00 $ 1,397.00 $ 4,342.00
Cash flow from operations attributable
to common shareholders $ 359.00 $ 475.00 $ 643.00 $ 777.00 $ 2,254.00
Per common 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 $ 99.00 $ 145.00 $ 117.00 $ 209.00 $ 570.00
Per common share - basic $ 0.81 $ 1.18 $ 0.88 $ 1.56 $ 4.46
- diluted $ 0.79 $ 1.09 $ 0.86 $ 1.51 $ 4.31
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TRADING AND SHARE STATISTICS Q1 Q2 Q3 Q4 2003 TOTAL 2002 Total
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TSX - C$
Trading volume (thousands) 45,742 36,859 30,386 34,688 147,675 154,829
Share price ($/share)
High $ 52.90 57.39 57.29 67.22 67.22 54.54
Low $ 45.20 46.55 51.23 53.31 45.20 37.60
Close $ 50.15 53.75 55.59 65.37 65.37 46.80
Market capitalization at
December 31 ($ millions) 8,742.00 6,261.00
Shares outstanding (thousands) 133,731.00 133,776.00
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NYSE - US$
Trading volume (thousands) 2,539 2,546 2,760 3,884 11,729 7,966
Share price ($/share)
High $ 35.97 $ 42.45 $ 41.35 $ 51.39 $ 51.39 $ 34.88
Low $ 29.25 $ 31.51 $ 36.50 $ 40.44 $ 29.25 $ 23.55
Close $ 34.00 $ 39.91 $ 41.16 $ 50.44 $ 50.44 $ 29.67
Market capitalization at
December 31 ($ millions) $ 6,745 $ 3,969
Shares outstanding (thousands) $133,731 $133,776
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59 ANNUAL REPORT 2003